Form 8-K

Operator: Good day, everyone, and welcome to the Southwestern Energy Company third quarter earnings teleconference. Today's call is being recorded. At this time, I would like to turn the conference over to the President, Chairman, and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.

Harold Korell: Good morning, and thank you for joining us. With me today are Richard Lane, the President of our E&P segment, and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release we announced yesterday regarding our third quarter results, please call 281-618-4784 to have a copy faxed to you.

Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

In preparing for this teleconference today, I couldn't help but reflect on the changes in our company over the past few years. Nearly 10 years ago we set out on a new strategy for our company. That was to build an organization capable of generating high return drilling opportunities. We have, with the help of a lot of good people, been highly successful at this, evidenced by our developments at the Ranger Anticline in Arkansas, our East Texas activities at Overton and in a bigger way even, our large acreage position in the Fayetteville Shale.

Finally, we are continuing to push the ball down the field in the Fayetteville Shale play, with longer horizontal wells, larger fracs and with the benefit of our growing 3-D seismic knowledge. In the Fayetteville we're building the database of production history on our wells and we're continuing to drill in new areas to evaluate our very large acreage position.

As we reported in our press release yesterday, we are experiencing better performance with longer laterals and larger frac stimulation treatments, which we expect will result in higher EURs for these wells.

I'd like to now turn the teleconference over to Richard for more details on our E&P activities and then to Greg for an update on our financial results.

Richard Lane: Thank you, Harold. Good morning. During the third quarter our natural gas and crude oil production totaled 30 Bcfe, up 56% from the 19.3 Bcfe we produced in the third quarter 2006. The increase was primarily due to growth from our Fayetteville Shale play, which produced 14.7 Bcf in the third quarter of 2007, compared to 10.7 in the second quarter of 2007, and 3.8 in the third quarter of 2006.

Due to our strong performance in the third quarter, we expect our full year's production to be approximately 111 Bcfe, above the top of our previous guidance range of 107 to 110 and we expect our Fayetteville Shale production for the full year to be approximately 51 Bcf.

In the first nine months of 2007, we invested approximately $1.05 billion in our exploration and production activities and participated in drilling 476 wells. Of those, 287 were productive, 10 were dry, and 179 were in progress at September 30th, for an overall success rate of 97%.

Of the $1.05 billion invested, approximately $872 million, or 83% was for drilling wells. We currently have 31 rigs running in the company, 15 deep and four shallow rigs in the Fayetteville Shale play, 6 rigs in East Texas, 1 in North Louisiana, 1 in the Permian Basin and 4 in our conventional Arkoma Basin activities.

At the Fayetteville Shale play, during the first nine months of the year we have invested approximately $731 million and have placed 187 wells on production. Gross production from our operated wells has increased from approximately 100 million cubic feet per day at the beginning of 2007, to 260 million cubic feet per day at October 22nd.

Approximately 16 million cubic feet per day of our current production is from 8 wells producing from conventional reservoirs and they're spread out over six different pilot areas in four counties. And we expect to be producing approximately 300 million cubic feet per day gross from our operated wells at the end of the year in the play.

During the third quarter our time drilled to total depth averaged 16 days from reentry to reentry compared to a second quarter time of 18 days. Average completed well cost during the third quarter were $3.0 million per well, slightly higher than the 2.9 that we completed in the last quarter, and that's due to drilling and completing wells with longer horizontals and some larger fracture stimulations. Although our average total well cost for the quarter was up, we have reduced our drilling and completion costs on a dollar per foot basis quarter on quarter.

Lateral lengths for third quarter averaged 2,613 feet, compared to 2,497 feet in the second quarter. In the third quarter we began to see improved performance due to shifting the focus of our drilling activities to areas that have been identified as better performing to date and where possible where we have 3-D data. As of September 30th we have acquired a total of approximately 320 square miles of 3-D in the play and expect to have approximately 450 square miles of 3-D seismic acquired by year-end.

We completed nearly all of our third quarter wells using slickwater stimulation and approximately 20% of the completions used open-hole packer systems. These wells have confirmed our analysis that indicated that both the slickwater and open-hole packer systems yield better performing wells.

We are also seeing better well results from drilling longer horizontal laterals. To date we have drilled and completed 24 slickwater wells with lateral lengths over 3,000 feet.

In our press release we provided an updated normalized average daily production for horizontal wells. In addition, we have provided a normalized average curve for the 24 wells with longer laterals. Based on our analysis and forecasts, we expect average gross estimated ultimate recovery from wells with greater than 3,000-foot laterals to range from 2 to 2.5 Bcfe per well.

Approximately 26 million cubic feet per day of our current production is from three of the company's easternmost pilot areas located in White County. Production increases in these three pilot areas alone account for approximately 28% of the 60 million cubic feet per day increase in gross operated production since the end of July.

Within the last 35 days we have placed 2 really good wells on production with production rates over 5 million cubic feet per day. The Poole 1-15 in our Sharkey pilot area was fracture stimulated using a slickwater fluid system along 2,949-feet of horizontal lateral section and was placed on production at a rate of 5.2 million cubic feet per day.

In the Featherston 1-22 well, also in Sharkey, fracture stimulated along an open-hole factor slickwater system 2,946-feet of lateral length and that was placed on production at a rate of 5.4 million cubic feet per day.

We plan to invest approximately $1 billion in the Fayetteville Shale project area during 2007, including our investments related to the gathering systems. This capital investment includes participating in approximately 400 horizontal wells in the play, of which approximately 70% are expected to be operated by us.

We also began investment in a demo project that we have near Southeast Rainbow in the third quarter and that project is designed to test longer laterals, concentrated well activity, multi-pad drilling and some efficiencies we can gain from our operations. And we'll report more on that as that unfolds in the fourth quarter and next year.

In our Arkoma Basin conventional projects we continue to have very positive results here, as Harold mentioned. We have invested approximately $126 million here, drilling 85 wells of which 65 were productive and 15 were still in progress at the end of the quarter.

We're continuing to put good wells on production at our Ranger Anticline and our Midway fields and as a result, production from those properties in the Basin was 6.3 Bcf for the quarter, up 26% from the third quarter of 2006.

In east Texas we continued our drilling programs with 3 rigs at Overton and 3 rigs in our other project areas. In the first nine months of 2007 we invested approximately $150 million drilling 35 wells at Overton and 21 wells in our Angelina River trend, 4 wells in our Jebel prospect and 4 in other areas. All of these wells were either productive or in progress at the end of the quarter. Production from east Texas was 7.6 Bcfe in the third quarter, compared to 8.2 last year.

To date we have now spudded 5 wells on our Jebel acreage block in Shelby County, Texas. 3 of these wells were drilled through the Travis Peak formation and 2 are horizontal wells targeting the James Lime Horizon. Of the 3 Travis Peak wells, 1 is currently on production and 2 are testing. Both of the James Lime wells offset some notable activity by other operators. Cabot Oil and Gas announced last week the Timberstar-Worsham well had been completed in the James Lime and was flowing to sales at a rate of 12.2 million cubic feet equivalent per day.

We hold a 21.5% working interest in that well and the Timberstar-Mills No. 1 which we operate with a 100% working interest is drilling and we expect to reach total depth during the fourth quarter. And pending results of both the Travis Peak and the James Lime wells there may be significant drilling for this area in 2008 and beyond.

On the new ventures front we are continuing to identify and pursue additional unconventional opportunities to add value. Yesterday we announced that we had leased approximately 70,000 net acres in Pennsylvania over the last year that we believe is prospective in the Devonian Age Marcellus Shale. We plan to drill our first test well in this exciting new play in early 2008.

In summary, we continue to be very encouraged by our success in our Fayetteville Shale project. It is advancing very well and hold tremendous potential to continue to organically increase our production and reserves at very meaningful rates. Our East Texas and conventional Arkoma Basin areas are also performing well, as we continue to identify additional opportunities to add value there.

Greg Kerley: Thank you, Richard, and good morning. Our earnings for the third quarter were $51 million or $0.30 a share, up 52% from the prior year. Our record financial results were driven primarily by the positive effect on our earnings of our significant growth in production volumes from the Fayetteville Shale play and higher realized natural gas prices, which were primarily the result of the positive effects of our hedging program.

Net cash provided by operating activities before changes in operating assets and liabilities increased 66% from the prior year to $157.7 million⁽¹⁾. We produced a record 30 Bcf in the third quarter and realized an average gas price of $6.66 an Mcf, which was up $0.43 from the prior year. Our commodity hedging program increased our average gas price during the quarter by about $1.17 per Mcf.

Our current hedge position, which consists of fixed price swaps and collars, provides us with support for a strong level of cash flow. For the remainder of the year, we have approximately 70 to 75% of our projected natural gas production hedged. We have 11.5 Bcf hedged with fixed price swaps at an average price of $8.09, and we have 10.5 Bcf hedged through price collars with an average floor price of $7.10 and an average ceiling price of $11.21.

We also have hedged 97 Bcf in 2008 and 72 Bcf in 2009 at attractive prices. Our detailed hedge position will be included in our Form 10-Q.

Our lease operating expenses per unit of production were $0.67 per Mcf during the third quarter, down slightly from last year, but almost now $0.15 lower than our previous guidance. Our LOE was lower than we expected, due in part to a decrease in cost of fuel gas for compression-related expenses, partially offset by increase in our gathering costs, both primarily related to our operations in the Fayetteville Shale play.

General and administrative expenses per unit of production were $0.46 an Mcf in the third quarter, down from $0.54 in the prior year. The decrease was primarily due to increased production volumes.

Taxes, other than income taxes per unit of production were $0.11 per Mcf during the third quarter, down from $0.32 in the prior year, due to a change in the mix of our production. Our full cost-full amortization rate was $2.56 per Mcf in the third quarter.

Our Midstream Services segment has installed over 230 miles of gathering system during the first nine months of the year and is currently gathering over 300 million cubic feet of gas per day from the Fayetteville Shale play.

Operating income for the segment was $4.1 million in the third quarter, up from $1.3 million in the same period a year ago. And the increase was primarily due to increased gas gathering revenues related to the Fayetteville Shale play.

Our natural gas distribution business realized a seasonal operating loss of $3.5 million in the third quarter, compared to a loss of $4.5 million during the same period last year. At September 30, we had total indebtedness of approximately $732 million, which included $594 million borrowed on our revolving credit facility, resulting in a capital structure of 31% debt and 69% equity.

On October 12, we amended our unsecured revolving credit facility and increased the borrowing capacity to $1 billion. This amount can be increased to $1.25 billion at any time upon our agreement with our existing banks or additional lenders. We plan to fund the remainder of our 2007 capital program with cash flow and debt borrowings and expect our long-term debt to total capitalization ratio to be approximately 36% at year-end.

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

Operator: Thank you, sir. (Operator Instructions.) And we will go first to Jeff Hayden at Pritchard Capital Partners.

Jeff Hayden: Real quick, just looking at some of those tests you guys put up in White County on the Sharkey pilot, I think before this the biggest well that you guys have had out in White County was on the Bull pilot. I think that was the Reaper 1-12. Can you give us a sense of the distance between that and some of the wells on the Sharkey pilot? And then, how many rigs do you guys have running in White County right now?

Richard Lane: Well, the distance--I don't know the exact distance of that. It's not too far. I'd say it's probably five to 10 miles north of the Reaper where these Sharkey wells that we've reported on. So basically they are both eastern-most pilot areas, if you will, and the Sharkey wells would be a little bit north of that Reaper well. And I'm not sure of the exact rig count. I think we have two or three of our rigs active over in that eastern area right now.

Robert Christensen: A question on the capital spend in the quarter. It was up about 30% sequentially. Any explanation for the real run up in capital spending? Just high levels of activity or what am I missing here?

Greg Kerley: The CapEx is, as we said in our press release, we're looking at--we probably are about $100, $110 million above our earlier projections for the full year. And that, obviously, is our run rate and our increased completion length. Some of that hit in the third quarter, and the fourth quarter will be--fill that gap. That basically is about $98 million of increase over the original projection to where the total E&P dollars invested this year we expect to be about $1.3 billion. And then, in the Midstream side we'll be up to about $100 million versus about $84, $85 originally projected there, just due to the increased pipe we're putting in the ground and with increased activity.

Robert Christensen: Okay, great. And a follow on. Regarding taxes, you said they're down to $0.11 an Mcf from 32 last year. I know you mentioned it's because of production mix. I wonder if you could elaborate on that a little bit. And do you expect it to stay there going forward?

Greg Kerley: Well, we had a couple of different things that helped us there. In the third quarter, we also had--in fact, for the nine months year-to-date we've had over $3 million of tax credits received from the State of Texas related to some changes in the law there. There was a cap--a $1 million cap on refunds. And so, those are--there's a big chunk of that that really related to 2006. So we have kind of a windfall that really helped our rate drive down and then just the changing mix of our production.

Tom Gardner: Just with respect to those 24 longer lateral wells, are those--have those been drilled sort of in a widely distributed pattern, or has it been concentrated in just various areas?

Richard Lane: It's pretty widespread. I think there's 10 different pilot areas that account for those 24 wells. So it's across the play pretty much.

Tom Gardner: Moving over to the Marcellus Shale, I just wanted to kind of get an idea of the competitive landscape and what might be your focus areas there. I have several questions along those lines, but I'll just let you tell me what you're going to tell me. And then, is your planned well next year likely to be horizontal or vertical?

Richard Lane: Well, I would say I probably won't tell you much more than what's in that press release for some obvious reasons--competitive reasons. We're active there. I think we'll start out with vertical pilot wells to gather data, and then likely move to some horizontal drilling.

Joe Allman: In terms of drilling the 3,000-plus-foot laterals, over what acreage--I know Richard just said that the 24 wells are across the play. But over what acreage do you think you will be drilling this kind of--these side laterals? Or could you talk about maybe what percentage of the acreage you think this kind of drilling would apply to? And also, what kind of spacing would you be thinking about you might ultimately get to in this play?

Richard Lane: Well, I think the acreage or the area where we would drill them, what we're seeing there, Joe, is that maybe we have better wells there that we can have higher EURs in, that would be--give us better economics. So we would--if that holds true, we would try to apply it to all the acreage we can. We don't see any kind of geographic bias for that, so we would try to approach the play as we have from the start with trying to improve the well results and how we're doing them. And I think it applies to the whole acreage. Obviously, we have some acreage that we've developed already and some spacing determinants made there. But I think it applies to the whole play.

And we have said that as time would move along we would begin to drill some longer laterals. There are interesting developments that generally take place as you think about the geometry of the wells that we're drilling. And it's a lot of detail to try to paint a word picture for you over the phone, but generally our--the orientation, the direction of our horizontals has been in a northwesterly direction. And units are spaced here on government sections. And so, that would allow you when you went in the first well in a section you might generally drill a shorter lateral, because you drill it near one of the corners. And then, later you would think in terms of drilling the longer laterals.

In this--what Richard mentioned earlier, this what we're calling internally here a demo project in Southeast Rainbow, we're taking basically a four-section part of our acreage - four government sections - and we're going to be using a slightly different orientation to our wells. We're going to be drilling--he mentioned drilling multiple wells off of a single pad. We will be drilling wells in a north/south orientation. If you think about one square mile and think about putting the surface location along, say, the northern border of the--of one square mile, and then drilling wells both north and south off of that, with an attempt to drill as long of laterals as possible, spacing them approximately--for this test the well bore is approximately 1,000 feet apart parallel to each other across that section. And then, ultimately having an eastwesterly well that would pick up reserves that otherwise wouldn't be drained along the northern section li ne.

So your question about spacing, we don't know the ultimate development spacing here. We've talked at times about 80-acre spacing, which would mean eight wells per section, thinking in terms of variable lateral lengths under the scenario of drilling wells in a northwesterly direction. However, if you began to do a geometry of drilling wells in north/south off of pad, and then picking up what wouldn't be drained during the turn part of the well that you would drill in an eastwesterly direction along the northern boundary, then--and 1,000 feet apart, you could think of, if you keep sequencing that across sections, that you would have maybe six wells per section, but they would have longer laterals. And with an assumption of 500-foot radius on fracturing, then you might be able to recover all of those reserves.

So we don't know that's the absolute answer, but we're going in with that kind of a test and we'll see what it shows us. And we're beginning that activity now. Locations are built. We're drilling wells. And that will all unfold now over the next basically six to eight to 10 months, a year, because it will take us that time to get all of this done.

The other things we'll be able to see in doing that are what are our costs are going to be when we get concentrated on development. And by the way, we haven't been concentrating on development. We've still got acreage to assess. So there's going to be a lot more interesting information come out. It might tell us that the 1,000-foot spacing between horizontals is too far and it might mean that ultimately we'd want tighter spacing.

It's a big project. We have a lot of work to do. But we think we're approaching it the right way with this particular test.

Joe Allman: That was a pretty good word picture, Harold. And I appreciate that. In terms of shallow conventional, could you talk--that play seems to be going pretty well. Could you talk about how extensive that play might be? And is that formation--is that--do you think it might be continuous across a lot of your acreage position?

Harold Korell: Well, Joe, the general packages are continuous across the acreage. The individual sands that we're finding are--there's for sure a stratographic component to them and they'll be variable across the acreage. I think the really good thing is that we've seen Atokan and Morrow sand production pretty much across the whole play. So we know it's not isolated to just one little part of our acreage there. And the other thing is that we've seen some really nice rates from those wells, at times unstimulated rates that are 3 and 4 million cubic feet per day.

So the jury is still out on how extensive it's going to be. The things that are pointing in a good direction is that we've found it over a pretty broad area. And we're just now really working that harder. I think 3D seismic will be a nice benefit for us there. And we're hopeful that we'll find some sizeable accumulation there.

Richard Lane: The good news about it is we get a look at it as we're drilling wells down to the Fayetteville. And so, if we find it, we can stop and complete it. The other beauty of it is that they are fairly inexpensive, about $600,000 or $700,000 a well. And they also help us earn acreage as we do those. And so, to the extent we can begin to map those, which we have an effort underway to map those, those can be very helpful in a number of ways - in earning acreage as well as in providing some very nice cash flow that is--that's a good thing.

Operator: (Operator Instructions.) And we will go next to Amir Arif with Friedman Billings Ramsey.

Amir Arif: Good morning, guys. Congratulations on a great quarter. Richard, I know you said you don't have much to say right now on the Marcellus Shale, but could you just give a sense of how many wells you're looking to drill in the first half?

Richard Lane: Amir, no, I don't really have a lot more to share with you there. It's going to really depend on the testing that we do in some of these first wells and gathering the real core data there for rock properties and all of that. And that will really determine those levels of activity.

Amir Arif: But you do plan to start drilling some wells in--is it Q1 '08 or are we just talking sometime early '08?

Richard Lane: Yes. I think we'll start permitting here before the end of the year and hopefully get them going early in '08. We've got some weather issues there to deal with as well.

Amir Arif: Okay. And second question, can you just update us on how you're progressing on your takeaway capacity?

Greg Kerley: Yes, Amir. This is Greg. Things are going really well there. As far as the Boardwalk pipeline, they submitted their FERC application. They have over half of their right-of-way purchased. They've actually got--have some delivery of pipe that's currently being coated, so we're real pleased. That's right on schedule where our anticipation was at this time. We also--just to remind you, there's the two other lines in the--the Ozark line has a capacity of 330 million a day. We hold about 225 million of firm on that line. And the CenterPoint line that runs along the south of the play has a capacity of about 250 million that--the firm on that is already subscribed to, but we can move gas to the ultimate end users on that also.

Harold Korell: If there are any Boardwalk listeners on the line, you guys keep the pressure on that project.

Brian Singer: Can you talk to where you think your drilling completion costs would be at a 3,000-foot lateral well in the Fayetteville? And then, where do you feel you are in terms of the maturity of that drilling and completion cost, i.e., to what extent is there room for that to come down?

Richard Lane: Yes, Brian. Well, I could tell you probably a good anchor number there is the 24 wells that we talked about that were greater than 3,000 feet that make up that production set. I think their average was $3.3 million per well. And we have a little more than half, probably 55, 60% of that is completion. In terms of where we are on the maturity of drilling costs and gaining efficiencies, I think a lot of that has to do with--or is controlled by what Harold talked about earlier. We really are not in the development phase yet. This demo project we'll start to do that. But because we are stepping out into a lot of new areas and have a lot of diverse conditions that we're having to deal with there, we're really not in a factory mode yet.

So we're not seeing--although we're seeing some efficiencies quarter-on-quarter like we reported, we're not really in that hard core development mode where we would expect that we would drive those costs down. I can't tell you how much they'll come down. I will say that in other projects where we defined the development mode, we've been able to do very well to drive those costs down.

Brian Singer: And in terms of spending, how do you think about that and how you balance that going forward? And how do you think about your financing options and balance sheet flexibility?

Harold Korell: Well, the first thing is, we don't use the term "spending," Brian. We always call it "investing." And I've said around here that we mash people's thumbs when they say it's spending. I know it's a word people use, but we think about it as investing. And--but Greg, I'll let you answer the question about that otherwise.

Greg Kerley: Yes, we had a grin on our face, all of us, because that's been an internal joke or whatever for years. But we think we're very well positioned, Brian, right now. We've talked about and we've given our guidance about where we are.

As far as the year, we were going to be clearly a user of our debt capacity this year and that's worked out. Our cash flow is running higher than our projections were as gas prices have been a little bit better, our hedges have been a little better for us, but our -- and our CapEx is up a little bit. But we'll be about exactly kind of where we projected at the beginning of the year. I mean, as we -- we haven't built our plan for 2008 right now. It's in the process. We were looking very hard at that, obviously, and -- but we still, even though our cash flow -- as productions grow over 50% this year and we'll have end of the year a real strong number and obviously have some strong numbers in 2008. We wouldn't anticipate that our cash flow quite equals our CapEx run. So we'll still be incurring some levels of debt, but still within a very reasonable capital structure.

Brian Singer: Great. Thank you for investing the time to answer the question.

Scott Hanold: You guys obviously in the past have talked about you're doing different things as far as drilling completion and it sounds like you're doing a demo where you do some pad drilling. Can you sort of talk about any efforts in trying the simul frac or have you tried that or do you expect to here over the next quarter?

Richard Lane: Yes. We have limited experiments with that. We've -- actually what we've done there is just a few wells and we really haven't -- it depends on what you call on simul frac. We've done kind of two wells back to back, but maybe not alternated the stages, so you were actually doing two wells at the same time and alternating the stages. There's been some of that work done in the industry and that's very interesting. And so we have some more of that to do. We don't really have much conclusive results to report on that, but we probably will continue to experiment with that.

Harold Korell: I think one of the constraints on us doing that is we haven't drilled a large number of wells that are like sitting side by side because -- and again that's because we're not down to that sort of spacing generally across the play because we still have our drilling rigs relatively more spread out. That's an open field I guess on that and I know there's been discussion internally that in the demo project that would afford us really our first opportunity to be able to gather that type of data in our area.

Richard Lane: We have to amass a lot of water in one place to really do that effectively and that's part of what we can do on this in more of a development mode.

Scott Hanold: Okay, fair enough. And with the Poole and the Featherston wells, I mean, what is your guys' sense on why those wells really work, or at least seem to work pretty good? I mean, is it the thickness out there or natural fracturing? I mean, do you guys have sort of a sense on what could have resulted in such strong rates?

Richard Lane: Right. I think the tangibles things you can point to is that when you compare it to the other wells nearby the lateral lengths were longer, I think 30 or 40% longer, and we pumped larger jobs. So those are the tangible things that impact rock contact and I think that has the most to do with it. Could we be encountering some -- a little more fractured rock, a little bit more of a sweet spot? Certainly that could be part of it, but the things you can put your arms around are the well design.

Scott Hanold: And you didn't have seismic covering that area, is that correct, at this time, 3-D?

David Heikkinen: Congratulations on all the hard work. I had a question, the recent wells in the PV -- in the Fayetteville, what's the PVI for the longer laterals?

Richard Lane: Well, I don't think we've -- we've really said on that. David, obviously, the -- we have projected a lot of those wells for the fourth quarter and going forward and we wouldn't be signing the AAPs and proving those if they weren't hitting our hurdle rate. So it's, not to be elusive, but the ultimates and the well costs are -- where they come down will really determine that, but our model of economics say that they hit our hurdle rates and then some.

David Heikkinen: So, easily greater than 1.3 is a good enough example. And the deep test in the Fayetteville on 3-D. Any thoughts of scheduling and any idea of prospectivity for drilling a deep test?

Richard Lane: The deep section there is, to me, is very intriguing. Coming up on the expiration side of the business, when I look at that -- look at the seismic and look at the style of the geology in the deep section, it's very, very interesting. We start to get some rotated faults with some reverse throw on them and things setting up for deeper carbonates to be just juxtaposed against source bed shales and very interesting looking geology. In terms of the timing, that will be -- those deep tests will really start in '08, early '08.

Harold Korell: The interesting thing about that, relative to where we'll be positioned today versus where the companies who were pursuing that back in the '70s is that their data sets were just so coarse. The seismic lines were maybe spaced ten miles apart and they had very little well control. And so the picture they were able to put together was a pretty gross one. They didn't have a lot of success. They did see gas shows in some of those prospective horizons. But with the 3-D that we'll have here, and then far more well data, albeit that initially it will be through the Fayetteville depths, we have a better chance certainly of putting together the geological picture down there. But it is exploration and it would be exploration and so it has all of the risks and uncertainties associated with it you would expect.

David Heikkinen: Sounds interesting. The -- just to make sure I'm visualizing that Southeast Rainbow, you're drilling six wells northeast, or north/south, and you'll drill one well at the heel and toe, so it's kind of eight wells per section is my mental picture.

Harold Korell: Well, if you started on the, in terms of trying to paint that picture, if you started on the west side with a well that would be drilled down the section line, and then there would be one, two, three, four, five across that, five more across that, so there would be six going north/south, and then there would be one across the north line and one across the south line. But if you start counting those successively one to another, you can't count all of those wells in each section. So it really becomes like six wells --

Harold Korell: -- that you would count on a continuum of that. It would be six wells per section. In other words, something in the 100-acre spacing range. So (inaudible).

David Heikkinen: (Inaudible) fine. That's the -- as you go section to section --

Richard Lane: And we haven't -- we really haven't seen -- at that spacing between wells, we really haven't seen any kind of classical sharing of reserves. On occasion, we've seen the frac job reach out and touch another well and interrupt its production, but then it gets back on its producing trend and -- so we're not seeing any -- although it's early, we're not seeing any real sharing reserves there. So I think that's part of why Harold mentioned that. The jury is still out on that spacing.

Harold Korell: Yes. What he's saying is you haven't seen any sharing of reserves. What that would mean is we haven't seen interference of one well on another's reserves. What that might lead you to believe is that you can drill more wells than that per section, but anyway we've got to start somewhere.

Another thing this kind of pattern does is it cleans up some of the questions that you would have of trying to drill the northwest diagonals across section line. It becomes a much cleaner thing. It's one of the wonders of Arkansas, is the spacing units in Arkansas are government sections. One square mile. It allows for this simplistic geometry versus what has to happen in some other states where you cobble together irregular patterns and then spacing really does start bouncing all over the place.

David Heikkinen: I hate to ask another question, and I'm breaking the rules. I saw a 200,000-acre fee land coming up from Anadarko. I know you guys did an early deal with Anadarko. Are you interested in adding more acreage with that type of blocks coming out and inner-spaced amongst your acreage?

Harold Korell: Well, generally things like acquiring and lease hold, we just don't talk about what our strategy is.

Gil Yang: I wanted to drill down a little bit into the better results. It sounds like there are a couple of things going on. One is longer laterals and maybe -- and then also bigger frac jobs. Can you maybe -- and then the third component would be the benefit of 3-D. Can you separate out the improving results into how much you think it's just longer laterals versus frac jobs versus avoiding problem areas?

Richard Lane: I think the overriding factor is the longer laterals. The larger -- that's the theme that runs through that body of wells we're talking about. The larger fracture stimulations have been mostly in the eastern end of the play, eastern part of the play, where we've -- looking at the thicknesses of the objectives and the boundary bed conditions and things, our engineers I think have pretty smartly figured out that -- how they can affect that, and that's where the longer, excuse me, the bigger fracture stimulations have been. And that area, we're seeing that that's, that's having a pretty good impact.

The larger fracture stimulations have been mostly in the eastern end of the play, eastern part of the play, where we've -- looking at the thicknesses of the objectives and the boundary bed conditions and things, you know, our engineers I think have pretty, pretty smartly figured out that -- how they can affect that, and that's where the longer, excuse me, the bigger fracture stimulations have been. And that area, we're seeing that that's, you know, that's having a pretty good impact.

Harold Korell: Well, some of you might remember that over there in that eastern side, in parts of it, it's quite thick, and some of our results we had reported earlier in past quarters weren't getting that good a wells relative to what you would think they should be based on the thickness. And one of our comments about that has been is maybe we didn't have our well bores placed appropriately or -- and, or we hadn't completely gotten in contact with all the rock there. So the bigger fracs, not only bigger fracs, when we say "bigger fracs," part of the detail of that is also pumping at higher rates which has something to do with a better sand transport when you're using slick water. So there may be some things happening there that are important to the equation also.

Now, we can't get away from this question that will, I know will continue to haunt us out there, and that might be that we may encounter areas of -- areas where we have better rock and then poorer rock. And we also encounter areas where we have some faults we frac into and result in some poorer wells. And if you look at that -- the curve, the graph that was put in the press release, there are a couple wells that were not such good wells that are responsible for that pretty low producing rate on the average normalized curve during the time period when they dominated the data set. So we've had some that haven't been quite as good, also.

Gil Yang: But has the 3D helped you avoid those, has -- have you seen experience that tells you that?

Richard Lane: Well, we think the 3D will help us, but we don't have 3D over there yet in that Sharkey area for example.

Richard Lane: You know, I think the numbers that I saw in some recent reviews were that when we're all done with '07 probably 15% to 20% of the wells we've drilled will actually have been able to utilize 3D, but next year we haven't firmed up our plan, but the way the seismic acquisition is going and where we'll likely be drilling that number will go way up, and so it will become a more important tool to our drilling.

Harold Korell: And Gil, yes, it does help us, where we have the structural picture, that certainly helps us where we can avoid faults and also avoid structural features that would help -- that help us keep our well bore, you know, within the Fayetteville section, and then beyond that there may be some additional help out of some of the attribute analysis that we do.

Gil Yang: Right. Just one quick question, my last quick question is 170 wells in progress now, can you just remind us how many were in progress last quarter and maybe a year ago?

Richard Lane: I don't have that at the top of my head, Gil, but we can take that question down and get it to you here later today.

David Tameron: Hi, good morning. A question for you, can you talk a little bit about the distribution of the wells across the Fayetteville? Is the stuff you're drilling is it following a bell curve or kind of what do the tails look like? Just what's the distribution as far as well rates and EURs?

Richard Lane: Well, it's -- I think we've talked about the -- when we talk about an average well, that certainly what gives rise to that average is that we have a pretty wide variance from less to -- less than a Bcf to well over 3 Bcf. And, you know, we look at that in terms of trying to figure out reserves and things, and it's kind of -- we're seeing kind of a lot more normal distribution of that.

Operator: And next to Joe Allman at J.P. Morgan.

Joe Allman: Hi, again, everybody. I'm trying to get an idea of how much acreage you're now focused on? I think you're trying to focus on the areas where you had the best results at this point? Could you kind of, could you comment on that, like how much of the, you know, how much of your drilling is going into the best areas? And those best areas at this point would be what percentage of your total acreage position?

Richard Lane: Well, I think that there's a balance there that we've talked about, Joe. You know, we can't concentrate all the rigs where we're seeing the very highest EUR. It's a program approach, but it also requires us to be able to plan long term and evaluate the acreage and to know what we have across the play and to hold the acreage that we're taking a little bit more risk in those areas and more exploratory in nature. So I think probably from a rig count, maybe a way to approach it is that probably 75% of our rigs are in more established areas right now.

Joe Allman: Okay. And any idea what percentage of your total acreage might be those more established areas?

Joe Allman: Okay. Got you. Okay. And then just in terms of financing, back to that issue, I mean do you guys expect that you might need to raise equity to fund the Fayetteville shale and maybe some, you know, who knows how the Marcellus shale is going to work out, and the other activity that you've got? And then just can you comment on that? And what about ramping up? I mean it seems to me that you might have some people constraints that are really preventing you from ramping up more than you otherwise would, could you comment on that, too?

Harold Korell: Yes, Joe, the basic question has a lot of moving parts to it. For example, as we think about 2008 commodity prices are very important. The other important element is at what pace do we decide to move ahead with activity levels in 2008. We can't really comment much on that right now because we're building that plan and we -- it's an iterative process, you know. We get the desires, I'd say, or the plans from the individual teams, we put them together, build it up to the total plan, and we look at what will our balance sheet look like under various scenarios. And we have to look at, you mentioned the people resource.

Now, many of you have heard me talk before about I for many years have viewed the oil, the E&P business as kind of a teeter-totter with the capital on one end of it and opportunities on the other end of it. And very seldom is a company ever completely in balance on that, and sometimes you have more opportunities than you have capital and you have to deal with the capital side of it. And for a lot of companies it's the other way around.

But really nowadays we are more like a three-bladed helicopter blade, capital on one blade, opportunities on the other, and the people and equipment resource on the third blade, and we have to try to keep all that in balance.

As we think about, generally about going forward here, the question is the pace of activity. You asked the pace question -- we can see with reasonable levels of capital expenditure in 2008 that we could end 2008 in a very comfortable debt-to-cap range, so we don't have to go do something. We would likely want to firm up some of our debt at some point along the way here, but if we want to go faster and as some of these things that we're working on, if they develop into bigger, bigger projects then, for example, don't talk a lot, people don't talk a lot about this right now because the Fed don't, but the activity we've had in Midway this year has cost us more capital because we've been so successful, you know, we build our plan on the basis of an assumed probability of success and then when we have total success then we set pacing in the wells and complete the wells, and it's a good news thing.

But when we sum all of it up, the activity levels are going to drive the answer to your question. The good thing that -- for us is we have a lot of options, we have a lot of optionality in regard to funding. You know, we could choose at some point in time to exit a business that we're in or an area that we're in that may be less of a focus for us. We've talked over time about the, not to say this is out there on the market, but we're, you know, as this Fayetteville unfolds with the large gathering system that we're building here we may have one of the largest gathering systems in the United States when all this is said and done. That's interesting.

So there are a lot of ways of dealing with this. The real question for us is if the Fayetteville Shale is as large as it appears that it is won't you go faster at some point in time? And the answer to that is that we would want to faster at some point in time, but we need to have our organizations built to where it has the capacity and the capability to go faster. We're not there right now.

Michael Scialla: Hi, guys. Actually, Joe just asked my question on the -- where you stood in the hiring process, but thanks, and great quarter.

Robert Christensen: Earlier in the Q&A I think David Heikkinen's question, you mentioned that you were I guess close to considering a deep test of what -- to the Arbuckle?

Richard Lane: Well, yes, we did mention that, Bob. We have exploratory work going on the -- on our vast acreage, besides just the Fayetteville work, and I think the section there that is prospective is immediately below the Mississippian section in the Siluro-Devonian rocks, and then on down really even into the older rocks, the Arbuckle could have potential, but we're more focused on those intermediate depth carbonates.

Robert Christensen: And do you think there's odds for such a wildcat in '08?

Harold Korell: Yes, we'll be likely testing some wildcats during '08 and hopefully early in '08.

Robert Christensen: If I can have my turn at the Marcellus, did you -- do you have a partner on your leasehold. I mean there's a number of operators up there that have drilled wells vertically from my understanding of it, did someone bring you in, or did you farm into somebody else's acreage, or is it 100% owned?

Richard Lane: I don't -- Bob, I understand the reason to want to know that. I don't think it's best for us to comment on that. We -- generally, we don't do a lot of following, though.

Scott Hanold: Hey, thanks. Hey, guys, one more question on drilling longer laterals, and I know there's been a lot of talk about where it could be drilled and what areas may be more prospective, but certainly looking at it a little different way, kind of, as you kind of look at your drilling say over the next say 6 to 12 months, you know, what would you guys sort of anticipate the percentage of the wells that you drill in the Fayetteville will be at length of 3,000 plus feet on the -- for the horizontal portion?

Richard Lane: I think the jury is out on that until we finish our plan, but a question, the top side question that we would have is if we're really getting higher EURs, which is what it looks like, and better economics why would we do anything but those. That would be the starting premise, and now there will be some reasons and some logistical things that come into play but we'll certainly push in that direction.

Joe Magner: Good morning. Just one more, in terms of average working interest or net revenue interest we can assume across the play, I think in October your net was about 75% of the total production, is that a reasonable number to use on future activity?

Joe Magner: Okay. And does it vary much across the area from areas where you're having a lot of success to some of the outlying pilots and will it shift much, or --?

Richard Lane: Well, that's a pretty complicated picture. I mean it varies by section, but geographically I wouldn't say that we have a fundamental change in interest levels.

Harold Korell: Yes, now, on the outside operated it -- of course, where Chesapeake is operating or XTO or someone else, then we may only have 5% or 10% on those, so the mix of our activity will dictate that to some extent so it depends on activity levels of those other companies, you know, in our total, but on our operated I think it's fairly consistent at this point.

Operator: And, gentlemen, that does conclude our Q&A session today. I would like to turn the conference back for any closing or additional comments you'd like to make.

Harold Korell: Well, thank all of you for joining us today. Clearly, we had a very good quarter to report here. As the kind of level of activity and our assessment part of our drilling here, you know, continues and as we're moving some of these, moving forward with, moving more towards a development, I guess I would say, and there'll be a lot of interesting things to unfold as I believe as we go on, forward on the demo project area. Thank you.

Operator: This does conclude today's conference. We do thank you very much for your participation. You may disconnect at this time.

(1) Net cash provided by operating activities before changes in operating assets and liabilities is a non-GAAP measure and is reconciled below. 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.


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

Exhibit Number		Description

99.1		Teleconference transcript for November 1, 2007 telephone conference call for investors and analysts.


	SOUTHWESTERN ENERGY COMPANY

Dated: November 1, 2007	By:	/s/ GREG D. KERLEY
	Name:	Greg D. Kerley
	Title:	Executive Vice President and
		Chief Financial Officer

Exhibit Number		Description

99.1		Teleconference transcript for November 1, 2007 telephone conference call for investors and analysts.

	3 Months Ended September 30,
	2007		2006
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	157,720	$	95,182
Add back (deduct):
Change in operating assets and liabilities		19,080		6,903
Net cash provided by operating activities	$	176,800	$	102,085

EXPLANATORY NOTE