8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): October 31, 2008

SOUTHWESTERN ENERGY COMPANY

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of incorporation)

1-08246	71-0205415
(Commission File Number)	(IRS Employer Identification No.)

2350 N. Sam Houston Pkwy. E., Suite 125, Houston, Texas	77032
(Address of principal executive offices)	(Zip Code)

(281) 618-4700

(Registrant's telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

       o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

EXPLANATORY NOTE

The information in this Report, including the exhibit, is being furnished pursuant to Item 7.01 of Form 8-K and General Instruction B.2 thereunder.  Such information shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

SECTION 7 - -  REGULATION FD

Item 7.01 Regulation FD Disclosure.

On October 31, 2008, Southwestern Energy Company hosted a telephone conference call for investors and analysts.  The teleconference transcript is furnished herewith as Exhibit 99.1.

Exhibits.  The following exhibit is being furnished as part of this Report.

Exhibit Number	Description
99.1	Teleconference transcript for October 31, 2008 telephone conference call for investors and analysts.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	SOUTHWESTERN ENERGY COMPANY
Dated: November 3, 2008	By:	/s/    GREG D. KERLEY
	Name:	Greg D. Kerley
	Title:	Executive Vice President and
		Chief Financial Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Teleconference transcript for October 31, 2008 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Company

Q3 2008 Earnings Conference Call

Friday, October 31, 2008

Officers

 Harold Korell; Southwestern Energy; Chairman and CEO

 Steve Mueller; Southwestern Energy; President

 Greg Kerley; Southwestern Energy; CFO

Analysts

 Scott Hanold; RBC Capital Markets; Analyst

 Amir Arif; Friedman Billings Ramsey; Analyst

 Brian Singer; Goldman Sachs; Analyst

 David Heikkinen; Tudor, Pickering & Holt; Analyst

 Gil Yang; Citi; Analyst

 Jeff Hayden; Pritchard Capital Partners; Analyst

 Mike Scialla; Thomas Weisel Partners; Analyst

 Jason Gammel; Macquarie Research Equities; Analyst

 Tom Gardner; Simmons & Company; Analyst

 Joseph Allman; JPMorgan; Analyst

 Dan McSpirit; BMO Capital Markets; Analyst

 Joe Magner; Tristone Capital; Analyst

 Marshall Carver; Capital One; Analyst

Presentation

Operator:  Good day, and welcome to the Southwestern Energy Company's 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:  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're 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 30, 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 to 192 Bcfe for 2008, which is an increase of approximately 68% compared to last year.

I'm 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'd now like to turn the teleconference over to Steve for more details on our E&P and midstream activities and then to Greg Kerley for an update on our financial results, and then we'll take questions.

Steve Mueller:  Thank you, Harold.  

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 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 0.7 of a Bcf from our Permian and Gulf Coast assets prior to the closing on the sale of nearly all of the properties there.  

As a result of our continued strong production performance, we now estimate that our fourth quarter production will range between 53 and 55 Bcf, and our full-year 2008 production will range from 190 to 192 Bcfe.  We are expecting flat to 4% production growth between 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 nine months 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 30, our gross production -- 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-one completion date that was originally anticipated to begin -- 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 3,736 feet, and an average drill time of 12 days from reentry to reentry.  This compares to an average time of 14 days to drill and 3,500 -- or, oh, just over 3,500-foot lateral last quarter.  Additionally, we continue to improve our completion practices with our wells completed averaging higher initial, 30^th and 60^th-day production rates ranging from 13 to 16% above our results in the second quarter.  

During the first three quarters of 2008, we continued testing 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 is improved by 20% to 25%, and we are currently planning to utilize this technique on all wells we plan to drill for the remainder of the year and into 2009.  Associated with this completion technique and longer laterals, we now expect completed well costs to average approximately $3.1 million per well for the fourth quarter.  

As a result of the continued performance of our Fayetteville Shale wells, we signed a precedent agreement with the Fayetteville Express Pipeline on September 30 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 the other areas.  

In Pennsylvania, we currently have approximately 110,000 net acres where we believe the Marcellus Shale is prospective.  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 the third quarter with encouraging results.  One vertical well is waiting on a 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 101 -- $104 million in our conventional Arkoma Basin properties.  We participated in drilling 61 wells here, including 21 wells at our 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 months of 2007.

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

As we previously announced, we have signed a 50/50 joint venture agreement with a private company to drill two wells starting the Haynesville interval of the Bossier Shale in Shelby and St. Augustine County, 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 have an -- outstanding results in our E&P and 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 1 sale of our utility.  

Our operating cash flow also increased significantly to $312 million⁽¹⁾, 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, a 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, payroll, and related costs primarily associated with the expansion of our E&P operations.  We expect our unit G&A costs 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 volumes.  

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 the result of our sales of oil and gas properties in the second and third quarters 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 30, we were gathering about 675 million cubic feet of gas a day in the Fayetteville Shale play area through approximately 793 miles of gathering lines.  

Effective with the sale of our utility on July 1, 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 will result in 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 any company's.  

I'm pleased to report that Southwestern Energy is in great shape.  Over the past several months, we've 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 $1 billion unsecured credit facility remains completely undrawn.  

Our strong financial results, along with our asset sales, combined to lower our debt-to-total capital percentage to 25% at the end of the quarter, down from 37% at year-end 2007, and our net debt at September 30 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 counter-party losses and believe that the counter-parties to our current hedging contracts remain solid.  

Overall, we're very pleased with our performance to date and our financial position.  We are in great shape as we enter 2009 with one of the strongest balance sheets in our history.

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

Questions and Answers

Scott Hanold:  Can you talk about the 60-acre downspacing?  You know, how do you think about this?  Obviously, you want to obviously go into this pretty early so your long-term development strategy isn't, I guess for lack of a better term, isn't sort of compromised, but can you kind of give us a sense of how you're approaching this, to the 60 acres and what sort of adjustments you're making in case that you think all the [point] 40 acres is the right number?

Steve Mueller:  Scott, this is Steve.  What we're doing is really we've targeted somewhere between 150 and 200 wells that will have some kind of downspacing consideration with them.  First pass 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've drilled in the past, also, so we can see what happens when we drill between older producing wells, as compared to just drilling them straight up new.  

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

Scott Hanold: Okay.  At 60 acres and--or even if you were to think in terms of 40 acres at this time, is there any major in the way you drill your patterns right now?

Steve Mueller: Not a significant change.  60 acres would just be splitting what we did in our pilot area.  So we're roughly 110 acres in the pilot area of the (inaudible).

Scott Hanold: Okay, got it.  And my follow-up question, maybe for Greg.  When you look at your cash position, obviously, its $400 million, very strong at this point.  You do--you did have to for I guess accounting purposes book the provision for the AMT.  Is--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?

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

Scott Hanold: Okay, got it.  Appreciate it.  Thanks.

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

Harold Korell: Well, we're--as you noted in your question, we're still building our plan for 2009.  And I would say with the backdrop of everything that's going on in the economy and the world we'll be maintaining our options open as they move right up to that time period.  I guess kind of the way that we've been talking about it internally is keeping your options open is smart.  And the analogy I've been using internally is a little bit like driving on the freeway and following a car in front of you.  

And if you follow one car length behind and that car stops, you're darn near almost certain to hit it.  If you follow five car lengths behind, you're going to get tired of people getting in 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're doing going forward.  Good thing is we're 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: Sounds good.  Thanks, Harold.

Brian Singer: 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 there--that some asset values remain distressed and depressed?

Harold Korell: Well, we want to keep all of our--just 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 of 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 time to end as we are.

And those projects or those things, if they were things we became interested in would--we'd have to lay them alongside 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: Great, thanks.  And then, big picture on the Fayetteville, we've seen the continuous improvement in 30-day, 60-day average rates, etc. over the last year partly because of the longer laterals, partly because of technology know-how 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 we can--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 has--is a little spot on the scale.  So, just hit them top-sided.  As far as longer laterals, there is some practical length where you're just not going to drill any longer lateral.  And in the shallower parts of our play you're probably not going to get much more than 4,000, 4,500.  As you get deeper towards the middle, you can get some longer laterals.  But there's some practical limit.  We haven't reached it yet and that's part of what we're testing.  And the rock will tell us that.  You'll get to a point where you can't just drill effectively.  And we'll know what that lateral length is.  

As far as the completion techniques go, in the last nine months we've gone from basically putting 1 to 2 million pounds of sand and about 1 million to 2 millions gallons of water in a single well to some of these ones in the longer laterals over 4 million pounds today.  And we're still getting incrementally very good results.  And we can continue to put more energy in and we can continue to decrease our intervals between our perforations and we'll--and that will just continue going on.

And since we haven't seen any kind of break over 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's at.   On the days to drill wells, you saw we took another couple days out or almost two days out from the second quarter.  We think there that once we're on pad doing full development that we can average somewhere around 10 or maybe even a little below 10 days of wells.  But we've got to get to the full development stage and that's down the road a ways.

Brian Singer: Great, thanks.  And any constraints you're seeing in terms of the ability to procure frac sand profit?

Steve Mueller: We're not seeing at all--and there's--our sand is not a very difficult sand to have overall.  We don't--it's not coated, it's not a high sand profit, so there hasn't been an issue that direction. But because we've got so much sand, we've actually purchased our own sand mine.  And towards the middle of next year, second quarter sometime, we'll have that up and running and we'll be supplying about 70% of our own sand.

David Heikkinen: Good morning.  Greg, just had a question.  Current hedge positions and basis hedges and kind of rolling into 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 hedge at $8.38 NYMEX and then we have about 17 Bcf with a collar of about I think $7.76, ceiling of about $10.70.  And about 43 Bcf of basis protect that--or production that is basically protected at an average of around $0.92 to $1.00.

David Heikkinen: --Maybe I was--I didn't phrase that very well.  I'm thinking about what would be the floor price given where gas prices are now where you want to layer in more hedges for more protection or what's your kind of target for percent hedge as roll into 2009 and then 2010?  That's what I meant to say.

Greg Kerley: Well, we like to be about--as we historically would like to be around 50% or so hedged as we enter a year at least.  And we're--we've got about 135 Bcf of production hedge right now, so we're in pretty good shape right now.  But again, we're looking for opportunities to hedge and we get some cooler weather as we get into the winter months in November and December and we'll take advantage of that.

Steve Mueller: I think just 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: Yes.  And thinking about the operation with Steve and you talked about drilling on pads in some of the site specific rigs, you're still thinking about drilling four 4,500-foot laterals in that overall pattern?  Is that kind of a general thought of long-term development, or do you think you go across lease lines over time?

Steve Mueller: Well--and that goes back to kind of the state rules.  Right now with state rules you're supposed to have 500-foot offsets between wells and off your lease lines as well.  And as you go to that down spacing you have to get exceptions.

David Heikkinen: Okay.

Steve Mueller: Right now, we're getting those exceptions fairly easily.

David Heikkinen: Okay.

Steve Mueller: So we have drilled some wells, actually over 5,000-foot laterals already.  Now, when you get to the full development stage, again, I don't know exactly what those lengths are going to be.  That's just part of our learning curve.

David Heikkinen: Yes.  But the exceptions are case by case still and--.

Steve Mueller: They are 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.  So we're getting those exceptions much, much faster.

David Heikkinen: Okay.  And then, federal land, just the update there, kind of timing in process.

Harold Korell: We have actually drilled on some private acreage right up and kind of on two sides that we've surrounded by federal acreage.  So we're working that way with the rigs right now.  In the case of federal, it's just like any other federal area.  You want to put together units and we'll start with exploratory units and work through the development unit phase.  We have begun the discussions on showing the BLM what those unit areas would like to do in a federal unit standpoint.  Awaiting their comments back and I expect that sometime next year, early in the year, we'll have unit designation, and then we'll drill some wells on federal the way we're planning next year.

David Heikkinen: Okay.  Thanks, guys.

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

Steve Mueller: It is both.

Gil Yang: It's both.  Okay.  So--but you need to get exceptions for--.

Steve Mueller: --So as we're doing this down spacing, we have to go to get exceptions just to do the testing, but we're getting those easy.

Gil Yang: 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've increased the clusters it's 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've got, theoretically we're designing them to get that far out.

Gil Yang: Okay.

Steve Mueller: And real--and that's part of the reason for going to the--from 2 million pounds to 4 million pounds, because on a per perf length interval we're putting the same amount of energy in the ground.  But part of the reason for trying to do the spacing work is to help solidify whether we really are doing that or what's actually happening down there.

Gil Yang: Okay.  And then, the last question is for the sand mine are--do you have cost savings associated with doing that for the wells and is that built into your $3.1 million, or would there be cost savings that would be seen--is it a cost savings venture or is it just more availability issue?  And how is that built into your $3.1?

Steve Mueller: We did it because we thought there would be some cost savings and we didn't want to worry about the availability part of the overall problem.  In general, the 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 what that--right now would be about $150,000 per well.  And that effect will not come in, like I say, until the earliest second quarter of next year.  So we have not factored that into any of the '08 type numbers and as we start talking about '09 later, we'll factor that in.

Gil Yang: Okay.  And is that $150 in total cost or in savings?

Steve Mueller: About $150,000 savings per well.

Gil Yang: Okay.  All right.  Great.  Thank you.

Jeff Hayden:  Good morning, guys.  Just a couple quick questions.  I wonder 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 could think about the deferred tax percentage going forward?

Steve Mueller: On the exit rate for the quarter, you're talking about nets or Fayetteville or --

Jeff Hayden:  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 would be a net rate.  On the Fayetteville, really, over the last three to four weeks, we've been 600 to 610 on a gross basis on the Fayetteville and that goes back to (inaudible).

Mike Scialla:  In terms of the Fayetteville lateral, how much production do you estimate is being curtailed there now, or how many wells are waiting on completion?

Steve Mueller: Today, we've got 29 wells that are fraced, hooked up to the tanks, and we could put on production.  And what we've done -- we haven’t slowed down drilling obviously, because we've got the same number of rigs running.  We were, a month ago, doing between seven and nine frac jobs a week or wells a week.  What we've done is we've dropped that to the five to six range on the numbers that we've done a week until we slow that down.  So part of our completions are going to move into next year and then as we continue to drill that 29, we'll go up from there.

Mike Scialla:  Okay.  Remind me, how much of your production in the Fayetteville moves through that center point pipeline?  There's still capacity on your other major takeaway pipeline in the area, is that right?

Steve Mueller: We've got everything -- everything we can possibly get out of the Fayetteville, we're getting out of it right now, with a small exception.  On any given day, there's between 15 and 20 million a day that we make decision about, but we're maxed out at that 600 through any kind of outlets you can get.  And on CenterPoint itself, we're moving total -- and this isn’t just on the Fayetteville, but we're moving about 240 million a day total gas on CenterPoint.

Mike Scialla:  Okay.  And then in terms of the split on your rigs, can you say, on the 15 rights that are drilling horizontal wells, how many are drilling in -- maybe you'd call them new areas versus development areas?

Steve Mueller: That varies, but roughly five rigs are kind of new areas, proven up acreage, those kind of things, and the rest of the rigs are drilling second wells on a section and they're doing something in that direction, second, third, fourth wells.

Mike Scialla:  Thank you.

Jason Gammel:  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 may be missing?

Steve Mueller: Well, in the case of the Boardwalk, once it gets on, very quickly, we'll be having -- we'll have about 550 million a day.  It's really two stages, but that'll be within a few months of each other and then ultimately, on Boardwalk, we'll have about 800 million a day takeaway on a gross basis.  The new project that we signed up, the Fayetteville Express, that one, when it goes on in 2011, over again, about a 12-month period, will end up having about 1.2 Bcf a day.  And then firm on other pipelines, we've got roughly 220 to 250 million a day that we either have or can continue to roll, as long as we want to do that.

Jason Gammel:  Okay, great.  and then my second quarter -- now that you're about three years into the drilling program on the Fayetteville, have you see anything that would indicate that any of your 860,000 acres would not be economic at -- let's just say at $7.00 NYMEX price?

Steve Mueller: We really haven’t.  part of what we've done over the last quarter, as we've got -- working on our new completion techniques, we've 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'll see we've 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've had some poor wells that individually, were not economic in different areas.

Steve Mueller: And there will -- let me add to that.  The geology changes across the area also.  Some areas have more faults than others, and certainly, you're not going to drill through a fault, or really close to faults, so where there's a fault, we'd draw something, but on a percentage basis, it's not very much.

Jason Gammel:  Okay.  Thank you, guys.

Tom Gardner:  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 to say that you see, or you project, a practical limit, somewhere in the 4,000 to 4,500-foot range on lateral length.  Is that correct?

Steve Mueller: Well, I said in the 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 2,000 feet and encounter the Fayetteville Shale.  The southern part of our acreage, that's more like 5,500, 6,000 feet on the very southern end.  So the practical limit is how much pipe you can push in a hole, from what you have standing up in the derrick, but it has to do just the physics.  

And so on that shallow acreage and that's why you'll see -- for instance, PetroHawk is a little bit less average lateral length than us.  That's because in general, they're in shallower acreage than we're drilling.  That's just a practical physics issue; it's not a rig issue or anything else, and what'll happen is if you get to the point where you physically just can't move the pipe anymore, and you're drilling rates will drop off and you know you’ve done it for that block and that area.

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

Steve Mueller: There's -- yes, 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 part.  It just --

Harold Korell: Well, I think we don’t know the answer is what -- is really -- 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.  And then --

Steve Mueller: Different spacing and different lengths.

Harold Korell: And then we'll find out.

Tom Gardner:  What is the longest lateral --

Harold Korell: We have, as Steve said, we haven’t seen it, but that doesn’t mean that it won't be there.

Tom Gardner:  What is the longest lateral you all have drilled to date?

Steve Mueller: Just over 5,000 feet.  We've done a couple of them.

Tom Gardner:  Okay.  And then the second question I have is sort of a follow-up to - -- you mentioned that the additional profit and more energy, I assume that's more horsepower you're pumping into the completions to --

Steve Mueller: Right.

Tom Gardner:  And are you lumping that benefit under the first cluster completions, that 20 to 25%?

Steve Mueller: Well, there's -- we're doing two different things.  We've got the first clusters and then we've got the number of stages that we do.  That horsepower is under that number of stages and we've gone from a year ago, three to five type stage numbers, to today, where it's 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:  I see.  Thanks, guys.

Joseph Allman:  Just a follow-up to some of the questions Jason was asking about the increasing capacity.  To get the Fayetteville production to ramp up to meet the capacities coming online, do you expect to ramp up the drilling activity significantly 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, we, as you know from prior discussions about this, we have had in our mind that there -- when we look at the overall Fayetteville shale play, that the way to maximize the present value is -- one of the ways is to do what we can in terms of drilling as at rapid a pace as possible.  So as we've thought about each of the years as we've moved along in our plans, in our heads, it's 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're sitting here right today is one of those that we mull over in our heads and we look forward at all of the uncertainties in the marketplaces 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 to drill more wells per year than we are.  One of the good things that's happening to us is that as we've been able to continue to improve our operation performance and drilling, we're 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're down now, in this quarter, to averaging 12 and Steve has said we can go to 10, so we're getting more activity and more drilling.

The answer of bringing in somebody to do this would be like giving away equity in the Company and it doesn’t compute for me, when the value creation that we're seeing, even at current price levels that we're achieving with our drilling, but as a corporation, as a company overall, we need to keep a 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's 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 when we'll want to do additional drilling, put more drilling rigs out here.

Joseph Allman:  Okay.  So how -- based on your obligation, do you have to get (inaudible) the pipelines, do you -- is there a need to ramp up the activities 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 it depends on how you model -- going forward, it depends upon how you model the improvements that we might see with some of the things we're doing currently.

Joseph Allman:  Okay.  That's great.  It's very helpful.  Thank you.

Dan McSpirit:  Can you comment, or do you have any comments on other pay zones that you may be 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 FTO sale of some our properties was let them do some testing on that and 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 one started this year, but we'll drill a couple of them the end of this year going on 2009, and start getting some information on it.

Dan McSpirit:  Okay.  And then a follow-up question with respect to the well, or wells, that you're drilling with lateral lengths greater than 5,000 feet.  Can you comment on planned number of stages, frac stages, on those wells and the spacing between frac stages?

Steve Mueller: We're still experimenting, so I can tell you that the ones we've just recently done, were 75-foot cluster space between the first -- I'm sorry -- 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.  If we go to a 50-foot cluster spacing on our perforations, which we're kind of 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's the kind of range.

Dan McSpirit:  Okay, very good.  And then lastly on WEHLU, on comments - -- you're 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 accumulated production rates at this point?

Steve Mueller: Where did you say?

Dan McSpirit:  At WEHLU.

Harold Korell: What did you say --

Dan McSpirit:  I'm sorry.

Harold Korell: We're looking at each other here wondering what that is.

Dan McSpirit:  Yes, I'm sorry, wrong -- different question for a different company.

Harold Korell: Yes, no need to comment.

Steve Mueller: We don’t know what WEHLU is; it sounds good, though.

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

Joe Magner: There was a time, several quarters back when you all discussed resource potential in your acreage, based on estimates of gas in place and crude oil recoveries. As your results continue to get better and as you continue to optimize drilling and completion design, has your understanding of that gas in place or has your estimate of 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: As far as the gas in place number, every well we drill gives us more information about the gas in place. 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’s completion technique, drilling technique, gas in place or any of the other rock characteristics; permeability, porosity and those things that go with it. And so, we’re continually updating that and we are getting new information. I don’t know that -- when you start saying are we going to update in the future and do things, I don’t know. As we get important things and as we apply it in the field, you’ll see that, but I don’t know that we’re going to just do an update as far as that goes. We have to see what happens.

Marshall Carver: I had a couple of questions. The first one, on the wells that you put on line 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? I’m just trying to get a feel for how much of the Q3 beat was timing versus rate.

Steve Mueller: Well, towards 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 a pretty constant rate 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. And I think what you’re seeing, that well count completion going up was a function of those drilling days going down, so you’re drilling more wells per quarter and you’re having to complete more wells per quarter.

Harold Korell: And then you would always have the variability of midstream -- of the gathering system laterals hooking up and different compression systems coming on. So, it’s not strictly a drilled, completed and necessarily directly in to the pipeline, 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 there could be a lot of variability in that over time. You have to keep that in mind.

Marshall Carver: 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: I was hoping for the breakdown of East Texas conventional and Fayetteville. If you could give me the breakdown again, I’d appreciate it.

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

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

Harold Korell: Okay. Well, just to sum all this up, I think when you look at Southwestern Energy, where we’re 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 $2.00 per Mcf range and being impacted positively by further drilling in the Fayetteville shale. We're in a great position on our projects and 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 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’re in.

So I want to thank you again for joining us and have a good day.

(1) Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Net cash provided by operating activities before changes in operating assets and liabilities should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles. The table below reconciles net cash provided by operating activities before changes in operating assets and liabilities with net cash provided by operating activities as derived from the company's financial information.

	3 Months Ended September 30,
	2008		2007
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	312,139	$	157,720
Add back (deduct):
Change in operating assets and liabilities		66,316		19,080
Net cash provided by operating activities	$	378,455	$	176,800