EXHIBIT 99.1

Slide Presentation dated May 2009

The following slides were presented by Southwestern Energy Company.

(Cover)
Southwestern Energy

May 2009 Update

NYSE: SWN

The left side of this slide contains a picture of a flock of birds in flight. One bird is leaving the flock in a positive direction to the right.  The caption above reads "Our Way."  The company's formula is located on the middle right of the picture.  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 April 30, 2009

Shares of Common Stock Outstanding	343,636,807
Market Capitalization	$12,322,000,000
Institutional Ownership	88.7%
Management Ownership	3.8%
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
Vice President, 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 Southwestern Energy Company's (the company) 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 SEC 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.
	* 2,185 Bcfe of reserves; ~100% natural gas; 11.2 R/P at year-end 2008.
* E&P strategy built on organic growth through the drillbit.
	* Over 80% of planned E&P capital allocated to drilling in 2009.
* Track record of adding significant reserves at low costs.
	* From 2004 through 2008, we've averaged production growth of 38%, reserve growth of 36%, 459% reserve replacement, and F&D cost of $1.94 per Mcfe.
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to approximately $12 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 Quarter 2009 Highlights
	*  Production of 63.9 Bcfe, up 64%.
	*  Discretionary cash flow(1) of $372.6 million, up 31%.
	*  Adjusted net income(2) of $125.5 million, up 15%.
	*  Significant progress realized in our Fayetteville Shale play.
		*  Gross operated production from Fayetteville Shale increased to approx. 850 MMcf per day at March 31, 2009, up from 400 MMcf a year ago.

* Strong Balance Sheet Positioned Well for 2009
	* Completed approximately $1 billion of non-core asset sales during 2008.
	* Debt-to-total capital ratio of 25% at March 31, 2009.
	* Cash balance of $82.3 million at March 31, 2009.
	* $1 billion credit facility with nothing drawn on it.

(1)	Discretionary cash flow is net cash flow before changes in operating assets and liabilities and is a non-GAAP financial measure (see explanation and reconciliation on page 27).
(2)	Adjusted net income of $125.5 million excludes a $558.3 million after-tax non-cash ceiling test impairment and is a non-GAAP financial measure (see explanation and reconciliation on page 28).

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.

	2000	2001	2002	2003	2004	2005	2006	2007	2008	2009E
Production (Bcfe)	36	40	40	41	54	61	72	113	195	289-292E
Reserve Replacement (%)	211%	155%	215%	313%	364%	399%	386%	474%	523%
EBITDA ($MM) (1)	$104	$134	$99	$151	$255	$346	$415	$675	$1,362
F&D Cost ($/Mcfe)	$0.92	$1.59	$0.99	$1.32	$1.43	$1.70	$2.72	$2.55	$1.53

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 29.

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

* 2008:	2,185 Bcfe of Reserves
	~100% Natural Gas
	Production - 194.6 Bcfe
* 2009 Est. Production: 289-292 Bcfe

Conventional Arkoma

* Reserves: 281 Bcf (13%)

* Production: 24.4 Bcf (13%)

* Net Acres: 426,099 (12/31/08)

Fayetteville Shale

* Reserves: 1,545 Bcf (71%)

* Production: 134.5 Bcf (69%)

* Net Acres: 875,107 (12/31/08)

East Texas

* Reserves: 351 Bcfe (16%)

* Production: 31.6 Bcfe (16%)

* Net Acres: 134,403 (12/31/08)

Marcellus Shale

* Net Acres: 138,600 (3/31/09)

* Southwestern's E&P segment operates in Arkansas, Texas, Oklahoma, Louisiana and Pennsylvania.

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

Notes:	2008 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.
	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:

						2009
	2004	2005	2006	2007	2008	Plan
	(in millions)
Corporate & Other	$13	$16	$32	$16	$17	$36
Property Acquisitions	$14	$ -	$18	$ 2	$ -	$ -
Cap. Expense & Other E&P	$18	$32	$62	$77	$153	$221
Leasehold & Seismic	$21	$61	$70	$166	$149	$125
Development Drilling	$209	$287	$421	$1,110	$1,255	$1,185
Exploration Drilling	$20	$36	$196	$20	$39	$28
Midstream Services	$ -	$16	$49	$107	$183	$205
Drilling Rigs	$ -	$35	$94	$ 5	$ -	$ -
Total	$295	$483	$942	$1,503	$1,796	$1,800

This slide also contains a pie chart of the company's preliminary planned 2009 capital investments by area of operation, summarized as follows:

	% of Total
	Capital Investments
Arkoma Fayetteville Shale	70%
Midstream	11%
East Texas	7%
Other E&P	7%
Arkoma	3%
Corp/Other	2%

* E&P capital program heavily weighted to low-risk development drilling in 2009.

* Plan to invest approximately $1.5 billion in the Fayetteville Shale play in 2009.

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
2008	26.0	5.6

James Lime Horizontals

21 Wells Completed

Avg IP Rate -  8.8 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 105,700 gross acres at Angelina and Jebel.

* 2009 capital program includes participation in approximately 35 wells, 29 of which are planned to be horizontal wells targeting the James Lime formation.

* Drilled two horizontal wells targeting the Haynesville/Bossier Shale intervals (current acreage position of approximately 50,000 net acres).  First well tested at 7.2 MMcfe per day.  Second well expected to be completed in second quarter 2009.

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 426,000 net acres in the traditional fairway.

* SWN currently holds approximately 875,000 net acres in the Fayetteville Shale play area (equivalent to over 1,350 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. 749,700 net acres and 125,400 net acres HBP are outlined on the map.  The Ranger Anticline, Chattanooga Test and Moorefield Prospective Area are also denoted.  Lines trace the Ozark, Centerpoint, NGPL, MRT and TETCO transmission pipelines. A line also traces the Boardwalk Fayetteville Lateral (Phase 1) transmission pipeline in-service at 12/24/2008.

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

* As of March 31, 2009, SWN has drilled and completed 938 operated wells, of which 798 are horizontal slickwater or crosslinked gel fracture stimulated wells.

* We anticipate participating in 600 horizontal wells in 2009, approximately 75% operated.

Notes:    Data as of March 31, 2009.

                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)	1,943 (74)	3,301	71/1/3
2nd Qtr 2008	83	2,541	2,155 (83)	1,858 (83)	3,562	83/0/0
3rd Qtr 2008	97	2,882	2,573 (96)	2,355 (95)	3,736	97/0/0
4th Qtr 2008(1)	74	3,347(1)	2,722 (74)	2,384 (74)	3,850	74/0/0
1st Qtr 2009(1)	120	3,000(1)	2,373 (75)	1,879 (31)	3,874	120/0/0

* Focusing on longer laterals, slick-water completions and larger frac jobs.  Average 2009 well cost is projected to be $2.9 million

* Over 95% of our 2009 planned wells will have the benefit of 3-D seismic (versus 70% in 2008).

Note: Data as of March 31, 2009.

(1)    The significant increase in the average initial production rate for the fourth quarter of 2008 and the subsequent decrease for the first quarter of 2009 primarily reflected the impact of the delay in the Boardwalk Pipeline.  Wells that were placed on production in January and February of 2009 had average initial production rates of 2,806 Mcf per day and 2,749 Mcf per day, respectively, while wells placed on production during March 2009 had average initial production rates of 3,375 Mcf per day.  During the first half of April 2009, the company had placed 27 wells on production at an average initial production rate of 3,763 Mcf per day.

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 March 31, 2009, for the company's horizontal wells drilled in the Fayetteville Shale.  This graph displays three composite curves, one showing the SW/XL normalized production from all the company's horizontal wells excluding mechanical issues, another showing the SW normalized production from the company's horizontal wells with laterals greater than 3,000 feet excluding mechanical issues, and a third showing the SW normalized production from the company's horizontal wells with laterals greater than 4,000 feet excluding mechanical issues. The production data is compared to 3.0 Bcf, 2.5 Bcf, and 2.0 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	All Horizontal Wells with Laterals > 4,000 Feet
30	706	432	107
60	658	380	89
120	591	317	58
180	550	277	38
240	495	231	27
300	437	179	15
360	382	131	6
420	328	90	4
480	281	61	1
540	237	26	1
600	196	18	0
660	162	8	0
720	134	2	0
780	89	2	0
840	62	2	0
900	39	1	0
960	26	1	0
1020	12	0	0
1080	5	0	0
1140	1	0	0
1200	1	0	0
1265	1	0	0

Note:	Data as of March 31, 2009.
	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 March 31, 2009. Gross operated production of approx. 850 MMcf/d as of March 31, 2009.  2008 Fayetteville Shale F&D cost of $1.21/Mcf.

(Slide 14)
Midstream - Adding 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 and the Ozark, Centerpoint, Boardwalk, 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 March 31, 2009, gathering approximately 918 MMcf per day through 892 miles of gathering lines, up from approximately 470 MMcf per day the same time a year ago.

* 2008 EBITDA⁽¹⁾ of $73.9 million and $115 to $120 million projected for 2009.

* Phase 1 of Fayetteville Lateral of Boardwalk Pipeline placed in-service late December 2008.  Fayetteville and Greenville Laterals placed in-service April 1, 2009.

* Planned Fayetteville Express Pipeline expected in-service January 2011 (FT volumes of 1,200,000 dkth/d).

Note:  Map as of December 31, 2008.

(1) EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 29.

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

(Slide 15)
Outlook for 2009

* Production target of 289 - 292 Bcfe in 2009 (estimated growth of ~50%).

	2008	2009 Guidance
	Actual	NYMEX Price Assumptions
	$9.04 Gas	$5.00 Gas	$6.00 Gas
	$104.42 Oil	$50.00 Oil	$60.00 Oil
Adj. Net Income	$568 MM(1)	$490 - $500 MM(2)	$590 - $600 MM(2)
Adj. Diluted EPS	$1.64(1)	$1.40 - $1.42(2)	$1.70 - $1.72(2)
EBITDA(3)	$1,362 MM(1)	$1,450 - $1,460 MM	$1,610 - $1,620 MM
Net Cash Flow (3)	$1,167 MM	$1,420 - $1,430 MM	$1,580 - $1,590 MM
Divestitures (4)	$964 MM	---	---
CapEx	$1,796 MM	$1,800 MM	$1,800 MM
Debt %	23%	26% - 28%(5)	21% - 23%(5)

(1)     Adjusted net income and adjusted diluted EPS for 2008 includes after-tax gain on sale of utility assets of $35.4 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)     Adjusted net income and adjusted diluted EPS in 2009 exclude a $558.3 million after-tax non-cash ceiling test impairment and both are non-GAAP financial measures.  See explanation and reconciliation on page 28.

(3)     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 29.

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

(5)    2009 projected book capitalization includes the effect of the $558.3 million after-tax non-cash ceiling test impairment in the first quarter of 2009.

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.
* Flexibility in 2009/2010 Capital Programs.
* Maintain Strong Balance Sheet.
* Deliver the Numbers.
	* Production and Reserves.
	* 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

	Quarter Ended March 31,		Year Ended December 31,
	2009	2008	2008	2007	2006
	($ in millions, except per share amounts)
Revenues	$540.8	$524.1	$2,311.6	$1,255.1	$763.1
EBITDA (1)	331.9	284.6	1,362.3(2)	675.4	414.5
Adjusted Net Income	125.5(3)	109.0	567.9(2)	221.2	162.6
Net Cash Flow (1)(4)	372.6	283.7	1,167.5	651.2	413.5
Adjusted Diluted EPS	$0.36(3)	$0.31	$1.64(2)	$0.64(4)	$0.47(4)
Diluted CFPS (1)	$1.07	$0.81	$3.37	$1.87(4)	$1.21(4)
Production (Bcfe)	63.9	39.1	194.6	113.6	72.3
Avg. Gas Price ($/Mcf)	$5.94	$7.70	$7.52	$6.80	$6.55
Avg. Oil Price ($/Bbl)	$34.90	$96.55	$107.18	$69.12	$58.36
Finding Cost ($/Mcfe) (5)			$1.53	$2.55	$2.72
Reserve Replacement (%) (5)			523%	474%	386%

(1)    Net cash flow is net cash flow before changes in operating assets and liabilities.  Net cash flow, EBITDA and diluted CFPS are non-GAAP financial measures.  See explanation and reconciliation of non-GAAP financial measures on pages 27 and 29.

(2)    Adjusted net income and adjusted diluted EPS for 2008 includes after-tax gain on sale of utility assets of $35.4 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)    Adjusted net income and adjusted diluted EPS for 2009 exclude a $558.3 million after-tax non-cash ceiling test impairment and both are non-GAAP financial measures.  See explanation and reconciliation on page 28.

(4)    Diluted EPS and diluted CFPS have been adjusted to reflect the two-for-one stock split effected on March 25, 2008.

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

(Slide 19)
Gas Hedges in Place Through 2010

This slide contains a bar chart detailing gas hedges in place by quarter for 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
2009	Swaps	76.0 Bcf	$8.30	26%
	Collars	59.0 Bcf	$8.71 / $11.69	20%
2010	Swaps	36.0 Bcf	$9.04	-
	Collars	14.0 Bcf	$8.29 / $10.57	-

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	$0.95
Ultra Petroleum	$0.99
EOG Resources	$1.06
Noble Energy	$1.08
Chesapeake Energy	$1.26
Range Resources	$1.29
EnCana	$1.36
Forest Oil	$1.43
Pioneer Natural Resources	$1.54
Newfield Exploration	$1.62
Devon Energy	$1.68
XTO Energy	$1.72
Anadarko Petroleum	$1.75
Quicksilver Resources	$1.77
Cimarex Energy	$1.77
Cabot Oil & Gas	$1.93
St. Mary Land & Exploration	$1.96
Apache	$2.02
Denbury Resources	$3.06

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	$1.00
Quicksilver Resources	$1.45
Southwestern Energy Company	$2.06
Denbury Resources	$2.25
Cabot Oil & Gas	$2.31
XTO Energy	$2.32
Range Resources	$2.37
EOG Resources	$2.39
EnCana	$2.62
Devon Energy	$2.83
Newfield Exploration	$3.15
Noble Energy	$3.35
Apache	$3.43
Forest Oil	$3.50
Pioneer Natural Resources	$4.37
St. Mary Land & Exploration	$5.11
Cimarex Energy	$5.61
Chesapeake Energy	$8.15
Anadarko Petroleum	$9.07

Source:  John S. Herold Database and public filings.

Note:  All data as of December 31, 2006, 2007 and 2008.

            Lifting Cost per Mcfe defined as production expenses plus production taxes divided by production.

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
2008E	Vertical Wells Drilled Horizontal Wells Drilled	150 ~3,150

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 23-year period.  Total Fayetteville Shale Field average daily production for January 2009 was 1,132 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 present. 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 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

We report our financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP").  However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods.  One such non-GAAP financial measure is net cash flow.  Management presents this measure because (i) it is accepted 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, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.  These adjusted amounts are not a measure of financial performance under GAAP.

	3 Months Ended March 31,		12 Months Ended December 31,
	2009	2008	2008	2007	2006
	(in thousands)		(in thousands)
Net cash provided by operating activities	$407,295	$297,087	$1,160,809	$622,735	$429,937
Add back (deduct):
Change in operating assets and liabilities	(34,740)	(13,370)	6,685	28,435	(16,429)
Net cash flow	$372,555	$283,717	$1,167,494	$651,170	$413,508

	2009 Guidance
	NYMEX Commodity Price Assumptions
	$5.00 Gas	$6.00 Gas
	$50.00 Oil	$60.00 Oil
	($ in millions)
Net cash provided by operating activities	$1,420 - $1,430	$1,580 - $1,590
Add back (deduct):
Assumed change in operating assets and liabilities	--	--
Net cash flow	$1,420 - $1,430	$1,580 - $1,590

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

(Slide 28)
Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted Net Income

Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy and diluted earnings per share attributable to Southwestern Energy stockholders, both of which exclude certain charges or amounts.  Management presents these measures because (i) they are consistent with the manner in which the Company's performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items.  These adjusted amounts are not a measure of financial performance under GAAP.

	3 Months Ended
	March 31, 2009
	($ in thousands)	(per share)
Net income (loss) attributable to SWN	($432,830)	($1.26)
Add back:
Impairment of natural gas and oil properties (net of taxes)	558,305	1.62
Adjusted net income	$125,475	$0.36

The table below reconciles forecasted adjusted net income with GAAP net income for 2009, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2009, including current hedges in place:

	2009 Guidance
	Overall Corporate
	NYMEX Commodity Price Assumptions
	$5.00 Gas	$6.00 Gas
	$50.00 Oil	$60.00 Oil
	($ in millions)
Net income (loss) attributable to SWN	($68) - ($58)	$32 - $42
Add back: Impairment of natural gas and oil properties (net of taxes)	558	558
Adjusted net income	$490 - $500	$590 - $600

	2009 Guidance
	Overall Corporate
	NYMEX Commodity Price Assumptions
	$5.00 Gas	$6.00 Gas
	$50.00 Oil	$60.00 Oil
	(per share)
Diluted earnings per share attributable to SWN stockholders	($0.22) - ($0.20)	$0.08 - $0.10
Add back: Impairment of natural gas and oil properties (net of taxes)	1.62	1.62
Adjusted diluted earnings per share	$1.40 - $1.42	$1.70 - $1.72

(Slide 29)

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.

	3 Months Ended  March 31,			12 Months Ended December 31,
	2009		2008	2008 (1)	2007	2006	2005	2004	2003		2002	2001	2000
				($ in thousands)
Net income (loss) attributable to SWN	($432,830)	(2)	$109,029	$567,946	$221,174	$162,636	$147,760	$103,576	$48,897		$14,311	$35,324	$20,461	(6)
Add back:
Net interest expense	3,684		11,529	28,904	23,873	679	15,040	16,992	17,311		21,466	23,699	24,689
Provision for income taxes	(270,959)	(3)	66,824	350,999	135,855	99,399	86,431	59,778	28,372	(5)	8,708	21,917	11,457
Depreciation, depletion and amortization	1,032,040	(4)	97,245	414,460	294,500	151,795	96,641	74,919	56,833		54,095	53,003	47,505
EBITDA	$331,935		$284,627	$1,362,309	$675,402	$414,509	$345,872	$255,265	$151,413		$98,580	$133,943	$104,112	(6)

(1)    Net income for the Midstream Services segment was $35,145, depreciation, depletion and amortization was $11,402, net interest expense was $6,059 and provision for income taxes was $21,278.

(2)    Net income (loss) includes the after-tax $558.3 million full cost ceiling impairment of our natural gas and oil properties recorded in Q1 2009.

(3)    Provision (benefit) for income taxes includes the ($349.5) million income tax benefit related to the full cost ceiling impairment of our natural gas and oil properties recorded in Q1 2009.

(4)    Depreciation, depletion and amortization includes the $907.8 million full cost ceiling impairment of our natural gas and oil properties recorded in Q1 2009.

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

(6)    2000 amounts exclude unusual items of $109.3 million for the Hales judgment and $2.0 million for other litigation.

The table below reconciles forecasted EBITDA with forecasted net income for 2009, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2009, including current hedges in place:

	2009 Guidance
	Overall Corporate
	NYMEX Commodity Price Assumptions				Midstream
	$5.00 Gas		$6.00 Gas		Services
	$50.00 Oil		$60.00 Oil		Segment (1)
	($ in millions)
Net income (loss) attributable to SWN	($68) - ($58)	(2)	$32 - $42	(2)	$51 - $53
Add back:
Provision (benefit) for income taxes	(43) - (38)	(3)	20 - 25	(3)	31 - 33
Interest expense	32 - 33		29 - 30		13 - 15
Depreciation, depletion and amortization	1,523 - 1,528	(4)	1,523 - 1,528	(4)	20 - 22
EBITDA	$1,450 - $1,460		$1,610 - $1,620		$115 - $120

(1)    Midstream Services segment 2009 results assumes NYMEX commodity prices of $5.00 per Mcf for natural gas and $50.00 per barrel for crude oil.

(2)    Net income (loss) includes the after-tax $558.3 million full cost ceiling impairment of our natural gas and oil properties in Q1 2009.

(3)    Provision (benefit) for income taxes includes the ($349.5) million income tax benefit related to the full cost ceiling impairment of our natural gas and oil properties recorded in Q1 2009.

(4)    Depreciation, depletion and amortization includes the $907.8 million full cost ceiling impairment of our natural gas and oil properties recorded in Q1 2009.

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