EXHIBIT 99.1

Slide Presentation dated November 2008

The following slides were presented by Southwestern Energy Company.

(Cover)
Southwestern Energy Company

November 2008 Update

NYSE: SWN

The left side of this slide contains a picture of a helicopter flying over a mountain range at sunset.  The caption above reads "The Right Balance."  The company's formula is located in the bottom 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 and natural gas gathering and marketing.

Market Data as of October 31, 2008

Shares of Common Stock Outstanding	344,405,493
Market Capitalization	$12,267,000,000
Institutional Ownership	90.0%
Management Ownership	4.0%
52-Week Price Range*	$20.81 (10/10/08) - $48.69 (6/9/08)

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

* As adjusted to reflect a two-for-one stock split effected on March 25, 2008.

(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 update 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 company’s ability to transport its production to the most favorable markets or at all; the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; 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 impact of federal, state and local government regulation, including any increase in severance taxes; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services; the company’s future property acquisition or divestiture activities; increased competition; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the company’s lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the company’s counterparties and any other factors listed in the 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 the 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.
	* 1,450 Bcfe of reserves; 96% natural gas; 12.8 R/P at year-end 2007.
* E&P strategy built on organic growth through the drillbit.
	* Over 80% of planned E&P capital allocated to drilling in 2008.
* Track record of adding significant reserves at low costs.
	* From 2004 through 2007, we've averaged production growth of 28%, reserve growth of 31%, 418% reserve replacement, and F&D cost of $2.26 per Mcfe.
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to approximately $12 billion.
* 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

*  Third Quarter 2008 Highlights
	*  Production of 52.8 Bcfe, up 76%.
	*  Net income of $218.2 million, up 328%.
	*  Discretionary cash flow of $312.1 million, up 98%.

* Operations Update
	* Significant progress realized in our Fayetteville Shale play.
		* Gross operated production from Fayetteville Shale project increased to approximately 600 MMcf per day at September 30, 2008, up from approximately 260 MMcf a year ago.
	* Arkoma Basin and East Texas development programs delivering high-return growth.
		* Success with James Lime drilling program in East Texas.
* Strong Balance Sheet Positioned Well to Move into 2009.
	* Completed approximately $1 billion of non-core asset sales.
	* Debt-to-total capital ratio down from 37% at year-end 2007 to 25% at September 30.
	* Cash balance of $426 million at September 30.
	* Fully undrawn credit facility of $1 billion.

Note:	Net income includes after-tax gain on sale of utility assets of $35.5 million during the third quarter of 2008.
	Discretionary cash flow is net cash flow before changes in operating assets and liabilities and is a non-GAAP financial measure (see reconciliation on page 27).

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	2007	2008E
Production (Bcfe)	33	36	40	40	41	54	61	72	113	190-192E
Reserve Replacement (%)	148%	211%	155%	215%	313%	365%	399%	386%	474%
EBITDA ($MM) (1)	$75	$104	$134	$99	$151	$255	$346	$415	$675
F&D Cost ($/Mcfe)	$1.20	$0.91	$1.59	$0.99	$1.33	$1.43	$1.71	$2.72	$2.55

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

(1)    EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 28.

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

(Slide 6)
Areas of Operations

This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and Pennsylvania with shadings to denote the Conventional Arkoma Basin, the East Texas region, the Fayetteville Shale and the Marcellus Shale.

Exploration and Production Segment

* 2007:1,450 Bcfe of Reserves
	96% Natural Gas
	Production - 113.6 Bcfe
* 2008 Est. Production: 190-192 Bcfe

Conventional Arkoma

* Reserves: 304 Bcf (21%)

* Production: 23.8 Bcf (21%)

* Net Acres: 366,419 (12/31/07)

Fayetteville Shale

* Reserves: 716 Bcf (49%)

* Production: 53.5 Bcf (47%)

* Net Acres: 860,000 (current)

East Texas

* Reserves: 353 Bcfe (24%)

* Production: 29.9 Bcfe (26%)

* Net Acres: 118,904 (12/31/07)

Marcellus Shale

* Net Acres: 110,000 (current)

* Southwestern's E&P segment operates in Arkansas, Texas, Oklahoma, Louisiana and Pennsylvania and generated approximately 95% of 2007 EBITDA.

* Midstream Services segment provides marketing and gathering services for the E&P business.

Notes:	2007 reserve and production data by area does not add to year-end totals for the company due to assets which were sold during 2008 and the exclusion of New Ventures area (sold approximately 25 MMcfe per day of production and approximately 90 Bcfe of reserves during 2008).
	Conventional Arkoma acreage excludes 125,372 net acres in the conventional Arkoma Basin operating area that are also within the company's Fayetteville Shale focus area.

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:

						2008
	2003	2004	2005	2006	2007	Plan
	(in millions)
Utility & Other	$9	$13	$16	$32	$16	$25
Property Acquisitions	$ -	$14	$ -	$18	$ 2	$ -
Cap. Expense & Other E&P	$12	$18	$32	$62	$77	$142
Leasehold & Seismic	$19	$21	$61	$70	$166	$131
Development Drilling	$120	$209	$287	$421	$1,110	$1,218
Exploration Drilling	$20	$20	$36	$196	$20	$50
Midstream Services	$ -	$ -	$16	$49	$107	$135
Drilling Rigs	$ -	$ -	$35	$94	$ 5	$ -
Total	$180	$295	$483	$942	$1,503	$1,701

This slide also contains a pie chart of the company's preliminary planned 2008 capital investments by area of operation, summarized as follows:

	% of Total
	Capital Investments
Arkoma Fayetteville Shale	70%
East Texas	9%
Arkoma	8%
Midstream	8%
Other E&P	4%
Corporate	1%
Utility/Other	<1%

* E&P capital program heavily weighted to low-risk development drilling in 2008.

* Plan to invest over $1.3 billion in the Fayetteville Shale play in 2008.

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 James Lime Horizontals and the East Texas Salt Basin are also denoted on the map.  The cities of Tyler and Lufkin, Texas are displayed as reference points.

This slide also contains a bar chart of East Texas production, summarized as follows:

East Texas Production:
	Cotton Valley/Travis Peak/Other	James Lime
	(Bcfe)	(Bcfe)
2000	0.3	0.0
2001	2.3	0.0
2002	5.9	0.0
2003	13.6	0.0
2004	22.2	0.0
2005	28.2	0.0
2006	32.0	0.0
2007	29.9	0.0
2008E	26.5	5.5

James Lime Horizontals

12 Wells Completed

Avg IP Rate -  9.0 MMcf/d

* 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 102,000 gross acres at Angelina and Jebel.

* 2008 development program includes approximately 28 gross (17 net) James Lime horizontal wells.

* Announced a 50/50 joint venture agreement with a private company to drill two wells targeting the Haynesville/Bossier Shale intervals (approximately 41,500 gross acres in 3 counties).

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

(Slide 9)

Arkoma Basin

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

* 65+ years of experience in the basin, large acreage position of over 366,000 net acres in the traditional fairway.
	* 2008 capital program includes drilling 100 - 110 wells in the traditional fairway, Ranger Anticline and Midway areas.
* SWN currently holds approximately 860,000 net acres in the Fayetteville Shale play area (equivalent to over 1,300 square miles).

Note:  Conventional Arkoma acreage excludes 125,372 net acres in the conventional Arkoma Basin operating area that are also within the company's Fayetteville Shale focus area.

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

(Slide 10)
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. 734,600 net acres and 125,400 net acres HBP are outlined on the map. Boxes denote Conventional Production (11 MMcf/d). The Scotland Field, Gravel Hill Field, Griffin Mountain Field, Cove Creek Field, New Quitman Field, Chattanooga Test and Ranger Anticline are also designated.  The Moorefield Prospective Area is outlined.  Lines trace the Ozark, Centerpoint, NGPL, MRT and TETCO transmission pipelines.

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

* As of September 30, 2008, SWN has drilled and completed 722 wells, of which 604 are horizontal slickwater or crosslinked gel fracture stimulated wells, in 33 separate pilot areas in 8 counties.

* We anticipate participating in 520 horizontal wells in 2008, approximately 75% operated.

Notes:    Data as of September 30, 2008.

                Well data excludes 24 wells which were sold in May 2008.

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

(Slide 11)
Fayetteville Shale - Improving Well Performance

Time Frame	Wells Placed on Production	Average IP Rate (Mcf/d)	30th-Day Avg Rate (# of wells)	60th-Day Avg Rate (# of wells)	Avg Lateral Length	Completion Method SW/XL/Hy-RHy
1st Qtr 2007	58	1,261	1,066 (58)	958 (58)	2,104	11/37/10
2nd Qtr 2007	46	1,497	1,254 (46)	1,034 (46)	2,512	24/12/10
3rd Qtr 2007	74	1,788	1,512 (72)	1,350 (71)	2,622	69/4/1
4th Qtr 2007	77	2,028	1,690 (77)	1,499 (76)	3,193	68/1/8
1st Qtr 2008	75	2,343	2,147 (75)	1,954 (74)	3,301	71/1/3
2nd Qtr 2008	83	2,541	2,155 (83)	1,893 (82)	3,562	83/0/0
3rd Qtr 2008	97	2,882	2,453 (82)	2,199 (50)	3,736	97/0/0

* Focusing on longer laterals, slick-water completions and larger frac jobs.

* For the fourth quarter of 2008, our average well cost is projected to be $3.1 million.

* Utilizing 3-D seismic to improve overall well performance.  Over 75% of our 2008 planned wells will have the benefit of 3-D seismic (versus 20% in 2007).

Note: Data as of September 30, 2008.

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

(Slide 12)
Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through September 30, 2008, for the company's horizontal wells drilled in the Fayetteville Shale.  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 2.5 Bcf, 2.0 Bcf and 1.5 Bcf 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	All Horizontal Wells with Laterals > 3,000 Feet
30	535	263
60	508	235
90	478	206
120	447	182
180	391	131
240	336	90
300	296	63
360	254	33
420	201	17
480	166	8
540	138	2
600	98	2
660	67	2
720	41	1
780	28	1
840	13	0
900	5	0
960	1	0
1020	1	0
1082	1	0

Note:	Data as of September 30, 2008.
	Data excludes wells with mechanical problems (28).

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

(Slide 13)
Fayetteville Project - Gross Production

This line graph shows gross production in MMcf/d for the Fayetteville Shale from January 2006 to September 30, 2008. Gross operated production of approx. 600 MMcf/d as of September 30, 2008.

(Slide 14)
Midstream - Capturing Additional Value Beyond the Wellhead

This slide contains a map of several counties in Arkansas where the company's Fayetteville Shale Focus Area is located.  These counties include Johnson, Pope, Van Buren, Cleburne, Logan, Yell, Conway, Faulkner and White.  Lines trace DeSoto Gathering Lines, the Planned Boardwalk Lateral and the Ozark, Centerpoint, NGPL, MRT and TETCO transmission pipelines.  Compression facilities are also indicated on the map.

* Midstream assets provide rapidly growing revenue stream and potential future funding source.

* At September 30, 2008, gathering approximately 675 MMcf per day through 793 miles of gathering lines, up from approximately 250 MMcf per day the same time a year ago.

* 2007 EBITDA⁽¹⁾ of $18.8 million and $65.0 to $70.0 million projected for 2008.

Note:  Data as of September 30, 2008.

(1) EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 28.

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

(Slide 15)
Outlook for 2008

* Production target of 190 - 192 Bcfe in 2008 (estimated growth of 68%).

	2007	2008 Guidance
	Actual	NYMEX Price Assumptions (1)
	$6.86 Gas	$9.04 Gas
	$69.72 Oil	$106.11 Oil
Net Income (2)	$221.2 MM	$585 - $590 MM
EPS (2)	$0.64 (3)	$1.68 - $1.70
EBITDA (2)(4)	$675.4 MM	$1,400 - $1,410 MM
Net Cash Flow (4)	$651.2 MM	$1,180 - $1,190 MM
Divestitures (5)	---	$1 Billion
CapEx	$1,503 MM	$1,701 MM
Debt %	37%	23% - 24%

(1)     Guidance updated as of November 7, 2008.  2008 oil and gas prices include actual last-day NYMEX closing prices through November 2008 and $7.00 gas/$70.00 oil for December 2008.

(2)     Net income and EPS for 2008 includes after-tax gain on sale of utility assets of $35.5 million ($0.10 per diluted share) during the third quarter of 2008 (while EBITDA includes the pre-tax gain on sale of $57.3 million).

(3)     As adjusted to reflect the two-for-one stock split effected on March 25, 2008.

(4)     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 27 and 28.

(5)    Expected gross proceeds of asset divestitures (includes sale of utility, Fayetteville Shale acreage, and Permian Basin and Gulf Coast assets).

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

(Slide 16)
The Road to V⁺

* Invest in the Highest PVI Projects.
* 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 17)
Appendix

(Slide 18)
Financial & Operational Summary

	Nine Months Ended September 30,		Year Ended December 31,
	2008	2007	2007	2006	2005
	($ in millions, except per share amounts)
Revenues	$1,811.5	$852.4	$1,255.1	$763.1	$676.3
Net Income (1)	463.7	149.5	221.2	162.6	147.8
EBITDA (1) (2)	1,075.6	459.0	675.4	414.5	345.9
Net Cash Flow (2)	884.1	446.9	651.2	413.5	321.8
Diluted EPS (1) (3)	$1.34	$0.43	$0.64	$0.47	$0.47
Diluted CFPS (3)	$2.55	$1.30	$1.87	$1.21	$1.03
Production (Bcfe)	137.0	78.7	113.6	72.3	61.0
Avg. Gas Price ($/Mcf)	$8.19	$6.75	$6.80	$6.55	$6.51
Avg. Oil Price ($/Bbl)	$112.37	$62.58	$69.12	$58.36	$42.62
Finding Cost ($/Mcfe) (4)			$2.55	$2.72	$1.71
Reserve Replacement (%) (4)			474%	386%	399%

(1)    Net income and EPS for 2008 includes after-tax gain on sale of utility assets of $35.5 million ($0.10 per diluted share) during the third quarter of 2008 (while EBITDA includes the pre-tax gain on sale of $57.3 million).

(2)    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 27 and 28.

(3)    Diluted earnings per share and diluted cash flow per share have been adjusted to reflect the two-for-one stock split effected on March 25, 2008 and two 2-for-1 stock splits during 2005.

(4)    Includes reserve revisions and excludes capital investments in drilling rigs.

(Slide 19)
Consistent Commodity Hedging Strategy

This slide contains a bar chart detailing gas hedges in place by quarter for year 2008, year 2009 and year 2010.  A summary of these gas hedges is as follows:

			Average Price per Mcf	Percent
	Type	Hedged Volumes	(or Floor/Ceiling)	Hedged
2008	Swaps	70.0 Bcf	$8.43	37%
	Collars	48.0 Bcf	$7.92 / $11.60	25%
2009	Swaps	76.0 Bcf	$8.30	-
	Collars	59.0 Bcf	$8.71 / $11.69	-
2010	Swaps	36.0 Bcf	$9.04	-
	Collars	14.0 Bcf	$8.29 / $10.57	-

SWN has historically hedged 70 - 80% of projected gas production volumes.

Historical Gas Hedge Percentages
2002	78%
2003	80%
2004	70%
2005	79%
2006	73%
2007	72%

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

(Slide 20)

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	$0.88
Noble Energy	$1.12
Chesapeake Energy	$1.16
Ultra Petroleum	$1.17
EOG Resources	$1.19
EnCana	$1.23
Range Resources	$1.24
Pioneer Natural Resources	$1.37
Devon Energy	$1.53
XTO Energy	$1.54
Newfield Exploration	$1.60
Forest Oil	$1.63
Cimarex Energy	$1.73
Cabot Oil & Gas	$1.75
Anadarko Petroleum	$1.77
Apache	$1.78
Quicksilver Resources	$1.84
St. Mary Land & Exploration	$1.87
Swift Energy	$1.88
Denbury Resources	$2.56

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	$0.75
Quicksilver Resources	$1.15
XTO Energy	$1.67
Range Resources	$1.89
Cabot Oil & Gas	$1.99
EOG Resources	$2.10
EnCana	$2.12
Southwestern Energy Company	$2.21
Devon Energy	$2.44
Apache	$2.53
Denbury Resources	$2.92
Newfield Exploration	$3.08
Forest Oil	$3.66
Noble Energy	$4.09
St. Mary Land & Exploration	$4.30
Pioneer Natural Resources	$4.41
Cimarex Energy	$4.42
Swift Energy	$6.08
Anadarko Petroleum	$6.09
Chesapeake Energy	$6.18

Source:  John S. Herold Database

Note:  All data as of December 31, 2005, 2006 and 2007.

Drillbit F&D Cost per Mcfe defined as three-year sum of total costs incurred less the three-year sum of proved acquisitions cost divided by the three-year sum of reserve additions from extensions and discoveries.

(Slide 21)

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 Vertical Wells/Year
1990-1994	Avg. 40 Vertical Wells/Year
1995-1999	Avg. 73 Vertical 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
2006	Vertical Wells Drilled Horizontal Wells Drilled	273 1,189
2007	Vertical Wells Drilled Horizontal Wells Drilled	185 2,442

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	32 40
2006	Vertical Wells Drilled Horizontal Wells Drilled	8 205
2007	Vertical Wells Drilled Horizontal Wells Drilled	8 504
2008E	Vertical Wells Drilled Horizontal Wells Drilled	0 ~1,000

Source: Republic Energy Co., Tudor, Pickering, Holt & Co. Securities, Inc., Arkansas Oil & Gas Commission via PI-Dwights, Southwestern Energy

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

(Slide 22)

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 less than 4-year period and the Barnett Shale over a more than 21-year period.  It is noted that the total Fayetteville Shale Field average daily production for August 2008 was 807 MMcf/d.

A box accompanying the graph states:

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

Source: Tudor, Pickering, Holt & Co. Securities, Inc., Arkansas Oil & Gas Commission

(Slide 23)

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 consumption and production rising in recent years.

Source: EIA

(Slide 24)
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 25)
U.S. Gas Drilling and Prices

This line graph denotes the number of rigs drilling for gas and the gas price in dollars per MMBtu through the period 2000 to present.

Source:  Baker Hughes

Bloomberg

(Slide 26)
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 27)

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 misleading. 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 Sept. 30,		Year Ended December 31,
	2008	2007	2007	2006	2005
	($ in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$884,086	$446,906	$651,170	$413,508	$321,758
Add back (deduct):
Change in operating assets and liabilities	82,621	(11,888)	(28,435)	16,429	(17,276)
Net cash provided by operating activities	$966,707	$435,018	$622,735	$429,937	$304,482

	2008 Guidance
	NYMEX Commodity Price Assumptions (1)
	$9.04 Gas
	$106.11 Oil
	($ in millions)
Net cash provided by operating activities	$1,180 - $1,190
Add back (deduct):
Assumed change in operating assets and liabilities	--
Net cash provided by operating activities before changes in operating assets and liabilities	$1,180 - $1,190

(1) Guidance updated as of November 7, 2008.  2008 oil and gas prices include actual last-day NYMEX closing prices through November 2008 and $7.00 gas/$70.00 oil for December 2008.

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

(Slide 28)

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,
	2008	2007	2007 (1)	2006	2005	2004	2003		2002	2001	2000		1999
	($ in thousands)
Net income	$463,747	$149,542	$221,174	$162,636	$147,760	$103,576	$48,897		$14,311	$35,324	$20,461	(2)	$9,927
Depreciation, depletion and amortization	300,529	204,071	294,500	151,795	96,641	74,919	56,833		54,095	53,003	47,505		41,707
Net interest expense	27,104	13,728	23,873	679	15,040	16,992	17,311		21,466	23,699	24,689		17,351
Provision for income taxes	284,232	91,654	135,855	99,399	86,431	59,778	28,372	(3)	8,708	21,917	11,457		6,449
EBITDA	$1,075,612	$458,995	$675,402	$414,509	$345,872	$255,265	$151,413		$98,580	$133,943	$104,112	(2)	$75,434

(1)    Net income for the Midstream Services segment was $6,933, depreciation, depletion and amortization was $5,527, net interest expense was $2,006 and provision for income taxes was $4,294.

(2)    2000 amounts exclude unusual items of $109.3 million for the Hales judgment and $2.0 million for other litigation.

(3)    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 2008, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2008, including current hedges in place, as of November 7, 2008:

	2008 Guidance
	Corporate
	NYMEX Commodity Price Assumptions (1)	Midstream
	$9.04 Gas	Services
	$106.11 Oil	Segment (1)
	($ in millions)
Net income	$585 - $590	$26-$28
Add back:
Provision for income taxes	362 - 365	15 - 17
Interest expense	36 - 37	15 - 17
Depreciation, depletion and amortization	428 - 430	9 - 11
EBITDA	$1,400 - $1,410	$65 - $70

(1)    Guidance updated as of November 7, 2008.  2008 oil and gas prices include actual last-day NYMEX closing prices through November 2008 and $7.00 gas/$70.00 oil for December 2008.

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