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Southwestern Energy (NYSE:SWN)

Q3 2011 Earnings Call

October 28, 2011 10:00 am ET

Executives

Steven L. Mueller - Chief Executive Officer, President and Director

Greg D. Kerley - Chief Financial Officer, Executive Vice President and Director

Analysts

Robert L. Christensen - Buckingham Research Group, Inc.

Brian Singer - Goldman Sachs Group Inc., Research Division

Rehan Rashid - FBR Capital Markets & Co., Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Scott M. Wilmoth - Simmons & Company International, Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

Michael D. Bodino - Global Hunter Securities, LLC, Research Division

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Operator

Greetings, and welcome to Southwestern Energy Third Quarter Conference 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, Mr. Mueller, you may now begin.

Steven L. Mueller

Thank you. Good morning, and thank you all for joining us. With me today are Bill Way, our Chief Operating Officer; Greg Kerley, our CFO; and Brad Sylvester, our 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 Statement 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 third quarter. Our earnings and cash flow were up primarily driven by our 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'll 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 operating production reaching approximately 1.9 Bcf per day earlier this week. Overall, our operated horizontal wells on 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 we 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 were very encouraged by what we have seen. No new wells are placed on production in third quarter. However, we're excited that the same 17 Marcellus Shale horizontal wells in our Greenzweig area and 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 5.4 -- 5.1 Bcf in the second quarter.

As for activities for the rest of the year, we are currently in the process of completing a 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 in 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 sale until January due to state permitting delays and the constraints of firm transportation and gathering capacity. We are planning to put -- be much more active in the Northeast Pennsylvania in 2012, and we recently signed a contract for 2 additional rigs to be delivered in midyear 2012. These rigs will be new builds and designed specifically for our Marcellus Shale operations.

Switching to New Ventures. In New Brunswick, we completed the second phase of surface geochemical sampling and the acquisition phase of approximately 250 miles of 2D data. Interpretation of both sets of data is currently underway. The next step in 2012 is to shoot more 2D seismic to help better -- 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 approximately 487,000 net acres located in the Lower Smackover Brown Dense formation, an unconventional oil reservoir find in Southern Arkansas and Northern Louisiana. We spud our first well in September, the Roberson #1-15H located in Columbia County, Arkansas, and is currently drilling the 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 plan there is 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 play could increase significantly over the next several years.

In addition to the projects mentioned, we have 461,000 net acres on other ideas that we'll provide updates on in the future. This acreage total is 86,000 acres, up from the second quarter, or 23%.

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

Greg D. Kerley

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, which 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 to 500 Bcf equivalent, representing an increase of approximately 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 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 cost, which includes lease operating expenses, G&A, taxes of an income tax and net interest expense, were $1.26% per Mcf in the third quarter, down from $1.31 a year ago.

Our full cost pool amortization rate also declined to $1.28 per Mcf in the third quarter, down from $1.31 of 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 favorable 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 increases are 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 7 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% payout 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, and 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 it back to the operator who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

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 kind of talk to where you think these wells would be producing on an unconstrained basis were it not for any of the pipeline issues. And 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?

Steven L. Mueller

There's really a couple of things to think about as far as the wells. If you remember last quarter, we talked that 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're flowing basically against something in the mid 400-pound range. Now that compares to, say, Fayetteville Shale we're 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, and any of the wells, brought them on quickly. We kind of slowly ramped them up and we've kind of capped them. I think the best we've ever done, somewhere around 10 million a day. Now what could be their ultimate? You could do some back-of-the-envelope calculations. And on IP, if you brought it on fairly quickly, you went to compression immediately, you might have between 25% and 30% to that quarter to 6 million a day well or 10 million a day well type number. 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're still working on this, but it looks like more stages of fracs are better than fewer stages. And today, we're, I think, averaging about 10 to 11 stages of fracs. We'll see that go up a little but. 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.

Brian Singer - Goldman Sachs Group Inc., Research Division

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?

Steven L. Mueller

And I think you're talking about Fayetteville Shale there?

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes, switching to the Fayetteville midstream.

Steven L. Mueller

I mentioned some of it for Marcellus also. But really no change in what we're thinking before, where you still are open to do something but it's probably not the right time right now. And when I say it's not the right time, we're working on 2012 budget 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 new quarter or something. So we keep watching it. There's value in our midstream. There's value in keeping our midstream where it's at, and there's possibly value down the road to doing something with it also. Now I do want to mention something in the Marcellus, and it's kind of related to how we look at our midstream. Our midstream is a stand-alone group. We signed contracts with our midstream in all the areas where they gather. And we actually had them bid, just like they were another company, whenever we're working with them. In the Marcellus, the one deal we have now is a company called DTE. They'll 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 been gathered by our midstream. We'll have some of the other parts of it gathered by other companies, and so that will be kind of a mix in Pennsylvania.

Brian Singer - Goldman Sachs Group Inc., Research Division

So your decision as to whether you would move ahead with it selling 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 kind of change in the states also?

Steven L. Mueller

The Fayetteville capital is dropping this year versus last year. And I think you'll see a 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 off 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's 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 work there than it is putting it in someplace else. So that's going to be the key on any of it. It doesn't matter if it's disposition or midstream.

Operator

Our next question is from the line of David Heikkinen with Tudor, Pickering.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just thinking about multiyear plans in the Marcellus and kind of where your constraints are today on the pipeline systems and kind of 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 '12 and just kind of how you're thinking about where those limits and governors come in?

Steven L. Mueller

There's kind of 2 pieces of that. Greg gave some guidance on what we've got firm for 2012. When you look at 2013, as you exit '12, 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, and 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 had to fill in some things between now and 2013. And we think there is some small -- when I say small, maybe 25 million 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 type 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 firm to get beyond little pieces. And so what you have to do is have new pipe into the area. And I don't -- except for knowing that we have that new pipe in the area talking to several different groups that have proposed where that pipe might go and how it might work, that's where we're at in that kind of process. But at 2013, we have just under 500 million a day. The shortest contract we have for firm is 10 years, most of these are 15, there's 120 in there. So we've got at least that in 2013 and forward. From a rig count standpoint, that's really the way we design our rigs also. We've got 2 rigs running right now. We said we're going to add 2 next year. Somewhere in 24, 25 rigs get you in that range that we're 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 at hand.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Steven L. Mueller

I think we're like everyone else. We're trying to figure out how fast it's going to grow and how big that impact truly is for the Northeastern and for the rest of the country. You're starting to see some of these contracts, they actually have back haul, related back hauling, and back towards Chicago or back hauling down to the Gulf Coast. And until we get more built into the system, the system will limit how much you've got, and that will kind of put a moderator, at least for the next few years, on having any issues. But as we start building out beyond 2013 as an industry, we will have to go to 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 pushing about 1 Bcf a day to the mid-continent whether that's to the Gulf Coast area or up to Chicago. And our idea all along was that over the years, at certain points in time, you put gas one way or the other in the system. And so that's our strategy really for any areas, trying 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. You'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's something for the entire industry to look at.

Operator

Our next question is from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Steve, could you give us your view on sort of what you think of gas price at this point in time? And structurally, what could that mean to Fayetteville? If you mean we've certainly been stuck on this $4 range for some time, how do you think about that when you start to develop your plans on the Fayetteville going forward?

Steven L. Mueller

I think, internally, $4.5 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 that the rig count is affected. But anything above $4 rig count seems to be holding in pretty much where it's at today. So we're just assuming for the next 3 years at least that we're range-bound in that $4 to $5 range. And I think that's reflected in our hedges. As Greg kind of said, we've got 60% of our production hedged at $5 this year just to guarantee that our realized price will be above $4. And then as we look out in 2012, 2013, we've got 266 Bcf hedged in 2012. We're like $5.16 floors. We've got 185 Bcf in 2013 with $5.06 floors. That pretty much will guarantee, unless gas gets in the low $3s, that we'll be in the $4 price environment. And as we mentioned in the past that our key project, Fayetteville Shale, as long as we 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're planning to be in this environment, and I think we've got hedges for the next couple of years that would already pretty much tell us that we can stand that environment. We will get the opportunity put on more hedges, we're not done there. And we're hoping for some cold spots during some of the winters coming up so we can do that.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So activity in the Fayetteville Shale will be sort of steady-state here over the next couple of years in this environment?

Steven L. Mueller

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Steven L. Mueller

As far as what we know today, we did take about 360 feet of core. We've got all but about 10 feet of core. So we got a very good sampling of the entire interval with our cores. That's all in labs [ph], being looked at in various ways. But first indication, and again to remind everyone, we were offsetting the well about a mile away that had a test on it and was cored. And we didn't have the core to look at but we had some core data. And everything we're seeing in the core today looks like the core about a mile away, so it's confirming what we thought. Even at the point where you can sometimes get indication whether it's oil or gas, and this looks oily from what we're seeing in the core. So that's where we're at as far as new information. Then as we look forward, what we're thinking about today is a little bit different than what we're 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're talking -- thinking about doing today, and it's not completely finalized, but what we're setting for today is basically splitting the well in half, completing part of it with one set of stages between first and now the first, both the stages and the first will be different, and then producing it for a while coming back and completing the second half. If we do that, then you'll get some information late in the year on part of the well and how it's produced, but you won't get the whole well until after the first year. And we haven't quite finalized that so I can't guarantee it. But I think 2 things to say. Once we get information, you won't see us press release probably, but the second we get a chance to get a new quarterly data or year-end data or have a conference call we'll talk about whatever we've 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 there's nothing confidential necessarily about the well test data or what we're seeing in the wells.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And could you give -- you said you're going to split the well. Why would you do that?

Steven L. Mueller

We did this in the -- early on in some of our wells in Marcellus where you don't know -- 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. And so one of the ways we've got to speak quickly in Marcellus was in our first few wells in, say, the total, we put the perforations at one space in, and then in the heel of the well, we put another space in, and we tested 2 different parts. And so we could basically get information that would normally take you 2 wells to get in 1 well. And we're talking about doing that same thing in this well where the fluid will be the same, the amount of sand we put in general for frac will be the same. But we might change the spacing of the fracs. But we might change the spacing in the perforations just to see if there's a difference in how it produced to help us set up, to help us complete the next well. So just accelerating our knowledge by trying to figure out some of the little tweaks early on.

Operator

Our next question is from the line of Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

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

Steven L. Mueller

It's both. We want to see what a longer lateral would do. And certainly, longer lateral gives you more ways to test it. But the other thing is that there's a difference between Arkansas and Louisiana. Arkansas, in their current rules, you need to keep your wells in 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 1,280-acre unit together, and then you can drill a lot longer lateral. So one of the reasons we're doing Louisiana because we can drill a longer lateral to test some of these things. But the other part is the state rule will let you do it there. I expect that once we figure out what the right lateral length is, if it's 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.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

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

Steven L. Mueller

That's a good question. 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 wherever we're at. But if I had my preference, we'll probably just keep the rigs the same, let the well count creep up a little bit. But that decision is still to be made.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Yes, and the detailed '12 guidance, will that come out in December or January?

Steven L. Mueller

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.

Operator

Our next question is from the line of Scott Wilmoth with Simmons & Company.

Scott M. Wilmoth - Simmons & Company International, Research Division

15% of 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 what are current well costs running in the Marcellus?

Steven L. Mueller

I don't know about this percentage of budget. I can tell you that whether it's Marcellus or Fayetteville, it's a little bit more expensive around the rig in the Marcellus. But it's 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 one running all year. It sets 100 -- below $100 million of additional budget over the 2 rigs that are running now, so you're going to start factoring in some dollars on that side. As far as our well costs go, I don't know yet what the 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 lengths. Those are running by about $5.5 million to drill. The one 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 kind of the range that we're looking at.

Scott M. Wilmoth - Simmons & Company International, Research Division

Okay. And then just kind of following-on on some Fayetteville efficiencies. Obviously, days to drill ticking down. A large number of wells, I think 25 wells, under 5 days. I think the limiting factor there is using the 1 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?

Steven L. Mueller

Well, I did a quick calculation. 19% of our wells last quarter were under 5 days. So that's significantly higher than spent for any other quarter. It's creeping up, it's along those learning curves. And we're trying to figure out where that might end up as we go out into 2012. Certainly, all indications I have is this year we guided that we'd average 9 days. We missed badly. We're going to average in mid-8s or even low 8s this year. Next year, you'll see some kind of average number less than 8 days per well.

Operator

Our next question is from the line of Gil Yang of Bank of America.

Gil Yang - BofA Merrill Lynch, Research Division

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

Steven L. Mueller

No, just how many wells are 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, one late first quarter, one late second quarter and then one in the -- yes, late second quarter and then one in the first quarter up to the Marcellus. And then we had to pick up 2 outside rigs, and so there's about 1.5 weeks, 2 weeks worth of time where we weren't drilling with the same number of rigs, and so we were down at little bit on well count. We're actually, on number of wells in inventory, almost identical quarter-over-quarter. We usually have about 50 wells that are in some kind of completion stage. And I think at the end of this quarter we're almost exactly 50. At the end of the second quarter I think we're 39 or 40. So it went up a couple of wells, but it's in that same range.

Scott M. Wilmoth - Simmons & Company International, Research Division

Okay. So we shouldn't expect any major change in the number of wells? Fayetteville wells per quarter going forward should be on the order [ph] of130-ish?

Steven L. Mueller

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

Scott M. Wilmoth - Simmons & Company International, Research Division

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 sort of filling sewing in the holes in the existing 400,000 acres? Or are you sort of 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?

Steven L. Mueller

Well, the area that we're actually buying in has a lot more acreage of 487,000 acres and it's close to 800,000, it's actually a little over 800,000 acres that we think could be a potential. Now in that, there's some people who already own some acreage, and some of that gets contracted [ph] back out. The reason you're seeing the acreage go up 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 the landowner. We've made a deal with the landowner. We've checked title on it to make sure he actually own it, and he's cashed the check. There's some acreage and really the acreage we have this quarter and the acreage we're going to have the next 3 or 4 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 the check and then they cash it to have it come in and be able to put in the courthouse. So you're going to see it continue to go up, but it's not because necessarily we're pushing the boundaries of the play or anything. It is nothing more than it takes time to get the title work done especially in 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.

Gil Yang - BofA Merrill Lynch, Research Division

Got you, okay. And then my last question is can you just -- you went through a nice sort of 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?

Steven L. Mueller

Let's start at kind of the 900,000 acres. To remind everybody, the 900,000 acres is a little over 600,000 that we've drilled on. There's 100 -- about 60,000 acres that's federal acreage that we now have 6 wells on. They're all verticals in their core, but there's no testing been done on those wells. And over the next several months, we'll drill another 5 wells on that acreage. And that's in a longer time frame to test and do something with. And then we have almost 150,000 acres that is in the older established part of the play that we've got held by production for a long time, and we'll get to it when we get to it. So when we usually talk about how many wells we have left to drill, we're 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 a number that we always talk about, the 8,000 net wells that we have to drill or on a gross basis. Because at that net, remember -- you need 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 drop down to $3.50, that 8,000 net drops down in the 2,000 net range at $3.50, so you do drop considerably off of that. And I can't tell you what happens at $3. There's going to be some piece of that that works at $3. But somewhere in the high $3s it starts dropping off pretty quick.

Gil Yang - BofA Merrill Lynch, Research Division

So if you go to $4.50, do you add a lot more wells or is it still -- it tops out around 8,000?

Steven L. Mueller

Yes, where you start seeing the real increase in wells is with the other acreage. It's not really with the pricing. Because we pretty much got the spacing we need in almost all of our acreage at 600,000 is economic, and that's $4. There's a little bit of fringe stuff, and I won't even guess it's 10%, 15%, that even if you went to $5 that would add to the well count. Mainly the north and some of the shallow areas right around the fringe of our acreage and the outside.

Greg D. Kerley

Gil, remember that the well count that Steve was talking about is to hit our 1.3 PVI target. First, we're staking out that well.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And you're talking about NYMEX price?

Steven L. Mueller

Yes.

Greg D. Kerley

Yes.

Operator

Our next question is from the line of Michael Bodino with Global Hunter Securities.

Michael D. Bodino - Global Hunter Securities, LLC, Research Division

So 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 the well count on the balance of the year in the Marcellus?

Steven L. Mueller

Yes. 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 takeaways 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. We're completely down for about 5 or 6 days, and they've had some problem sensing. But there is probably for us another 10 million to 15 million a day that we can get Stagecoach lines out there work that we've got committed. We just haven't been able to put in a new line. And then, I mentioned we've got some permitting issues. There is a fifth compressor we need to put up on a certain side. We thought we've had that permit by now. It looks like that will be late in the year. If it comes sooner than that, we probably going to 15 million to 20 million a day that we could put on between now and the end 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 bumped up right at the very beginning of the year, that was the compressor coming on in January was our assumption there. That's where it comes from. So the next significant jump is when the DTE line comes in, and we'll kind of work our way up to that. But the DTE line is some time in the second quarter.

Operator

Our next question is from the line of Robert Christensen of Buckingham Research.

Robert L. Christensen - Buckingham Research Group, Inc.

Steve, on this Lower Smackover first well, how was 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're in this lateral leg?

Steven L. Mueller

I'll kind of give you 2 comments there. The actual formation, we drilled it vertically and we did the scoring, actual formation came within 10 feet of exactly where we had our maps. So it was dead-on in that direction. And one of the reasons we wanted to drill through besides taking the core was we want to land in the bottom, basically 40 or 50 feet at the Brown Dense. We're in that. I don't know exactly how many feet we're at right now. We're at a couple of thousand feet at this point, not quite 2,000 feet at this point. And so far we're right in the zone and haven't had any issues.

Robert L. Christensen - Buckingham Research Group, Inc.

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 in their lands and yours. Any thoughts on what that client might be doing?

Steven L. Mueller

I really don't have any thoughts. We're still talking about 3Ds and resuming some seismic together, but we really haven't got any indication in the drilling that they may do. And for everyone, Exxon has a position basically east of where we're drilling, almost in Louisiana-Arkansas border.

Robert L. Christensen - Buckingham Research Group, Inc.

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

Steven L. Mueller

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 the core. You just don't know outside of that one core what the real characteristic of all the rock is. You've done a lot of calculations, but you need to get some cores, you need to get some other wells with a lot of data. And very well could be that there's parts of this play that don't have those characteristics and are too tight or have some issue you can't frac on them. And so the play is smaller than you think it is. That would be one issue. I think the other issue, you get the Brown Dense. The Brown Dense that we're going for is 300- 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're considering it to seal for the Brown Dense. And then above that tight limestone is the conventional Smackover that all of these fields in Southern Arkansas and North Louisiana produce oil from for all these years. That upper Smackover has very high porosity, permeability and has water. So somehow it is from a fault that would go from the porous [ph] Smackover all the way down into the Brown Dense or from -- it would be really strange to have a frac that high. But if somehow you could fracture all the Brown Dense through 200 feet of tight rock and then get into that, you can actually have water come from that up the interval. So those are the 2 risks in the play.

Operator

[Operator Instructions] The next question is from Hsulin Peng of Robert W. Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

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're seeing in Marcellus and also the availability?

Steven L. Mueller

Okay. Your first question had to do with the -- whether that was all-in cost?

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Right. Also with that pad drilling, if you're anticipating any sort of additional savings from that?

Steven L. Mueller

Yes. All of our wells to date have had basically pad drilling. I think the fewest number of wells we put on a pad is 3. And as I said, we're about ready to do a 5-well pad. So there's some, if you want to 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. And the reason I say that, it looks like it's going to be a wider spacing. When we talk about 40- and 60-acre spacing in Fayetteville shale, it looks like it's going to be over 100 acres spacing here. So you won't have as much chance as pad efficiency because you're 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 in the high 3s, $3.6 million, $3.7 million. So there is significant cost differences between Fayetteville and Marcellus. Some of those are terrain, some of those are permitting, some of those are water handling that you're -- they're just different and 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 services have been difficult to find historically. You're starting to see the services, because the rig count stayed flat for the last 6 or 7 months, the services are starting to be more available to you. And I have said this in the past, this time last year, if you could find frac equipment, you took whatever you had, and it didn't matter how good the equipment was, how bad the equipment was, you just took it and went with it. Today you can actually call in 30 days down the road, talk to several vendors and get frac equipment out there. Cost, they're still about 20% higher than Fayetteville Shale but they're flat really from -- they've gone down a little bit from the beginning of the year, but they've been flat the last couple of quarters.

Operator

Our next question is from Rehan Rashid with FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co., Research Division

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's located and what the plant would be? What are we waiting for, Steve?

Steven L. Mueller

Yes, it's just like -- it was before we announced the Brown Dense play. We need to get all the acreage we've kind of targeted for any one if those areas. And once we get the acreage put together in any of those areas and we've controlled what we think we need to control, then we'll start talking about it. And I would expect that next year we'll talk about at least one more area with the pace we're going right now and some of the ones we're doing. And again, that acreage isn't just one area. There is more than one area we're putting acreage together on. So I would expect that next year third quarter conference call we've got some acreage and you're asking the same question. But one, we're going to know about this as well.

Robert L. Christensen - Buckingham Research Group, Inc.

Okay, okay. Back to the Fayette really quick. If I look at the decline curve for greater than 4,000-, greater by 5,000-foot laterals, towards the back end of the decline curve, I see a kind of bounce back up in kind of productivity rates a couple of hundred days down the road. Can you tell us kind of why? Is that a data aberration or associated gas coming out? Any thoughts on that front?

Steven L. Mueller

No. I don't think -- it's a good question. I think it's more data aberration. And one of the things we're do on 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 coding. In the top blue curve, when it starts bumping up especially -- I'd say you were 400 days on. You can see that there's only about 36 wells and it dropped quickly down to one well versus the beginning of that curve is over 250 wells in it. And 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 are asking, though, is we do have a significant amount of what we call absorbed gas. And absorbed gas comes out with a pressure drop. In the flattening you see on all those curves, it doesn't matter which lateral length is showing that absorbed gas. And 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 your beginning first year, 1.5 year production. And we're probably in some of these now. We've got an update on them. And although the curves, that flattening, is you're actually starting to see some absorbed gas coming in the system.

Operator

Our next question is from the line of Michael McAllister with Sterne Agee.

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

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?

Steven L. Mueller

I don't know the answer to that. If just -- 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-, 11-stage average that it will probably 14-, 15-stage. 14- to 15-stage well would be $6.5 million to $7 million dollars. So I'm thinking it's going in that direction but we're still doing a lot of testing to make sure that really is right or not.

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

So you're still going to be like in a mix for the price?

Steven L. Mueller

Yes. For a while, we're going to be in a mix. And 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- to 700-acre size units which would be between 4,000 and maybe as high as 6,000-foot laterals. We do have some that are bigger. But that also does a little bit of limitation on lateral length which also -- and then factors back in a number of stages also.

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

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

Steven L. Mueller

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

Operator

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

Steven L. Mueller

Thank you. I started today saying we're very excited, and we're 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's going to be around for a while, and we believe we're one of few operators that can really do that. We're excited about the Fayetteville Shale. And in the case of Fayetteville Shale, we're doing pad drilling. The days are coming down. We're getting more efficient, there's more efficiency to take out. So we're comfortable that over the next few years, we can drill wells at the same cost we're doing today and continue to do what we're doing on the production and EUR side of that.

And I'm excited about Pennsylvania, and we've shown the graphs in our presentation that 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're starting to get that going in our direction as well.

And then when you look at the New Ventures, we're drilling that first well in the Brown Dense. We're continuing to get more information in New Brunswick. So things are working for us. We're looking forward to a really good fourth quarter and a really exciting 2012.

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

Operator

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

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