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): November 1, 2007

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 November 1, 2007, at 10:00am Eastern, Southwestern Energy Company will host a telephone conference call for investors and analysts.  The prepared teleconference comments are furnished herewith as Exhibit 99.1.

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

Exhibit Number	Description
99.1	Prepared teleconference comments for November 1, 2007 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 1, 2007	By:	/s/    GREG D. KERLEY
	Name:	Greg D. Kerley
	Title:	Executive Vice President and
		Chief Financial Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Prepared teleconference comments for November 1, 2007 telephone conference call for investors and analysts.

EX-99

Southwestern Energy Third Quarter 2007 Earnings Teleconference

Speakers:

Harold Korell; President, Chairman and Chief Executive Officer

Richard Lane; Executive Vice President and President of the company's Exploration and Production business

Greg Kerley; Executive Vice President and Chief Financial Officer

Harold Korell - CEO, President, Chairman

Good morning, and thank you for joining us.  With me today are Richard Lane, the President of our Exploration and Production 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 big way, our 900,000 net acre position in the Fayetteville Shale.  

In our E&P business, the third quarter brought further positive developments in our key operating areas.  Our drilling activities in the conventional Arkoma program at the Ranger Anticline and at Midway are going extremely well - our production will grow there this year.  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 are building the database of production history on our wells and we are 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 fracture 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 - EVP and President of E&P Operations

Good morning.  During the 3rd quarter, our natural gas and crude oil production totaled 30.0 Bcfe, up 56% from the 19.3 Bcfe we produced in the 3rd quarter of 2006.  The increase was primarily due to growth from our Fayetteville Shale play, which produced 14.7 in the 3rd quarter of 2007, compared to 10.7 in the 2nd quarter of 2007 and 3.8 in the 3rd quarter of 2006.  

Due to our strong performance in the 3rd 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 the 476 wells, 287 were productive, 10 were dry, and 179 were in-progress on 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, 15 deep and 4 shallow rigs in the Fayetteville Shale Play, 6 rigs in East Texas, one rig in North Louisiana, one rig in the Permian Basin and 4 rigs in the conventional Arkoma Basin.

Fayetteville Shale Play

During the first nine months of 2007, we have invested approximately $731 MM in the Fayetteville Shale Play and have placed 187 wells on production.  Gross production from our operated wells has increased from approximately 100 Mmcfpd at the beginning of 2007 year to the current rate of 260 Mmcfpd.  Approximately 16 Mmcfpd of our current production is from eight wells producing from conventional reservoirs spread out over six pilot areas located in four counties. We expect to be producing approximately 300 Mmcfpd gross from our operated wells at the end of the year.

During the 3rd quarter, our time to drill to total depth averaged 16 days from re-entry to re-entry compared to a 2nd quarter average time of 18 days. Average completed well costs during the 3rd quarter were $3.0 million per well, slightly higher than the $2.9 million average cost for wells completed in the 2nd quarter due to drilling and completing wells with longer horizontal laterals and 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 3rd quarter wells averaged 2,613 feet compared to 2,497 feet in the 2nd quarter.  

In the 3rd quarter, we began to see improved performance due to shifting the focus of our drilling activity 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 data in the Fayetteville Shale area and expect to have approximately 450 square miles of 3-D seismic data by year-end. We completed nearly all of our 3rd quarter wells using slickwater stimulations and approximately 20% of the completions used open-hole packer systems.  These wells have confirmed our analysis that indicated that both the slickwater stimulations and the 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'. In our press release, we provided an updated normalized average daily production for horizontal wells completed with slickwater and/or crosslinked gel frac fluids.  In addition, we have provided a normalized average curve for the 24 wells with longer laterals.  Based on our analysis and forecast, we expect the average gross estimated ultimate recovery from wells with greater than 3,000' foot laterals to range from 2.0 to 2.5 Bcfe per well.

Approximately 26 MMcf per day of our current production is from three of the company's easternmost pilot areas (Sharkey, Hammerhead, and Mako) located in White County. Production increases in these three pilot areas alone account for approximately 28% of the 60 MMcf per day increase in gross operated production since the end of July. Within the last 35 days, we have placed two wells on production with initial production rates of over 5 MMcf per day. The Poole #1-15H well, located in our Sharkey pilot area and fracture stimulated using a slickwater fluid system in six stages along a 2,949 feet horizontal lateral section, was placed on production at a rate of 5.2 MMcf per day. The Featherston #1-22 well, also located in the Sharkey pilot area was fracture stimulated using an open-hole packer slickwater system in eight stages along a 2,946 feet long horizontal lateral section and placed on production at a rate of 5.4 MMcf per day.

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

Arkoma Basin Conventional

Moving on to our conventional Arkoma Basin properties, we continue to have very positive results here.  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 are continuing to put good wells on production at our Ranger Anticline and Midway areas.  As a result, production from the conventional Arkoma basin was 6.3 Bcf for the quarter, up 26% from the 3rd quarter of 2006.  

East Texas

In East Texas, we continued our active drilling programs with 3 rigs at Overton, and 3 rigs at our other East Texas areas.  In the first nine months of 2007, we invested approximately $150 million drilling 35 wells at Overton, 21 wells at Angelina River, four wells at our Jebel prospect, and four wells 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 3rd quarter, compared to 8.2 Bcfe last year.   

To date, we have now spudded 5 wells on our Jebel acreage block in Shelby County, Texas.  Three of these wells were drilled to the Travis Peak formation and two are horizontal wells targeting the James Lime horizon.  Of the three Travis Peak wells, one is currently on production and two are testing.  Both of the James Lime wells offset some notable activity by other operators.  As Cabot Oil & Gas announced last week, the Timberstar Worsham #1H well has been completed in the James Lime and is flowing to sales at a rate of 12.2 Mmcfe per day. We hold a 21.5% working interest in this well.  The Timberstar Mills #1H, which we operate with a 100% working interest, is drilling and we expect to reach total depth in the 4th quarter.  Pending the results of both the Travis Peak and James Lime wells, there may be significant drilling potential in this area for 2008 and beyond.

New Ventures

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.  

Summary

In summary, we continue to be very encouraged by our success in our Fayetteville Shale project.  It is advancing very well and holds 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.  

I will now turn it over to Greg Kerley who will discuss our financial results.

Greg Kerley - EVP and CFO

Thank you, Richard, and good morning.  Our earnings for the third quarter were $51 million, or $0.30 per 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 30.0 Bcfe in the third quarter, and realized an average gas price of $6.66 per Mcf, which was up $0.43 from the prior year.  Our commodity hedging program increased our average gas price during the quarter by $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 70-75% of our projected natural gas production hedged.  We have 11.5 Bcf hedged with fixed price swaps at an average price of $8.09 per Mcf 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 Mcfe during the third quarter, down slightly from $0.68 during the same period last year, but almost $0.15 lower than our previous guidance.  Our LOE was lower than we expected due to a decrease in the cost of fuel gas for compression-related expenses, partially offset by increases in gathering costs, both primarily related to our operations in the Fayetteville Shale play.  

General and administrative expenses per unit of production were $0.46 per Mcfe in the third quarter, down from $0.54 in the prior year period.  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 period.  Our full cost pool amortization rate was $2.56 per Mcfe 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 320 MMcf of gas per day from the Fayetteville Shale play area.  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.  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, 2007, we had total indebtedness of approximately $732 million (including $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 $1.0 billion. This amount can be increased to $1.25 billion at any time upon our agreement with our existing 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, so now we'll turn back to the operator who will explain the procedure for asking questions.

(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 liabiliti es with net cash provided by operating activities as derived from the company's financial information.

	3 Months Ended September 30,
	2007		2006
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