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 6, 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 Exhibit 99.1 attached hereto, shall not be deemed to be "filed" for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to the liabilities of that Section, and shall not be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

SECTION 7.  REGULATION FD

Item 7.01 Regulation FD Disclosure.

On November 6, 2007, Southwestern Energy Company (the "Company") made a presentation available to investors on the Company's website, http://www.swn.com.  The presentation included updated operating information relating to the Fayetteville Shale play and updated guidance regarding the Company's projected net income, operating income, earnings per share, net cash provided by operating activities before changes in operating assets and liabilities ("Net Cash Flow") and earnings before income taxes, depreciation, depletion and amortization ("EBITDA") for the fiscal year  2007.  Net Cash Flow and EBITDA are non-GAAP measures that are reconciled on pages 40 and 41 of the presentation. A copy of the presentation is furnished herewith as Exhibit 99.1.

All statements in the presentation, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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

Exhibit Number	Description
99.1	Transcript of slideshow accompanying the November 6, 2007 presentation.

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 6, 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	Transcript of slideshow accompanying the November 6, 2007 presentation.

EX-99

EXHIBIT 99.1

Slide Presentation dated November 6, 2007

The following slides will be presented to investors.

(Cover)
Southwestern Energy Company

November 2007 Update

NYSE: SWN

The left side of this slide contains a close-up picture of a leaf.  The caption above reads "Stimulating Growth."  The company's formula is located in the bottom-left corner.  The top-right corner of this slide contains the company logo.

(Slide 1)
Southwestern Energy Company (NYSE: SWN)

General Information

Southwestern Energy Company is an integrated natural gas company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production, natural gas gathering and marketing and natural gas distribution.

Market Data as of November 2, 2007

Shares of Common Stock Outstanding	170,229,759
Market Capitalization	$9,444,000,000
Institutional Ownership	92.6%
Management Ownership	5.1%
52-Week Price Range	$32.87 (1/3/07) - $55.48 (11/2/07)

Investor Contacts

Greg D. Kerley
Executive Vice President and Chief Financial Officer

Phone:	(281) 618-4803
Fax:	(281) 618-4820

Brad D. Sylvester, CFA
Manager, Investor Relations

Phone:	(281) 618-4897
Fax:	(281) 618-4820

(Slide 2)
Forward-Looking Statements

All statements, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The company has no obligation and makes no undertaking to publicly updat e or revise any forward-looking statements. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); the timing and extent of the company’s success in discovering, developing, producing and estimating reserv es; the economic viability of, and the company’s success in drilling, the company’s large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas plays; the company’s ability to fund the company’s planned capital investments; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services, including pressure pumping equipment and crews in the Arkoma Basin; the company’s future property acquisition or divestiture activities; the effects of weather; increased competition; the impact of federal, state and local government regulation; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets and changes in interest rates, and any other factors listed in th e reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise

The Securities and Exchange Commission has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible,” and “non-proven” reserves, reserve “potential” or “upside” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company.

(Slide 3)
About Southwestern

* Focused on domestic exploration and production of natural gas.
	* 1,026 Bcfe of reserves; 95% natural gas; 14.2 R/P at year-end 2006.
* E&P strategy built on organic growth through the drillbit.
	* Over 80% of planned E&P capital allocated to drilling in 2007.
* Track record of adding significant reserves at low costs.
	* From 1999 through 2006, we've averaged annual production growth of 12%, reserve growth of 16%, 297% reserve replacement, and F&D cost of $1.73 per Mcfe.
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to approximately $9 billion today.
* Strategy built on the Formula:
	The Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value+.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 4)
Recent Developments

*  First Nine Months of 2007 Highlights
	*  Production of 78.7 Bcfe (up 53%); 2007 production projected at 111 Bcfe (up 54%).
	*  Discretionary cash flow of $446.9 million, up 47% from the prior year period.
	*  Capital investments of $1.1 billion, up 80% from the prior year period.

* Operations Update
	* East Texas and Ranger Anticline development programs delivering high-return growth.
	* Fayetteville Shale - progress in horizontal drilling and confirmation of play.
		* Through September 30, 2007, 392 wells were completed, including 290 SW/XL horizontal wells.
		* Gross operated production from Fayetteville Shale project increased to approximately 260 MMcf per day at October 22, 2007, compared to approximately 70 MMcf the same time a year ago.

Notes:    Discretionary cash flow is net cash flow before changes in operating assets and liabilities. Discretionary cash flow is a non-GAAP financial measure (see explanation and reconciliation on page 40).

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 5)
Proven Track Record

This slide contains bar charts for the periods ended December 31.

	1999	2000	2001	2002	2003	2004	2005	2006	2007E
Production (Bcfe)	33	36	40	40	41	54	61	72	111E
Reserve Replacement	150%	196%	224%	209%	351%	388%	450%	505%
EBITDA ($MM)(1)	$75	$104	$134	$99	$151	$255	$346	$415
F&D Cost ($/Mcfe)	$1.20	$0.99	$1.11	$1.02	$1.18	$1.34	$1.51	$2.10

Note: Reserve data excludes reserve revisions and capital investments in drilling rigs.

(1)    EBITDA is a non-GAAP financial measure. See explanation and reconciliation of EBITDA on page 41.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 6)
About the Company

This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and New Mexico with shadings to denote the Arkoma and Permian Basins, the Gulf Coast and the East Texas regions. Lines trace gas distribution pipelines.

Exploration and Production Segment

* 2006: 1,026 Bcfe of Reserves
	95% Natural Gas
	Production: 72.3 Bcfe
* 2007 Est. Production: 111 Bcfe

Arkoma

* Reserves - 577 Bcf (56%)

* Production - 31.9 Bcf (44%)

East Texas

* Reserves - 383 Bcfe (37%)

* Production - 32.0 Bcfe (44%)

Gulf Coast

* Reserves - 15 Bcfe (2%)

* Production - 2.6 Bcfe (4%)

Permian

* Reserves - 51 Bcfe (5%)

* Production - 5.8 Bcfe (8%)

Gas Distribution Segment

* 151,000 customers in North Arkansas

* Service area includes 6th fastest growing region in U.S. and the Milken Institute's 8th "Best Performing City"

* Southwestern operates in Arkansas, Texas, New Mexico, Oklahoma and Louisiana and has three segments: E&P, Midstream Services and Gas Distribution.

* E&P generates approximately 95% of operating income and EBITDA.

* Midstream Services and Gas Distribution segments provide operating synergies for the E&P business in addition to contributing to the stability of our cash flow.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 7)
Capital Investments

This slide contains a bar chart of company capital investments, summarized as follows:

					2007
	2003	2004	2005	2006	Plan
	(in millions)
Utility & Other	$9.3	$13.0	$15.9	$32.7	$19.0
Property Acquisitions	$ -	$14.2	$ -	$18.0	$ -
Cap. Exp. & Other	$12.4	$17.9	$32.4	$62.0	$78.0
Leasehold & Seismic	$19.0	$21.1	$60.6	$70.0	$140.0
Development Drilling	$119.7	$208.7	$287.6	$421.4	$1,034.0
Exploration Drilling	$19.8	$20.1	$35.6	$196.0	$83.0
Midstream Services	$0.0	$0.0	$15.8	$48.7	$101.0
Rig Commitment	$0.0	$0.0	$35.2	$93.6	$ -
Total	$180.2	$295.0	$483.1	$942.4	$1,455.0

This slide also contains a pie chart of the company's preliminary planned 2007 capital investments by area of operation, summarized as follows:

	% of Total
	Capital Investments
Arkoma Fayetteville Shale	64%
East Texas	13%
Arkoma	10%
Midstream	7%
Other E&P	3%
Permian/Gulf Coast	2%
Utility	1%

* E&P capital program heavily weighted to the Fayetteville Shale play in 2007.

* Over 80% of E&P capital is allocated to drilling in 2007.

* Plan to invest approximately $1 billion in the Fayetteville Shale play in 2007.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 8)

East Texas

This slide contains a map of several counties in East Texas.  The company's Overton and Angelina River Trend acreage positions are highlighted.  The East Texas Salt Basin is also denoted on the map.  The cities of Tyler and Lufkin, Texas are displayed as reference points.

East Texas Activity:		Annual	Year-End
	Well	Production	Reserves
	Count	(Bcfe)	(Bcfe)
Original Wells (acquired)	16	0.3	22
2001 - 2002 Development	33	8.2	111
2003 Development	57	13.6	196
2004 Development	84	22.2	299
2005 Development	88	28.2	369
2006 Development	78	32.0	383
Planned 2007 Development	80	27 - 29

* Entered area in 2000 with purchase of 10,800 acres at Overton for $6.1 million.

* Current acreage position of 24,400 gross acres at Overton and 80,000 gross acres at Angelina.

* Drilled 354 wells at Overton from 2001 to September 30, 2007, with 100% success.

* Plan to drill 43 wells at Overton and 33 wells at Angelina in 2007.

* Potential for future development program at Angelina.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 9)

Arkoma Basin - Conventional

This slide contains a map of Arkansas and Oklahoma with shading to denote the Arkoma Basin. The Ranger Anticline, the Midway Exploration and the area known as the Fairway are further noted. 

* 60+ years of experience in the basin, large acreage position of 460,000 net acres.

* 2007 capital program includes drilling 100 - 110 wells, including 50 - 60 wells in the company's growing Ranger Anticline area.

Arkoma Basin 2004-2006 Avg Results:⁽¹⁾

Reserve Replacement:	205%
LOE Cost (incl. Taxes) ($/Mcf):	$0.60
F&D Cost ($/Mcf):	$1.74

Ranger Anticline (inception thru 12/31/06):⁽¹⁾

Success:	104/118
Net EUR:	95.7 Bcf
F&D/Mcf:	$1.52

(1) Including reserve revisions.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 10)
Ranger Anticline

This slide contains a map of the Ranger Anticline prospect with the company's exploratory and held by production acreage designated with shading.  Also shown are SWN's producing wells at 12/31/06 and 2007 proposed wells. A box denotes the successful extension wells.

Ranger Anticline (inception thru 12/31/06):⁽¹⁾

Success:	104/118
Net EUR:	95.7 Bcf
F&D/Mcf:	$1.52

* Current acreage position of 16,000 gross dev. acres and 58,000 gross undev. acres.

* Average working interest 50% - 100%.

* Plan to drill up to 60 wells in 2007.

* Area has significant potential growth/inventory.

* 2006 exploration success at Midway prospect, approx. 10 miles north of Ranger, also holds significant potential.

Ranger Anticline Potential:		Reserve
	Well	Adds
	Count	(Net Bcfe)
Successful Wells at 12/31/02	13	12
Successful Wells in 2003	10	8
Successful Wells in 2004	20	25
Successful Wells in 2005	34	17
Successful Wells in 2006	27	34
Planned 2007 Drilling Program	60
Future Potential Locations	~150

(1) Including reserve revisions.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 11)

Fayetteville Shale Play

This slide contains a map of Oklahoma, Arkansas and portions of Louisiana and Texas.  A box denotes SWN's Fayetteville Shale position in the Arkoma Basin. The Barnett Shale in the Fort Worth Basin, the Wedington Incongruity as well as the Llano Uplift and Sabine Uplift are also denoted. The Arbuckle and Ouachita mountains are shown as reference points.

* Mississippian-age shale, geological equivalent of the Barnett Shale in north Texas.

* Within the SWN play area, the shale appears to be laterally extensive across several counties in Arkansas, ranging in thickness from 50 to 550 feet and depths from 1,500 to 6,500 feet.

* SWN currently holds approximately 902,000 net acres in the Fayetteville Shale play area (equivalent to approximately 1,400 square miles).

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 12)
Fayetteville Shale Focus Area

This slide contains a map of the Fayetteville Shale Focus Area in Arkansas.  Existing pilot areas and portions of the conventional fairway are indicated. 777,000 net acres and 125,000 net acres HBP are outlined on the map. A box denotes Conventional Production (16 MMcf/d). The Scotland Field, Gravel Hill Field, Griffin Mountain Field, Cove Creek Field, New Quitman Field, Chattanooga Test, Ranger Anticline and Moorefield Test are also designated.  The Moorefield Prospective Area is outlined.

* As of September 30, 2007, SWN has drilled and completed 392 wells, of which 290 are horizontal SW/XL wells, in 35 separate pilot areas in 8 counties. We have also produced gas from the deeper Moorefield and Chattanooga Shales and from conventional production in six pilot areas.

* We anticipate participating in 400 horizontal wells in 2007, approximately 70% of which we would operate.

* Assuming development of 50% of the acreage within the shaded areas at 80-acre spacing and average ultimate production of 1.4 Bcf gross per well, the potential exists for 8,000 horizontal wells and approximately 11 Tcf gross ultimate recovery.

Note: Data as of September 30, 2007.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 13)

Horizontal SW/XL Well Results - From Inception

This slide contains a map of the Fayetteville Shale Play where pilot areas are highlighted with circles and categorized as First 30 Day average rate (Pilots with 2 or more wells), Initial test rate only and Conventional Production.  The Moorefield Prospective Area is outlined.

* Gravel Hill

    Average: 1,856 Mcfpd

    Range: 361 - 3,868 Mcfpd

    53 wells

* East Cutthroat

    Average: 489 Mcfpd

    Range: 179 - 991 Mcfpd

    8 wells

* Scotland

    Average: 1,154 Mcfpd

    Range: 370 - 2,531 Mcfpd

    19 wells

* Steelhead

    Average: 1,361 Mcfpd

    Range: 648 - 1,797 Mcfpd

    14 wells

* Southeast Rainbow

    Average: 1,084 Mcfpd

    Range: 313 - 2,168 Mcfpd

    17 wells

* SW Greer Lake

    Average: 2,515 Mcfpd

    Range: 1,818 - 3,055 Mcfpd

    5 wells

* Yellowstone

    Average: 1,098 Mcfpd

    Range: 345 - 1,551 Mcfpd

    7 wells

* Midge

    Average: 633 Mcfpd

    Range: 341 - 858 Mcfpd

    6 wells

* Mako

    Average: 837 Mcfpd

    Range: 468 - 1,748 Mcfpd

    4 wells

* Hammerhead

    Average: 932 Mcfpd

    Range: 203 - 1,660 Mcfpd

    2 wells

* Nemo

    Average: 537 Mcfpd

    Range: 419 - 654 Mcfpd

    2 wells

* Griffin Mountain

    Average: 830 Mcfpd

    Range: 322 - 1,628 Mcfpd

    27 wells

* South Brownie

    Average: 673 Mcfpd

    Range: 560 - 786 Mcfpd

    2 wells

* South Rainbow

    Average: 2,021 Mcfpd

    Range: 623 - 3,849 Mcfpd

    18 wells

* Cove Creek

    Average: 1,207 Mcfpd

    Range: 271 - 2,768 Mcfpd

    37 wells

* Caddis

    Average: 552 Mcfpd

    Range: 203 - 975 Mcfpd

    3 wells

* New Quitman

    Average: 857 Mcfpd

    Range: 280 - 1,780 Mcfpd

    22 wells

* Sharkey

    Average: 1,062 Mcfpd

    Range: 735 - 1,617 Mcfpd

    12 wells

* Matthis Hollow

    Avg. Test: 1,122 Mcfpd

* Phillips Mountain

    Test: 3,128 Mcfpd

* Sturgeon

    Test: 868 Mcfpd

* North Yellowstone

    Avg. Test: 1,049 Mcfpd

* West Cutthroat

    Avg. Test: 1,260 Mcfpd

* North Charley

    Avg. Test: 469 Mcfpd

* Charley

    Avg. Test: 575 Mcfpd

* Stonefly

    Avg. Test: 362 Mcfpd

* Bull

    Test: 4,029 Mcfpd

* Tiger

    Avg. Test: 1,892 Mcfpd

Notes: Data as of September 30, 2007. Each circle has been scaled to size to reflect the relative position of the rate compared to the others shown.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 14)

Horizontal SW/XL Well Results - 3Q 2007

This slide contains a map of the Fayetteville Shale Play where pilot areas are highlighted with circles and categorized as First 30 Day average rate (Pilots with 2 or more wells), Initial test rate only and Conventional Production.  The Moorefield Prospective Area is outlined.

* Gravel Hill

    Average: 1,985 Mcfpd

    Range: 735 - 3,111 Mcfpd

    13 wells

* Scotland

    Average: 1,729 Mcfpd

    Range: 1,378 - 2,081 Mcfpd

    2 wells

* Steelhead

    Average: 1,342 Mcfpd

    Range: 1,144 - 1,540 Mcfpd

    2 wells

* Southeast Rainbow

    Average: 1,242 Mcfpd

    Range: 1,214 - 1,271 Mcfpd

    2 wells

* SW Greer Lake

    Average: 2,720 Mcfpd

    Range: 2,352 - 3,055 Mcfpd

    3 wells

* Yellowstone

    Average: 1,145 Mcfpd

    Range: 345 - 1,551 Mcfpd

    5 wells

* Mako

    Average: 515 Mcfpd

    Range: 468 - 562 Mcfpd

    2 wells

* Hammerhead

    Average: 932 Mcfpd

    Range: 203 - 1,660 Mcfpd

    2 wells

* Griffin Mountain

    Average: 962 Mcfpd

    Range: 322 - 1,628 Mcfpd

    4 wells

* South Rainbow

    Average: 2,341 Mcfpd

    Range: 922 - 3,761 Mcfpd

    2 wells

* Cove Creek

    Average: 2,207 Mcfpd

    Range: 1,506 - 2,768 Mcfpd

    4 wells

* Caddis

    Average: 589 Mcfpd

    Range: 203 - 975 Mcfpd

    2 wells

* Sharkey

    Average: 1,105 Mcfpd

    Range: 825 - 1,617 Mcfpd

    6 wells

* Mathis Hollow

    Test: 1,571 Mcfpd

* Phillips Mountain

    Test: 3,128 Mcfpd

* New Quitman

    Test: 3,491 Mcfpd

* Midge

    Test: 1,219 Mcfpd

* Bull

    Test: 4,029 Mcfpd

* Tiger

    Avg. Test: 1,892 Mcfpd

Notes: Data as of September 30, 2007. Each circle has been scaled to size to reflect the relative position of the rate compared to the others shown.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 15)
Fayetteville Project - Gross Production

This line graph shows gross production in MMcf/d for the Fayetteville Shale from January 2006 to October 22, 2007. Gross operated production of approximately 260 MMcf/d as of October 22, 2007.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 16)
Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through September 30, 2007, for the company's horizontal wells drilled.  This graph displays a composite curve of the SW/XL normalized production from the company's horizontal wells excluding mechanical issues.  The production data is compared to 2.0 Bcf, 1.5 Bcf and 1.3 Bcf SW/XL typecurves from the company's reservoir simulation shale gas model.  Composite curves are also shown for Gravel Hill production excluding mechanical issues and East Cutthroat production excluding mechanical issues. Well counts and respective days of production are also displayed, as follows:

Days of Production	Total Well Count	Gravel Hill Well Count	East Cutthroat Well Count
	(as of September 30, 2007)
30	253	47	8
60	225	36	8
90	201	33	8
120	186	30	8
150	168	28	8
180	150	27	4
210	127	24	3
240	104	23	1
270	93	22	1
300	72	18	0
330	58	17	0
360	47	16	0
390	40	15	0
420	32	15	0
450	23	13	0
480	14	7	0
510	8	2	0
540	4	2	0
570	2	2	0
600	1	1	0
630	1	1	0
660	1	1	0
690	1	1	0
718	1	1	0

Notes: Data as of September 30, 2007.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 17)
Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through September 30, 2007, for the company's horizontal wells drilled.  This graph displays two composite curves, one showing the SW/XL normalized production from the company's horizontal wells excluding mechanical issues and another showing the SW normalized production from the company's horizontal wells with laterals greater than 3,000 feet excluding mechanical issues. The production data is compared to 2.0 Bcf, 1.5 Bcf and 1.3 Bcf SW/XL typecurves from the company's reservoir simulation shale gas model.  Well counts and respective days of production are also displayed, as follows:

Days of Production	Total Well Count	SW Horizontal Wells with Laterals > 3,000 Feet
	(as of September 30, 2007)
30	253	19
60	225	12
90	201	5
120	186	3
150	168	2
180	150	1
210	127	1
240	104	1
270	93	1
300	72	1
330	58	1
360	47	1
390	40	1
420	32	1
450	23	1
480	14	0
510	8	0
540	4	0
570	2	0
600	1	0
630	1	0
660	1	0
690	1	0
718	1	0

Notes: Data as of September 30, 2007.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 18)
Outlook for 2007

* Production target of 111 Bcfe in 2007 (estimated growth of 54%).

	2006	2007 Guidance
	Actual	NYMEX Price Assumptions
	$7.23 Gas	$7.00 Gas
	$64.74 Oil	$70.00 Oil
Net Income	$162.6 MM	$200 - $205 MM
EPS	$0.95	$1.16 - $1.19
Operating Income	$246.3 MM	$355 - $360 MM
Net Cash Flow(1)	$413.5 MM	$610 - $620 MM
EBITDA(1)	$414.5 MM	$630 - $640 MM
CapEx	$942.4 MM	$1,455 MM

Note:   Guidance updated as of October 31, 2007.  2006 oil and gas prices include actual last-day NYMEX closing prices.

(1)        Net cash flow is net cash flow before changes in operating assets and liabilities.  Net cash flow and EBITDA are non-GAAP financial measures.  See explanation and reconciliation of non-GAAP financial measures on pages 40 and 41.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 19)
The Road to V⁺

* Invest in the Highest PVI Projects.
	* Continue Development of East Texas and the Ranger Anticline.
* Accelerate Development of the Fayetteville Shale Play.
* Deliver the Numbers.
	* Production and Reserve Growth.
	* Maximize Cash Flow.
* Continue to Tell Our Story.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 20)
Appendix

(Slide 21)
Financial & Operational Summary

This slide contains a table that summarizes the company's financial and operational indicators.

	Nine Months Ended September 30,		Year ended December 31,
	2007	2006	2006	2005	2004
	($ in millions, except per share amounts)
Revenues	$852.4	$549.1	$763.1	$676.3	$477.1
EBITDA (1)	459.0	309.2	414.5	345.9	255.3
Net Income	149.5	128.9	162.6	147.8	103.6
Net Cash Flow (1)	446.9	304.8	413.5	321.8	237.7
Diluted EPS (2)	$0.87	$0.75	$0.95	$0.95	$0.70
Diluted CFPS (2)	$2.59	$1.78	$2.41	$2.06	$1.61
Production (Bcfe)	78.7	51.6	72.3	61.0	54.1
Avg. Gas Price ($/Mcf)	$6.75	$6.73	$6.55	$6.51	$5.21
Avg. Oil Price ($/Bbl)	$62.58	$60.24	$58.36	$42.62	$31.47
Finding Cost ($/Mcfe) (3)			$2.10	$1.51	$1.34
Reserve Replacement (%) (3)			505%	450%	388%

(1)    Net cash flow is net cash flow before changes in operating assets and liabilities.  Net cash flow and EBITDA are non-GAAP financial measures.  See explanation and reconciliation of non-GAAP financial measures on pages 40 and 41.

(2)    Diluted earnings per share and diluted cash flow per share have been adjusted to give effect to the two 2-for-1 stock splits during 2005.

(3)    Excluding reserve revisions and capital investments in drilling rigs.

(Slide 22)
Gas Hedges in Place Through 2009

This slide contains a bar chart detailing gas hedges in place by quarter for year 2007, year 2008 and year 2009.  A summary of these outstanding gas hedges is as follows:

			Average Price per Mcf	Percent
	Type	Hedged Volumes	(or Floor/Ceiling)	Hedged
2007	Swaps	43.5 Bcf	$7.81	41%
	Collars	36.0 Bcf	$6.99 / $12.21	34%
2008	Swaps	49.0 Bcf	$8.26	-
	Collars	48.0 Bcf	$7.92 / $11.60	-
2009	Swaps	50.0 Bcf	$8.20	-
	Collars	22.0 Bcf	$8.07 / $10.94	-

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 23)

SWN is One of the Lowest Cost Operators

This slide contains a bar graph that compares SWN to its competitors in terms of lifting cost per Mcfe of production (3 year average).

	Lifting Cost per Mcfe
	of Production
	(3 year average)
Southwestern Energy Company	$0.83
EOG Resources, Inc.	$1.04
Noble Energy	$1.04
Chesapeake Energy	$1.06
EnCana	$1.07
Pioneer Natural Resources	$1.09
Newfield Exploration	$1.10
Range Resources	$1.13
Ultra Petroleum	$1.16
Cabot Oil & Gas	$1.18
Devon Energy	$1.28
Anadarko Petroleum	$1.33
XTO Energy	$1.41
Apache	$1.49
Pogo Producing	$1.50
Cimarex Energy	$1.52
Swift Energy	$1.54
Forest Oil	$1.56
St. Mary Land & Exploration	$1.62
Quicksilver Resources	$1.67
Denbury Resources	$2.04

This slide also contains a bar graph comparing SWN to its competitors in terms of drillbit F&D cost per Mcfe (3 year average).

	Drillbit F&D Cost
	per Mcfe
	(3 year average)
Ultra Petroleum	$0.52
Quicksilver Resources	$1.00
XTO Energy	$1.35
Southwestern Energy Company	$1.69
Range Resources	$1.77
Cabot Oil & Gas	$1.82
EOG Resources, Inc.	$1.90
EnCana	$1.93
Apache	$2.02
Devon Energy	$2.05
Denbury Resources	$2.31
Noble Energy	$2.89
St. Mary Land & Exploration	$3.22
Newfield Exploration	$3.29
Anadarko Petroleum	$4.29
Pioneer Natural Resources	$4.47
Cimarex Energy	$4.48
Forest Oil	$4.58
Chesapeake Energy	$4.58
Swift Energy	$7.18
Pogo Producing Co.	$7.34

Source:  John S. Herold Database

Note:  All data as of December 31, 2004, 2005 and 2006.

(Slide 24)

Fayetteville Shale Activity Compared to the Barnett

This slide contains bar charts displaying the number of wells drilled in the Barnett Shale Play and the Fayetteville Shale Play, summarized as follows:

Barnett Shale Play

*1981 – 1^st Well Drilled

*1992 – 1^st Horizontal Well Drilled

*1997 – 1^st Slickwater Frac

1981-1989	Avg. 7 Wells/Year
1990-1994	Avg. 40 Wells/Year
1995-1999	Avg. 73 Wells/Year
2000	Vertical Wells Drilled Horizontal Wells Drilled	186 2
2001	Vertical Wells Drilled Horizontal Wells Drilled	501 3
2002	Vertical Wells Drilled Horizontal Wells Drilled	785 5
2003	Vertical Wells Drilled Horizontal Wells Drilled	872 75
2004	Vertical Wells Drilled Horizontal Wells Drilled	566 278
2005	Vertical Wells Drilled Horizontal Wells Drilled	322 613
2006E	Vertical Wells Drilled Horizontal Wells Drilled	200 1100
2007E	Vertical Wells Drilled Horizontal Wells Drilled	250 1500

Fayetteville Shale Play

*Q2 2004 – 1^st Well Drilled

*Q1 2005 – 1^st Horizontal Well Drilled

*Q3 2005 – 1^st Slickwater Frac

2004	Vertical Wells Drilled Horizontal Wells Drilled	21 0
2005	Vertical Wells Drilled Horizontal Wells Drilled	30 37
2006	Vertical Wells Drilled Horizontal Wells Drilled	7 189
2007E	Vertical Wells Drilled Horizontal Wells Drilled	0 ~400

Source: Republic Energy Co., Tudor, Pickering & Co. Securities, Inc.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 25)

Fayetteville Shale Production Compared to the Barnett

The graph contained in this slide displays production volumes in MMcf/d for the Fayetteville Shale over a 2-year period and the Barnett Shale over an 18-year period, which are the respective time periods in which each shale play reached 120 MMcf/d in production.

A box accompanying the graph states:

We collapsed the “learning curve” dramatically; Paradigm shift in gas prices

Source: Tudor, Pickering & Co. Securities, Inc.

(Slide 26)

East Texas - Overton Field

This slide contains a map of Smith County, Texas, where the Overton Field is located.  Existing wells at year-end 2005 and development well locations for 2006 and 2007 are denoted.  It is stated that the Overton Field contains 17,600 acres and the South Overton Farm-in Acreage contains 6,800 acres.

* Purchased original 10,800 acres and 16 producing wells for $6.1 million in 2000 (developed at 640-acre spacing).

* Drilled 354 wells from 2001 to September 30, 2007, with 100% success.

* Plan to drill 43 wells in 2007, a portion of which will be at 40-acre spacing.

Overton Field Reserve Potential:		Approx.	Reserve
	Well	Spacing	Adds(1)
	Count	(Acres)	(Net Bcfe)
Original Wells	16	640	21
2001 - 2002 Development	33	365	66
2003 Development	57	170	70
2004 Development	83	100	123
2005 Development	80	70	106
2006 Development	66	60	87
Planned 2007 Development	43	60

Overton Field 2004-2006 Avg Results:⁽²⁾

Reserve Replacement:	297%
LOE Cost (incl. Taxes) ($/Mcfe):	$0.57
F&D Cost ($/Mcfe):	$1.98

⁽¹⁾Excluding reserve revisions.

⁽²⁾Including reserve revisions.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 27)
Overton Field Gross Production

The graph contained on this slide displays the Overton Field gross production rate (MMcfe/d) from June 2000 to December 2006. Additionally, in early 2003, the graph indicates the projected production profile from an accelerated drilling program as a result of our 2003 equity offering. In 2004, the graph indicates addition of a fifth rig and curtailment issues.

Overton Net Production:

	Bcfe
2000	0.3
2001	2.3
2002	5.9
2003	13.6
2004	21.8
2005	26.7
2006	29.8

(Slide 28)
Overton Field - Improved Drilling Results

This slide of drilling days versus depth portrays the improved drilling rate in the Overton Field since its purchase from Fina in 2001.  Fina's average drilling rate was 55 days.  Upon the Field's purchase in 2001 SWN decreased that rate to 35 days.  It was further decreased to 27 days in 2002, 23 days in 2003, 19 days in 2004, 18 days in 2005 and 17 days in 2006.

* Reduced drilling time by >50%.

* Increased initial production by 200%.

* Increased gross reserves by 60% (avg. gross EUR of 1.6 Bcfe per well in 2006)

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 29)

The Energy Balance Today

* Oil and gas prices have risen substantially since 2002.

* World demand for hydrocarbons has increased dramatically (China, India, etc.) and supply/demand relationship is tight.

* Resource nationalism is a reality.

* A serious challenge exists to meet demand growth for hydrocarbons (oil and gas).

* There are no "silver bullet" technologies today to replace hydrocarbons.

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 30)

U.S. Oil Consumption and Sources

This slide displays U.S. oil production versus U.S. oil consumption in thousands of barrels per year from 1981 to present. Net imports for the same period are also given.  Imports represent 66% of total US consumption.

Source:  EIA

(Slide 31)

West Texas Intermediate Oil Prices

This line graph shows the price of West Texas Intermediate oil in $/Bbl for the years 2000 to present noting a compound average growth rate of 28% from 2002 to 2007.  It is also noted, however, finding costs for US E&P companies from 2002-2006 grew at a 38%CAGR.

Source: Bloomberg, John S. Herold, Inc.

(Slide 32)

Rising Resource Nationalism

This slide contains a bar graph displaying the volume of oil and gas resources in BBoe controlled by the following entities:

Government-owned Oil Companies (GOCs) – 95%:

Saudi Aramco, NIOC (Iran), Qatar Petroleum, ADNOC (UAE), Iraq NOC,

Gazprom (Russia), KPC (Kuwait), PDVSA (Venezuela), NNPC (Nigeria), NOC (Libya)

Sonatrach (Algeria), Rosneft (Russia), Petronas (Malaysia), Lukoil (Russia),

Pemex (Mexico), Petrochina (China), Petrobras (Brazil), ONGC (India), Sinopec (China)

International Oil Companies (IOCs) – 5%:

ExxonMobil, BP, Chevron, Royal Dutch Shell, Total, ConocoPhillips, ENI

* GOCs control an overwhelming majority of oil and gas resources.

Source: Merrill Lynch

(Slide 33)

The Challenges

* Aging of the workforce

* Access to land

* Political situations in large resource countries

* Balancing environmental vs. energy needs

* Lack of new talent (engineering and technical)

* Challenge of meeting the demand growth with new supplies

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 34)

U.S. Gas Consumption and Sources

This slide displays U.S. gas production versus U.S. gas consumption in Bcf from 1975 to 2006. Net imports for the same period are also given.  U.S. gas production basically flat since 1994.

Source: EIA

(Slide 35)
U.S. Gas Production Decline Rate

This graph portrays U.S. natural gas production history.  The graph indicates a 32% 2006E decline rate.

	Production Decline Rate of Base
1990	17%
1991	17%
1992	16%
1993	18%
1994	19%	*
1995	19%	*
1996	20%	*
1997	21%	*
1998	23%	*
1999	23%	*
2000	25%
2001E	24%
2002E	27%
2003E	28%
2004E	29%
2005E	30%
2006E	32%	*

*Supply impact of 32% vs. 19-23% is under estimated

Utilizes data supplied by IHS Energy; Copyright IHS Energy

Chart prepared by and Property of EOG Resources, Inc.; Copyright 2006

(Slide 36)
U.S. Electricity Consumption on the Rise

This line graph shows an increase in U.S. electricity consumption in billion kilowatt-hours per month from 1990 to present.

Source:  Edison Electric Institute

(Slide 37)
NYMEX Gas Prices

This line graph represents NYMEX gas prices in $/Mcf from 2000 to present.

Source:  Bloomberg

(Slide 38)
U.S. Gas Drilling

This line graph denotes the number of rigs drilling for gas through the period 1988 to present.

Source:  Baker Hughes

(Slide 39)
Oil and Gas Price Comparison

This line graph compares the prices of Henry Hub natural gas and WTI crude oil in $/MMBtu and $/Bbl, respectively, for the period 1994 to present.

Source:  Bloomberg

(Slide 40)

Explanation and Reconciliation of Non-GAAP Financial Measures: Net Cash Flow

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. Forecasting changes in operating assets and liabilities would require unreasonable effort, would not be reliable and could be misl eading. Therefore, the reconciliation of the company’s forecasted net cash provided by operating activities before changes in operating assets and liabilities has assumed no changes in assets and liabilities. The first table below reconciles actual 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.

	9 Months Ended September 30,		Year Ended December 31,
	2007	2006	2006	2005	2004
	($ in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$446,906	$304,847	$413,508	$321,758	$237,706
Add back (deduct):
Change in operating assets and liabilities	(11,888)	26,289	16,429	(17,276)	191
Net cash provided by operating activities	$435,018	$331,136	$429,937	$304,482	$237,897

	2007 Guidance
	NYMEX Commodity Price Assumptions
	$7.00 Gas
	$70.00 Oil
	($ in millions)
Net cash provided by operating activities	$610-$620
Add back (deduct):
Assumed change in operating assets and liabilities	--
Net cash provided by operating activities before changes in operating assets and liabilities	$610-$620

Note that the information contained on this slide constitutes a "Forward-Looking Statement".

(Slide 41)

Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA

EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Southwestern has included information concerning EBITDA because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry.  EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's profitability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical EBITDA with historical net income.

	9 Months Ended September 30,		12 Months Ended December 31,
	2007	2006	2006	2005	2004	2003		2002	2001	2000		1999
	($ in thousands)
Net income	$149,542	$128,876	$162,636	$147,760	$103,576	$48,897		$14,311	$35,324	$20,461	(1)	$9,927
Depreciation, depletion and amortization	204,071	100,883	151,795	96,641	74,919	56,833		54,095	53,003	47,505		41,707
Net interest expense	13,728	501	679	15,040	16,992	17,311		21,466	23,699	24,689		17,351
Provision for income taxes	91,654	78,988	99,399	86,431	59,778	28,372	(2)	8,708	21,917	11,457		6,449
EBITDA	$458,995	$309,248	$414,509	$345,872	$255,265	$151,413		$98,580	$133,943	$104,112	(1)	$75,434

(1)   2000 amounts exclude unusual items of $109.3 million for the Hales judgment and $2.0 million for other litigation.

(2)    Provision for income taxes for 2003 includes the tax benefit associated with the cumulative effect of adoption of accounting principle.

The table below reconciles forecasted EBITDA with forecasted net income for 2007, assuming different NYMEX price scenarios and their corresponding estimated impact on the company's results for 2007, including current hedges in place, as of October 31, 2007:

	2007 Guidance
	NYMEX Commodity Price Assumptions
	$7.00 Gas
	$70.00 Oil
	($ in millions)
Net income	$200 - $205
Add back:
Provision for income taxes - deferred	123 - 126
Interest expense	25 - 30
Depreciation, depletion and amortization	285 - 295
EBITDA	$630 - $640

Note that the information contained on this slide constitutes a "Forward-Looking Statement".