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Executives

Harold Korell - Chairman and CEO

Steve Mueller - President, Southwestern Energy

Greg Kerley - CFO

Analysts

Scott Hanold - RBC Capital Markets

Amir Arif - Friedman Billings

Brian singer - Goldman Sachs

David Heikkinen - Tudor Pickering & Holt

Gil Yang - Citi

Jeff Hayden - Rodman & Renshaw

Mike Scialla - Thomas Weisel Partners

Jason Gammel - Macquarie

Tom Gardner - Simmons and Company

Joseph Allman - JPMorgan

Dan McSpirit - BMO Capital Markets

Joe Magner - Tristone Capital

Marshall Carver - Capital One

Southwestern Energy Co. (SWN) Q3 2008 Earnings Call October 31, 2008 10:00 AM ET

Operator

Good day and welcome to the Southwestern Energy Company third quarter earnings teleconference. At this time, I'd like to turn the conference over to the Chairman and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.

Harold Korell

Hi. Good morning. Thank you for joining us. With me today are Steve Mueller, President of Southwestern Energy and Greg Kerley, our Chief Financial Officer.

If you have not received a copy of yesterday's press release regarding our third quarter results, you can call 281-618-4847 to have a copy faxed to you. Also I would like to point out that many of the comments during this conference call 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 SEC.

Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Well to begin with, once again Southwestern Energy has had a great quarter. Our financial results were outstanding and in our Fayetteville shale play, we continue to see significant improvements in well performance as we implement new completion techniques across the play.

As a result, gross operated daily production volumes had risen to approximately 600 million cubic feet per day at September 30th, up from about 260 million cubic feet per day a year ago. Adjusting for our improved performance we have now moved our full year production guidance to a range of 190 Bcfe to 192 Bcfe for 2008 which is an increase of approximately 68% compared to last year.

I am also very pleased to report that our financial position and balance sheet are both in great shape. We had over $425 million of cash and cash equivalents on hand at the end of the quarter. It reduced our debt-to-total capitalization ratio down to 25% and our $1 billion unsecured credit facility was completely undrawn.

While we understand that these are uncertain times in our economy, we believe that Southwestern Energy with our low cost operations and the financial strength and flexibility to pursue highly accretive drilling programs is well-positioned to add significant value for our shareholders.

I would now like to turn the teleconference over to Steve for details on our E&P and Midstream activities and then to Greg Kerley for an update on our financial results and then we will take questions.

Steve Mueller

Thank you, Harold and good morning. During the third quarter of 2008, we produced 52.8 Bcf, up 76% from the third quarter of 2007. Our Fayetteville Shale production was 37.2 Bcf, up significantly from the 14.7 Bcf we produced in the third quarter of 2007.

We produced 8.1 Bcf from East Texas and 6.8 Bcf from our conventional Arkoma properties. We produced another 7/10ths of a Bcf from our Permian and Gulf Coast assets prior to the closing on the sale of nearly all the properties there. As a result of our continued strong production performance, we now estimate that our fourth quarter production will range between 53 Bcf and 55 Bcf and our full-year 2008 production will range from 190 Bcfe to 192 Bcfe.

We are expecting flat to 4% production growth between the third and fourth quarters of 2008, mainly due to the restrictions associated with the delayed completion of the Boardwalk Pipeline in our Fayetteville Shale. I will be discussing this in more detail later.

In the first nines month of 2008, we invested approximately $1.2 billion in our exploration and production activities and participated in drilling 580 wells. Of this amount, approximately $954 million or 83% was for drilling wells. Additionally, we invested $134 million in our Midstream segment, almost entirely on the Fayetteville Shale.

Now let's talk about the Fayetteville Shale development. In the first nine months of 2008, we invested approximately $1 billion in our Fayetteville Shale play, including both our E&P and Midstream activities. At September 30th, our gross operated production rate reached another milestone of approximately 600 million cubic feet per day. We are currently experiencing restrictions related to the Fayetteville Shale production as a result of the delayed completion of the Boardwalk Pipeline.

Due to the construction difficulties including hard rock formations on one major bore, the Phase I completion date that was originally anticipated to be at the beginning of fourth quarter of 2008 is now scheduled for late in the fourth quarter. As a result, we have delayed placing some of our wells on production and delayed completing some wells until this takeaway issue is resolved.

During the third quarter of 2008, our typical well had an average completed well cost of $3 million, an average lateral length of 3736 feet and an average drill time of 12 days from a re-entry to re-entry. This come compares to an average time of 14 days to drill and just over 3500-foot lateral last quarter.

Additionally, we continue to improve our completion practices with our wells completed averaging higher initial 30th and 60th day production rates ranging from 13% to 16% above our result from the second quarter.

During the first three quarters of 2008, we continued to see closer perforation cluster spacing in our horizontal wells with very positive results. We have now tested this technique in 132 of our wells and seen a significant improvement in early production. We estimate that the ultimate recovery on these wells has improved by 20% to 25% ad we are currently planning to utilize this technique on well we plan to drill for the remainder of the year and in to 2009.

Associated with this completion technique and longer laterals, we now expect completed well cost to average approximately $3.1 million per well for the fourth quarter.

As a result of the continued performance of our Fayetteville Shale well, we signed a precedent agreement with the Fayetteville Express Pipeline on September 30th to further expand the further takeaway capacity from an area starting in late 2010 or early 2011. Fayetteville Express Pipeline is a joint venture of Kinder Morgan and Energy Transfer.

Now, let's talk about some of our other areas. In Pennsylvania, we currently have approximately 110,000 net acres from Marcellus Shale's perspective. We have drilled our first three wells, vertical wells in Bradford and Susquehanna Counties, located in the northeast part of the Commonwealth.

Two of these wells were completed and tested in third quarter with encouraging results. One vertical well is waiting on completion. We recently finished drilling our first horizontal well, which we expect to complete in the fourth quarter. In the first nine months of 2008, we invested approximately $104 million in our conventional Arkoma Basin properties.

We participated in drilling 61 wells here including 21 wells that are Ranger Anticline field and 9 wells at our Midway field. Our production from the conventional Arkoma during the first nine months of 2008 was 18.6 Bcf compared to 17.8 Bcf for the first nine of 2008.

In the first nine months of 2008, we invested approximately $122 million in East Texas where we participate in 35 wells, 14 of which were James Lime horizontal wells. Production from East Texas wait was 24.1 Bcf in the first nine months of 2008, up from 22.7 Bcf in 2007.

As we previously we assigned a 50/50 joint venture agreement with a private company to drill two wells, already in the Haynesville and Bossier Shale in Shelby and San Augustine counties, Texas. The first vertical well's drilling is expected to reach total depth by the end of the fourth quarter.

In summary, we continue to having outstanding results in our E&P Midstream businesses and expect continued results in the remainder of 2008 and well into 2009. I will now turn it over to Greg Kerley, who will discuss our financial results.

Greg Kerley

Thank you, Steve and good morning. As Harold indicated our financial results for the quarter were outstanding. We had record earnings of $218 million or $0.63 a share, which was over four times our earnings for the same period last year. Our record results were driven by the significant growth in our production volumes and by higher realized natural gas prices. Our third quarter results included an after tax gain of $35.5 million or $0.10 a share from the July 1st sale of our utility.

Our operating cash flow also increased significantly to $312 million, double the prior year period. In the third quarter of 2008, operating income for our E&P segment was $280.6 million, up over threefold from the prior year period. We produced 52.8 Bcf in the quarter, 76% increase from a year ago and realized an average gas price of $8.56 in Mcf, up 29% from the prior year period.

Our lease operating expenses per unit of production were $0.96 in Mcf equivalent in the quarter, up from $0.67 a year ago. The higher per unit costs were driven primarily by our gathering and compression costs in the Fayetteville Shale play including the impact of higher natural gas prices on the cost of compression fuel.

We expect our lease operating expenses to average between $0.92 and $0.97 per Mcf in the fourth quarter.

General and administrative expenses per unit of production were $0.33 per Mcf in the third quarter, down from $0.46 last year. The decrease was primarily due to the effects of our increased production volumes which more than offset increased incentive compensation in payroll and related costs primarily associated with the expansion of our E&P operations.

We expect our unit G&A cost to average between $0.32 and $0.37 in the fourth quarter. Taxes other than income taxes, were $0.15 per Mcf in the quarter, compared to $0.11 in the prior year period due to changes in the mix of our production volume.

Our full cost pool amortization rate averaged $1.86 per Mcf in the third quarter, down from $2.56 a year ago. The decline in the average amortization rate was primarily a result of our sales of oil and gas properties in the second quarter and third quarter of 2008, the proceeds of which were credited to the full cost pool

Operating income from our Midstream Services segment was $18.3 million during the quarter, up from $4.1 million a year ago. The increase was due to higher gathering revenues related to our Fayetteville Shale play, partially offset by increased operating costs and expenses. At September 30th, we are gathering about 675 million cubic feet of gas a day in the Fayetteville Shale play area to approximately 793 miles of gathering lines.

Effective with the sale of our utility on July 1st, we are no longer engaged in any natural gas distribution operations. We received $223.5 million for the utility after post-closing adjustments and expenses and in order to receive regulatory approval for the sale and certain related transactions, paid $9.8 million to the utility for the benefit of its customers.

We recorded a pre-tax gain on the sale of the utility of $57.3 million in the third quarter. By the end of the third quarter, we closed on all, but $21 million of our planned 2008 divestitures, which were resultant total gross proceeds of approximately $1 billion. As a result of the tax gains realized from our E&P asset sales and the sale of our utility, we recorded a current tax provision of approximately $107 million, all of which is related to alternative minimum tax.

As a result of the turmoil in the financial and credit markets that has occurred over the past few weeks, liquidity has become a major concern of many companies. I am pleased to report that Southwestern Energy is in great shape. Over the past several months, we have dramatically improved our financial flexibility and strengthened our balance sheet. We had $426 million of cash and cash equivalents at the end of the third quarter and our $1billion unsecured credit facility remains completely undrawn.

Our strong financial results along with our asset sales combined to lower our debt to total percentage to 25% at the end of the quarter, down from 37% at year end, 2007. And our net debt at September 30th was 12%. We have a strong banking group and believe that our long-term relationships will weather the current downturn and benefit us for years to come.

In our commodity hedging program, we have not incurred any counterparty losses and believe that the counterparties to our current hedging contracts remain solid. Overall, we are very pleased with our performance to date and our financial position. We are in great shape as we head into 2009 with one of the strongest balance sheets in our history.

That concludes my comments. So now we will turn it back to the operator who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). We will take our first question from Scott Hanold, RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Good morning.

Harold Korell

Good morning.

Scott Hanold - RBC Capital Markets

Can you talk about the 60-acre downspacing? How do you think about this? Obviously you won't obviously go into this. You are pretty early, so your long-term development strategy isn't, I guess lack of better term isn't sort of compromise. So can you give us a sense of how you are approaching this to the 60-acres and what sort of adjustments you are making in case that you think on the plain 40 acres is the right number?

Steve Mueller

Scott. This is Steve. What we are doing is really we have targeted somewhere between a 150 and 200 wells. That will have some kind of downspacing consideration with them. First path is basically splitting what we did in some of our pilot areas which is roughly that 60 acres. Part of that 60 acres will be drilling between wells we have drilled in the past also. So we can see what happens between older producing wells as compared to just drilling them straight up new.

And then, we will continue the downspacing until we run into a situation where we are comfortable that we figured out what the right spacing is. So, we just keep working it down from there, but it is a couple of hundred wells work, which is between four to six months of drilling. And then to get production, you are probably looking this time next year before you really see results. But that we can say here is what it looks like the right spacing for certain areas.

Scott Hanold - RBC Capital Markets

Okay, at 60 acres and/or even if you were to think in terms of 40 acres at this time, is there any major change in the way you drill your patterns right now is this.

Steve Mueller

Not a significant change. 60 acres would just be splitting what we did in our pilot area. We were roughly 110 acres in the pilot area.

Scott Hanold - RBC Capital Markets

Okay. Okay, got it. And my follow up question, maybe for Greg. When you look at our cash position, obviously it is over 400 million, very strong at this point.

You did have, for accounting purposes, book the provision for the AMT. When that gets paid out, would that be sort of an early '09 event and would that be a reduction to cash or is that already accounted for in your current cash position?

Steve Mueller

There's about half of it, Scott, that is already paid and the balance will be paid in the fourth quarter and then in part over the year as we get into the beginning of 2009.

Scott Hanold - RBC Capital Markets

Okay. Got it. Appreciate it. Thanks.

Operator

And we will take our next question from Amir Arif at Friedman Billings.

Amir Arif - Friedman Billings

Good morning, guys. I was just wondering and I know you haven't given your '09 guidance and you won't be doing that till late December or so. But just how you are thinking of spending relative to your cash flow levels and just in terms of acreage expiring coming up, to just how things are shaping up when you look at '09.

Harold Korell

As you noted, in your question we are still building our plan for 2009 and I would say with the backdrop of everything that is going on in the economy and the world, we will be, maintaining our options open as we move right up to that time period.

I guess the, kinds of the way that we have been talking about it internally is keeping your options open is smart, and the analogy I have been using internally is a little bit driving on the freeway and following the car in front of you.

And if you follow one car far length behind and that car stops, down there almost certain to hit it. And if you follow five car lengths behind, you are going to get tired of people getting if front of you. So maybe we want to be following three or four car lengths behind.

Just keep our options open, we have a lot of flexibility in how we do, what we are doing going forward. Good thing is we are well suited to take advantage of opportunities. But, I guess the answer for right now is we are not at a point to put out our 2009 plan.

Amir Arif - Friedman Billings

Okay. Sounds good. Thanks, Harold.

Operator

Our next question comes from Brian singer, Goldman Sachs.

Brian singer - Goldman Sachs

Thank you. Good morning.

Harold Korell

Hi, Brian.

Steve Mueller

Good morning.

Brian singer - Goldman Sachs

Just following up in terms of the flexibility of your balance sheet, do you see opportunities for acreage or property acquisitions either in Fayetteville or in some of your other core areas that you may want to expand and is that something that you might look to do to the extent that some asset values remain distressed and depressed?

Harold Korell

It is kind of right to the prior question, we want to keep all of our options open and keep our eyes open. And fortunately, we did some of the things we did earlier this year not because we knew things were going to go bad in the financial markets, but because we thought they were fundamentally kind of the right things to do.

And selling the utility and exiting our positions in the Gulf Coast and Permian really so we could have people available to do more what we should be doing in East Texas and the Fayetteville and then finally testing the market with a piece of our acreage in the Fayetteville shale.

And there's no doubt right now as we look around, we see companies that aren't as well prepared for the times we are in as we are. And those projects or those things if they were things we became interested in, we would have to lay them along side of the other things we have to do and match them up with our capability to fund them and then make decisions on an individual basis.

Brian singer - Goldman Sachs

Great. Thanks. And then big picture on the Fayetteville. We have seen a continuous improvement in 30-day, 60-day average rates et cetera over the last year, partly because of the longer laterals, partly because of technology knowhow and moving up the learning curve et cetera. Can you just comment on where you feel you are on that learning curve and the extent to which you expect to continue to use longer and longer laterals and see improving initial production rates? Where are we on that scale?

Steve Mueller

Well, each area it will be a different spot on the scale. So I will go and just hit some topside. As far as longer laterals, there is some practical length where you are just not going to drill any longer lateral and the shallower parts of our play, you are probably not going to get much more than 4,000 to 4500. As you go deeper towards the middle you can get some longer laterals, but there is some practical limit. We haven't reached it yet and that's part of what we are testing and that the rock will tell us that.

You will get to a point where you just can't drill effectively and we will know what that lateral length is as far. As the completion techniques go, in the last nine months, we have gone from basically putting 1 million pounds to 2 million pounds of sand and about 1 million gallons to 2 million gallons of water in a single well to some of these ones with longer laterals over 4 million pound today.

And we are still getting incrementally very good results. We can continue to put more energy in and we can continue to decrease our intervals between our perforations and that will just continue going on. And since we haven't seen any kind of breakover or any kind of slowdown there, I really can't tell you what the end is.

Again, there's some practical point. But I don't know where that one is at. On the days drill wells, we took another couple of days out or almost two days out from the second quarter. We think there that once we are on pad, doing full development that we can average somewhere around 10 or maybe a little bit below 10 days a well, but we got to get to the full development stage. And that's down the roadway.

Brian singer - Goldman Sachs

Great. Thanks. And any constraints you are seeing in terms of the ability procure fracs end [province]?

Steve Mueller

We are not seeing at all. Our sand is not a very difficult sand to have overall. We know it is not coated, it is not high string province. So there hasn't been an issue in that direction. But because we have got so much sand, we have actually purchased our own sand mine and towards the middle of next year, second quarter sometime, we will have that up and running and we will be supplying about 70% of our own sand.

Brian singer - Goldman Sachs

Great. Thank you.

Operator

And we will take our next question from David Heikkinen at Tudor Pickering & Holt.

David Heikkinen - Tudor Pickering & Holt

Greg, just had a question. The current hedge positions and basis hedges and kind of rolling in to 2009 as well, any update to your hedging?

Greg Kerley

Just what we had in the press release this morning. We have about 11.5 Bcf commodity price hedged at 838 NYMEX and then we have about 17 Bcf with a collar of about I think 47, 76, ceiling of about 1070 and about 43 Bcf basis protected production that is basis protected at an average of around $0.92 to $1.

David Heikkinen - Tudor Pickering & Holt

Maybe I didn't phrase that very well. What would be the floor price given where gas prices are now, do you want to layer in more hedges for more protection or what is your kind of targets for per percent hedge as we roll into 2009 and then 2010? That's what I meant to say.

Greg Kerley

Well historically we would like to be around 50% or so hedged as we enter a year at least. And we are, we have got about 135 Bcf of production hedged right now. So, we are in pretty good shape right now. But again, we are looking for opportunities to hedge and we get some colder weather as we get into the winter months in November and December and we will take advantage of that.

Harold Korell

Adding to that, Greg, it would be fair to say that at prices where they are right now, we probably are not encouraged to do and haven't done recently more hedging.

David Heikkinen - Tudor Pickering & Holt

Yes and thinking about now operationally, Steve and you have talked about drilling on pads in some of the site-specific rig. You are still thinking about drilling four 4500-foot laterals in that overall pattern? Is that a general thought of long-term development? Or do you think you go across lease lines over time?

Greg Kerley

Well, that goes back to the state rules. Right now in state rules, you are supposed to have 500-foot offsets between wells and off your lease lines as well. And as you go to that downspacing you have to get exceptions.

Right now, we are getting those exceptions fairly easily. So we have drilled some wells actually over 5000-foot laterals already. Now when you get to the full development stage, again, I don't know exactly what those lengths are going be. That's just part of our learning curve.

David Heikkinen - Tudor Pickering & Holt

Yes, but the exceptions are case by case still.

Greg Kerley

They're still case by case. There's no change in field rules and probably the only change has been, when we first started drilling, if we wanted exception it took a little bit of time. Now, they're understanding better why we might want to drill longer wells or why we might want to drill closer to lease lines. We are getting those exceptions much faster.

David Heikkinen - Tudor Pickering & Holt

Okay and then Federal lands, just the update there, timing of process?

Greg Kerley

We have actually drilled on some private acreage right up and on two sides at least surrounded by federal acreage. So we are working that way with the rigs right now. In the case of Federal, it is just like any other Federal area. You want to put together units and we will start the exploratory units and work through the developing unit phase.

We have begun the discussions on showing BLM what those unit areas would like to do on a Federal unit standpoint. Waiting for their comments back and I expect that some time next year, early in the year, we will have unit designations and then we will drill some wells in Federal the way we are planning next year.

David Heikkinen - Tudor Pickering & Holt

Okay. Thanks, guys.

Operator

We will take our next question from Gil Yang, Citi.

Gil Yang - Citi

Hi. Just a follow up on that last question, Steve. The 500-foot spacing is a lease line separation, not between well separation?

Harold Korell

It is both.

Gil Yang - Citi

Both. Okay. But you need to get exceptions for to highlight.

Harold Korell

Right. So as we are doing down spacing we have to go to get exceptions just to do the testing, but we are getting those easy.

Gil Yang - Citi

Okay. What does your micro-seismic work tell you about how far the frac wings extend out from the older space laterals, older space fracs versus the tighter space fracs today?

Steve Mueller

It doesn't tell us a whole lot. As we have increased the clusters, it is getting a little more fuzzy on the seismic, along the way. I think part of your question, are we getting as far out on our wings now as we were before with the techniques we have got.

Theoretically we are designing them to get that far out.

Gil Yang - Citi

Okay.

Steve Mueller

And that's part of the reason for going from 2 million pounds to 4 million pounds because on a perforal link, whenever we are putting the same amount of energy in the ground, but part of the reasons for trying to do the spacing work is to help solidify whether we really are doing that or what is actually happening down there.

Gil Yang - Citi

Okay. And then the last question is for the sand mine, do your cost savings associated with doing that for the wells, is that built into your 3.1 million or would there be cost savings that would be seen. Is it a cost savings issue or is it a just more availability issue and how is that built in to your 3.1?

Steve Mueller

We did it because we thought there was some recent cost savings and we didn't want to worry about the availability part of the overall problem. In general, service companies versus what we think we can do it. We can do it for about half of what the service companies were charging us for sand, maybe even less than half. And that right now would be about $150,000 per well. And that affect will not come in and like I say until the earliest second quarter of next year. So, we have not factored that in to any of the '08 type numbers. And as we start talking about '09 later we will factor that in.

Gil Yang - Citi

Okay. And is this the answer in total cost or in savings?

Steve Mueller

About 150,000 savings per well.

Gil Yang - Citi

Okay. All right. Great. Thank you.

Operator

Our next question comes from Jeff Hayden, Rodman & Renshaw.

Jeff Hayden - Rodman & Renshaw

Morning, guys. Just a couple of quick questions. One, if you could give us a little color on what your exit rates for the quarter was in terms of production. And then also with the asset sales kind of behind us now, a little color on how we should think about the deferred tax percentage going forward?

Steve Mueller

On the exit rate for the quarter are you talking about net or Fayetteville?

Jeff Hayden - Rodman & Renshaw

Fayetteville and total company if possible.

Steve Mueller

We are probably doing in the 560 to 570 range, exit rate as a company give or take and that being net rate. On the Fayetteville, really over the last three to four weeks, we have been 600 to 610 on a gross basis on the Fayetteville and that goes back to Boardwalk issue.

Operator

And we will take our next question from Mike Scialla Thomas Weisel Partners.

Mike Scialla - Thomas Weisel Partners

Hi, guys.

Harold Korell

Good morning.

Steve Mueller

Good morning.

Mike Scialla - Thomas Weisel Partners

In terms of the Fayetteville lateral, how much production you estimated being curtailed in there or how many wells are waiting on completion?

Steve Mueller

Today, we have got 29 wells that are frac hooked up to the tanks and we could put on production. And what we have done, we haven't slowed down drilling obviously because we have got the same number of rigs running. We were a month ago doing between 7 and 9 frac jobs a week or wells a week.

What we got it done is we dropped that to 5 to 6 range on a number that we have done in a week and so we slowed that down. So part of our completions are going to move into next year. And then as we continue to drill that, 29 will go up from there.

Mike Scialla - Thomas Weisel Partners

Okay. How much of your production in the Fayetteville moves through that CenterPoint pipeline? There's still capacity on your other major takeaway pipeline in the areas? Is that not right?

Steve Mueller

We have got everything we can possibly get out of the Fayetteville, we are getting out of it right now with a small exception that on any given day, there's between 15 million and 20 million a day that we make decisions about. But we are maxed out of that 600 through any kind of outlets you can get. And on CenterPoint itself, we are moving total and this isn't just on the Fayetteville, but we are moving about 240 million a day of total gas on CenterPoint.

Mike Scialla - Thomas Weisel Partners

Okay and then in terms of the split on your rigs, can you say on the 15 rigs that are drilling horizontal wells, how many are drilling in maybe called new areas versus development areas?

Steve Mueller

That varies, but roughly five rigs are new areas, [proven up] acreage, those kind of things and the rest of the rigs are drilling second wells on a section or doing something in that direction. Second, third, fourth wells.

Mike Scialla - Thomas Weisel Partners

Thank you.

Operator

And our next question comes from Jason Gammel with Macquarie.

Jason Gammel - Macquarie

Thank you. Can you guys remind us how your takeaway capacity in the Fayetteville is going to step up from the existing 600 as Boardwalk is completed and then Fayetteville Express is completed and any other pipeline expansions that I maybe missing?

Steve Mueller

In the case of the Boardwalk, once it gets on very quickly, we will have about 550 million a day. It is really two stages, but that will be within a few months of each other. And then ultimately on Boardwalk, we will have about 800 million a day takeaway on a gross basis.

The new project that we signed up to the Fayetteville Express, that one when it goes on in 2011, over again about a 12-month period, we will end up having about 1.2 Bcf a day and then affirm on other pipelines, we have got roughly 220 million to 250 million a day that we either have or can continue to roll as long as we want to do that.

Jason Gammel - Macquarie

Okay. Great. And then my second question, now that you are about three years into the drilling program on the Fayetteville, have you seen anything that would indicate that any of your 860,000 acres would not be economic at $7 NYMEX price.

Steve Mueller

We really haven't. As part of what we have done over the last quarter and as we are working on our new completion techniques, we have drilled wells on the far eastern part of the acreage all the way to the far western and have gotten very good wells.

If you look at any of the third party stuff that's out there, you will see we have got 4 million a day test rates across our entire acreage block. So right now, we haven't condemned any of our acreage under any gas price really.

Harold Korell

But to be clear we have had some four wells that individually were not economic in given areas.

Steve Mueller

And let me add to that. The geology changes across the area also. Some areas have more faults than others and certainly you are not going to drill through a fault and really close to fault. So where there's a fault, we drop something out, but on a percentage basis, the acreage that's not very much.

Jason Gammel - Macquarie

Okay. Thank you guys.

Operator

And we will go next to Tom Gardner, Simmons and company.

Tom Gardner - Simmons and Company

Hey, guys just had a follow up to Brian's question. He mentioned basically practical limits to lateral lengths and what that meant with regard to rates and reserves. I understood you did say that you see or you project a practical limit somewhere in the 4,000 to 4500-foot range on lateral length. Is at that correct?

Steve Mueller

Well at certainly shallow areas. If you think about our acreage position, the north side of our acreage position is fairly shallow. You can be as shallow as 2000 feet and encounter Fayetteville Shale. The southern part of our acreage, that's more like 5500, 6000 feet on the very southern end. The practical limit is how much pipe you can push in a hole from what you are standing up on the dirt.

So, it has to do with just the physics. And so on a shallow acreage and that's why you will see for instance Petrohawk has a little less average lateral length than us. That is because in general they are on shallower acreage than we are drilling. That's just a practical physics issue. It is not a regular issue or anything else. And what will is you will get to the point where you physically just can't a pipe anymore and your drilling rates will drop off and you have for that rock in that area.

Tom Gardner - Simmons and Company

So with regard to the corresponding rate and reserve uplift, you really haven't seen as you put it, a breakover in that and you would expect the rates and reserves to maintain that relationship to lateral length going forward?

Steve Mueller

Yes and we have not seen the breakover and there could be a point out there where it does break over, but we haven't seen it. So, I don't know how to answer that other part.

Harold Korell

Well I think we don't know the answer is really. And so we have to drill the wells on that tighter spacing and have a long enough production history on them to compare them to ones drilled on different spacing.

Steve Mueller

On different spacing and different length.

Harold Korell

And then we will find out. I think the day when we have it, as Steve said we haven't seen it, but that doesn't mean that it won't be there.

Tom Gardner - Simmons and Company

Okay. And what is the longest lateral you all have drilled to date.

Steve Mueller

Just over 5,000 feet. We have done a couple of them.

Tom Gardner - Simmons and Company

Okay and then the second question I have is sort of a follow up. You mentioned that the additional [prompt] and more energy I assume, that's more horsepower you are pumping into the completion. And are you lumping that benefit under the perf cluster completions in that 20% to 25% uplift?

Steve Mueller

Wee are doing two different things. We have got the perf clusters and then we have got the number of stages that we do. That horsepower is one of that number of stages. And we have gone from a year ago, three to five type stage numbers to the day where nine to 11 stages. And each one of those stages are about the same size as the three to five were before. So that's where you get more energy in the ground.

Tom Gardner - Simmons and Company

I got you. Thanks, guys.

Operator

We will go next to Joseph Allman JPMorgan.

Joseph Allman - JPMorgan

Hi, everybody.

Harold Korell

Good morning.

Joseph Allman - JPMorgan

Just a follow up to some of the questions Jason was asking about the increasing capacity. So, to get the Fayetteville production to ramp up, to meet the capacities coming online, do you expect a ramp up in drilling activity significantly and over the next couple of years. And would you do that on your own or would you consider bringing in a partner?

Harold Korell

Joe, as you know from prior discussions about this, we have had in our mind, when we look at the overall Fayetteville Shale, that the way to maximize the present value is, one of the ways is to do what we can in terms of drilling at as rapid pace as possible. So, as we have thought about each of the years as we have moved along in our plan, in our heads it has been that we would put additional rigs out here to accelerate.

And that's a decision that I would tell you based upon where we are sitting here right today is one of those that we mull over in our heads and we look forward at all of the uncertainties and the market places and everything else and that gets wrapped up in our 2009 plan, for example, falls under the category of maintaining our options open. And maintaining flexibility.

There would be some point in time clearly in this play when we would want to drill more wells per year than we are. One of the good thing that's happening to us is that as we have been able to continue to improve our operating performance and drilling, we are actually drilling more wells per year with the same number of rigs and that's been a quite substantial improvement.

If you think back to some of these conference calls when we had much longer amounts of time required to drill an individual well. We are down now in this quarter to averaging 12 and Steve has said we can go to ten. So, we are getting more activity and more drilling. The answer of bringing in somebody to do this is, is would be like giving away equity in the company.

And it doesn't compute for me when the value creation that we are seeing even at current price levels that we are achieving with our drilling. But as a corporation, as a company overall, we need to keep the balance here much like our helicopter on the cover of the annual report turned out to be very prophetic for this year. And I think it is also applicable to next year. We want to keep capturing acreage and we want to keep making improvements, we want to keep improving our efficiency. And there will be a time where we will want to do additional drilling, put more drilling rigs out here.

Joseph Allman - JPMorgan

Okay. Harold, based on your obligations you have to get gas in those pipelines. Is there a need to ramp up the activity to some extent if not in '09, then in 2010?

Harold Korell

Well, all of that has to come together as we see the impact of the improving results and going forward, it depends upon how you model the improvements that we might see with some of the things we are doing currently.

Joseph Allman - JPMorgan

Okay. That's very helpful. Thank you.

Operator

We will go next to Dan McSpirit, BMO Capital Markets.

Dan McSpirit - BMO Capital Markets

Gentlemen, good morning.

Harold Korell

Good morning, Dan.

Dan McSpirit - BMO Capital Markets

Can you comment or do you have any comments on other pay zones that you maybe testing, obviously or namely the Moorefield and the Chattanooga.

Steve Mueller

In the case of Moorefield, we haven't done anything on it from over a year ago. And part of the reason for our XTO sale as some of our properties, was let them do testing on that. So from that standpoint, we really haven't done anything else.

On the Chattanooga, we will drill a couple of Chattanooga tests, maybe we can get one started this year. But we will drill a couple of them end of this year going into 2009 and start getting some information on it.

Dan McSpirit - BMO Capital Markets

Okay. And then a follow up question with respect to the well or wells that you are drilling with lateral lengths greater than 5000 feet. Can you comment on planned number of frac stages on those wells and the spacing between frac stages?

Steve Mueller

We are still experimenting. So, I can tell you that the ones we have just recently done were 75-foot plus cluster spacing between the first and the stages on that I think the most we did on one of those really long laterals was 12 stages.

Harold Korell

If we go to a 50-foot cluster spacing on our perforations which we are doing in some of our other wells and experimenting with right now, those stages might go up. It may go up another two to three, four stages. So, that is the kind of range.

Dan McSpirit - BMO Capital Markets

Okay. Very good. And then lastly on [Waloo], any comments? You are certainly realizing success there as is Petrohawk as you comment in your press release that they're operating two rigs. Have you determined EURs at all? Are you willing to comment on cumulative production rates at this point?

Steve Mueller

What did you say?

Harold Korell

On Waloo, what did you say.

Dan McSpirit - BMO Capital Markets

I'm sorry, no.

Harold Korell

We are looking at each other here wondering what that is?

Dan McSpirit - BMO Capital Markets

Yes, I am sorry. A wrong, a different question for a different company.

Harold Korell

Waloo, yes?

Dan McSpirit - BMO Capital Markets

Yes, no need to comment.

Harold Korell

We don't know what Waloo is, it sounds good though.

Dan McSpirit - BMO Capital Markets

Yes, you got it. You should be there. There you go. Thank you very much.

Operator

(Operator Instructions). We will go next to Joe Magner, Tristone Capital.

Joe Magner - Tristone Capital

Good morning. There was a time several quarters back when you all discussed resource potential of your acreage based on estimates of gas and plays and through the recoveries. As your results continue to get better and as you continue to optimize drilling and completion designs, has your understanding of that gas in place or has your sort of estimate or recoveries changed at all and can we expect any sort of update at some point in the future on recoverable resource estimates? Thanks.

Steve Mueller

Well, as far as the kind of gas and plays number. Every well we drill gives us more information about the gas and plays and we have a group that their whole job is to work on gathering all the information we have and put it in a big picture for us and whether that completion technique, drilling technique, gas and plays or any of the other rock characteristics, permeability, frosting those things that go with it and so we are continually updating that and we are getting new information.

I don't know that when you start saying about what we are going to update in the future and do things, I don't know. As we get the important things, and as we apply it in the field, you will see that, but I don't know when we are going to do an update as far as that goes. We will just have to see what happens.

Operator

And our next question comes from Marshall Carver, Capital One.

Marshall Carver - Capital One

Yes, I had a couple of questions. The first one on the wells that you put online in the third quarter, you had been putting on about 80 wells a quarter and you stepped up to 97. Did you tie a bunch of wells on at the beginning or at the end of the quarter or were they spread throughout the quarter just trying to get a feel for how much of the Q3 bit was timing versus rate?

Steve Mueller

Well, toward the end of the quarter, you were starting to see the CenterPoint issue. So we actually slowed down a little bit right at the very end of the quarter. But other than that it was pretty constant right through the whole quarter. When I say the last quarter, maybe the last two weeks we slowed down a little. But it was pretty much consistent across that. I think what you were seeing that the well count completion going up, was a function of the drilling days going down. So you are drilling more wells per quarter and you are going to complete more wells for the quarter.

Harold Korell

And then you would always have the variability of Midstream of the gathering system laterals looking up and different compression systems coming on. So it is not strictly a drilled, completed and necessarily directly in to the pipelines because in some of the areas we have to build out and expand the piping system in order to put them on. Then they come on in groups also. So it could be a lot of variability in that over time. You have to keep that in mind.

Marshall Carver - Capital One

Okay. Thank you. Did you give the production breakdown by area? I missed the first minute or two of the call.

Steve Mueller

We did. Is there any particular one?

Marshall Carver - Capital One

I was hoping for the breakdown of East Texas conventional and Fayetteville and any other, if you could give me the breakdown again, I would appreciate it.

Steve Mueller

Okay.

Harold Korell

Have you got it, Greg?

Greg Kerley

For the Arkoma conventional it was 6.8 Bcfe, Fayetteville Shale, 37.2, East Texas 8.1, the Gulf Coast, Permian and others is about 0.7, and if I did that right that should add out to 52.8.

Marshall Carver - Capital One

Okay. Thank you very much. Sorry about that.

Steve Mueller

Okay.

Operator

And Mr. Korell, we have no other questions standing by at this time. I would like to turn the conference back over to you for any additional or closing remarks.

Harold Korell

Okay. Well, just to sum all of this up, when you look at Southwestern Energy, where we are positioned is financially strong. Our balance sheet being now at 25% debt-to-cap. We have a low cost structure as our DD&A rates are in the sub $2 per Mcf range and being impacted positively by further drilling in the Fayetteville Shale.

We are in a great position on our projects. That's evidenced again in our cost structure plus the size of the projects we have in front of us can have substantial impact on the results going forward. We have a growing production volume. And that will drive in front of us just because of our activity levels.

And then, with all of that summed up, we have the flexibility to act. We have options open to us which will position us really well to keep our eyes open for opportunities in the market we are in. So, I want to thank you again for joining us and have a good day.

Operator

And once again, ladies and gentlemen, that does conclude today's conference call. We do thank you for your participation. You may disconnect at this time.

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Source: Southwestern Energy Co. Q3 2008 Earnings Call Transcript
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