EXHIBIT 99.1

Slide Presentation dated April 2010

(Cover)
Southwestern Energy

April 2010 Update

NYSE: SWN

The left side of this slide contains a photograph of a rock climber scaling a steep cliff with a mountain range in the background.  The caption above reads "High adventure."  The company's formula is located in the left side of the picture.  The top-right corner of this slide contains the company logo.

(Slide 1)
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 impact of federal, state and local government regulation, including any legislation relating to hydraulic fracturing, the climate or over the counter derivatives; 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; 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.

The contents of this presentation are current as of April 1, 2010.

(Slide 2)
Southwestern Energy Company

General Information

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

Market Data as of March 31, 2010

NYSE: SWN
Shares of Common Stock Outstanding	346,087,780
Market Capitalization	$14,092,000,000
Institutional Ownership	87.5%
Management Ownership	3.0%
52-Week Price Range	$29.69 (3/31/09) - $51.65 (1/05/10)

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 3)
About Southwestern

* Focused on domestic exploration and production of natural gas.
	* 3,657 Bcfe of reserves; ~100% natural gas; 12.2 R/P at year-end 2009.
* E&P strategy built on organic growth through the drillbit.
	* Over 75% of planned E&P capital allocated to drilling in 2010.
* Track record of adding significant reserves at low costs.
	* From 2004 through 2009, we've averaged over 40% annual production and reserve growth and annually replaced over 500% of our production at a F&D cost of $1.46 per Mcfe.
* Proven management team has increased Southwestern's market capitalization from $187 million at year-end 1998 to approximately $14 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

*  2009 Highlights
	*  Production of 300.4 Bcfe, up 54%.
	*  Reserves of 3.7 Tcfe, up 67%
	*  Discretionary cash flow(1) of $1.4 billion, up 23%.
	*  Finding and development cost of $0.86 per Mcfe (including reserve revisions).
	*  Significant progress realized in our Fayetteville Shale play.
		*  Gross operated production from Fayetteville Shale was approximately 1.2 Bcf per day in February 2010, up from 750 MMcf a year ago.

* Strong Growth and Low-Cost Operations Set the Stage for a Record 2010
	* 2010 planned capital investment program of approximately $2.1 billion, up 16% from 2009 levels.
	* 2010 gas and oil production projected to grow approximately 35% to 400 - 410 Bcfe.
	* Balance sheet positioned well for 2010, as of December 31, 2009:
		* Debt-to-book capital ratio of 30%; debt-to-market capitalization ratio of 6%.
		* $1 billion credit facility with $325 million drawn at an average interest rate of 1.1%.

(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 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	2009	2010
Production (Bcfe)	36	40	40	41	54	61	72	113	195	300	400-410E
Reserve Replacement (%)	211%	155%	215%	313%	364%	399%	386%	474%	523%	592%
EBITDA ($MM) (1)	$104	$134	$99	$151	$255	$346	$415	$675	$1,362	$1,368
F&D Cost ($/Mcfe)	$0.92	$1.59	$0.99	$1.32	$1.43	$1.70	$2.72	$2.55	$1.53	$0.86

Note: Reserve data includes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.

(1)    EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 30.

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 & Production Segment

* 2009:	3,657 Bcfe of Reserves
	~100% Natural Gas
	Production - 300.4 Bcfe
* 2010 Est. Production: 400-410 Bcfe

Conventional Arkoma

* Reserves: 208 Bcf (6%)

* Production: 22.0 Bcf (7%)

* Net Acres: 338,486 (12/31/09)

Fayetteville Shale

* Reserves: 3,117 Bcf (85%)

* Production: 243.5 Bcf (81%)

* Net Acres: 888,695 (12/31/09)

East Texas

* Reserves: 330 Bcfe (9%)

* Production: 34.9 Bcfe (12%)

* Net Acres: 115,199 (12/31/09)

Marcellus Shale

* Net Acres: 149,317 (12/31/09)

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

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

Notes:	2009 reserve data by area does not add to year-end totals for the company due to the exclusion of Marcellus Shale reserves.
	Conventional Arkoma acreage excludes 125,402 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:

							2010
	2004	2005	2006	2007	2008	2009	Plan
	(in millions)
Corporate & Other	$13	$16	$32	$16	$17	$29	$80
Property Acquisitions	$14	$ -	$18	$ 2	$ -	$ 4	$ -
Cap. Expense & Other E&P	$18	$32	$62	$77	$153	$190	$220
Leasehold & Seismic	$21	$61	$70	$166	$149	$114	$205
Development Drilling	$209	$287	$421	$1,110	$1,255	$1,254	$1,220
Exploration Drilling	$20	$36	$196	$20	$39	$4	$105
Midstream Services	$ -	$16	$49	$107	$183	$214	$270
Drilling Rigs	$ -	$35	$94	$ 5	$ -	$ -	$ -
Total	$295	$483	$942	$1,503	$1,796	$1,809	$2,100

This slide also contains a pie chart of the company's planned 2010 capital investments by area of operation, summarized as follows:

	% of Total
	Capital Investments
Arkoma Fayetteville Shale	57%
Midstream	13%
East Texas	11%
Appalachia	7%
New Ventures	6%
Corp/Other	5%
Arkoma	1%

* E&P capital program heavily weighted to low-risk development drilling in 2010.

* Plan to invest approximately $1.5 billion in the Fayetteville Shale play in 2010.

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 and Louisiana and certain well production data.  The company's Overton and Angelina River Trend acreage positions and the DVN Well are highlighted.  The James Lime Horizontals, the Haynesville/Middle Bossier Horizontals, the Haynesville Shale Prospective Area and the East Texas Salt Basin are also denoted on the map.  The city of Tyler, Texas is displayed as a reference point.

James Lime Horizontals
43 Operated Wells
Avg IP Rate - 9.8 MMcf/d
Haynesville/Middle Bossier Horizontal Well IPs
First Well:	7.2 MMcf/d
Second Well:	13.4 MMcf/d
Third Well:	16.7 MMcf/d
Fourth Well:	21.0 MMcf/d
Fifth Well:	18.1 MMcf/d
Sixth Well:	11.3 MMcf/d
Seventh Well:	22.1 MMcf/d

CHK	HK	Other Wells
120 Wells	66 Wells	95 Wells
Avg IP: 10.6 MMcf/d	Avg IP: 17.0 MMcf/d	Avg IP: 8.0 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 135,400 gross acres at Angelina.
* Drilled seven horizontal wells targeting the Haynesville/Middle Bossier Shale intervals (approximately 42,300 net acres).
* 2010 capital program includes participation in approximately 50-60 wells, 22-27 of which will be operated.
	* 21-26 wells targeting the Haynesville or Middle Bossier Shales; 29-34 wells targeting the James Lime, Pettet or Cotton Valley formations.

Sources: Southwestern Energy Company, RBC Capital Markets

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

(Slide 9)

Marcellus Shale

This slide contains a map of several counties in Pennsylvania and New York and certain well production data.  The company's acreage positions are highlighted.  The locations of the company's four test wells are shown on the map: Greenzweig (2 wells), Range Trust and Price.  Lines trace the Dominion, Tennessee Gas, Millennium and Stagecoach transmission pipelines.

Other test wells and areas are located on the map with their respective production data:

Cabot

30 wells drilled, 14 producing

30 day avg = 6.9 MMcf/d

CHK

10.1 MMcf/d

8.9 MMcf/d

RRC

>13.0 MMcf/d (2 hzls)

6.3 MMcf/d (vertical)

5.0 MMcf/d (vertical)

Other Test Wells

4.5 MMcf/d

4.0 MMcf/d

* Currently hold approximately 149,000 net acres in Northeast Pennsylvania with Marcellus potential with an average lease term of 5 years, average royalty of 13% and average cost of approximately $594 per acre.

* Drilled 4 wells to date (3 vertical, 1 horizontal) with positive results.

* Drilling in 2010 with one operated rig in Greenzweig area and plan to participate in 35-40 wells, 21-24 of which are planned to be operated.

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

(Slide 10)
New Brunswick, Canada Project

This slide contains a map of the Province of New Brunswick, Canada.  The acreage on which the company has obtained licenses to explore are highlighted on the map: Marysville (2,309,247 acres) and Cocagne (209,271 acres).  The McCully Field, Stoney Creek Field, M&NE Pipeline and the Green Road G-41 well are also denoted on the map.

* SWN currently holds exploration licenses to over 2.5 million acres within the Maritimes Basin
* Principal targets are the conventional and unconventional sandstone and shale reservoirs of the Horton Group
* Oil and gas production from fields along southern flank:
	* McCully - reserves 190 bcfg
	* Stoney Creek - cum 800,000 bo, 30 bcfg
* 3-year initial exploration license to complete work program
	* $47MM total work commitment with yearly rentals of $1.55 per acre
	* Options for multiple 5-year extension leases
	* Maximum 12.5% royalty

(Slide 11)
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. 763,293 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, Boardwalk, NGPL, MRT and TETCO transmission pipelines. Fayetteville Lateral Compression in-service January 2010.

* SWN currently holds approximately 889,000 net acres in the Fayetteville Shale play area (equivalent to approximately 1,400 square miles).

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

* In 2009, we drilled and completed 500 operated wells, all of which were horizontal wells fracture stimulated with slickwater.

* We anticipate participating in 650-680 wells in 2010, 475-500 of which we plan to operate.

Notes:    Data as of December 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 12)
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
1st Qtr 2007	58	1,261	1,066 (58)	958 (58)	2,104
2nd Qtr 2007	46	1,497	1,254 (46)	1,034 (46)	2,512
3rd Qtr 2007	74	1,769	1,510 (72)	1,334 (72)	2,622
4th Qtr 2007	77	2,027	1,690 (77)	1,481 (77)	3,193
1st Qtr 2008	75	2,343	2,147 (75)	1,943 (74)	3,301
2nd Qtr 2008	83	2,541	2,155 (83)	1,886 (83)	3,562
3rd Qtr 2008	97	2,882	2,560 (97)	2,349 (97)	3,736
4th Qtr 2008(1)	74	3,350(1)	2,722 (74)	2,386 (74)	3,850
1st Qtr 2009(1)	120	2,992(1)	2,537 (120)	2,293 (120)	3,874
2nd Qtr 2009	111	3,611	2,833 (111)	2,556 (111)	4,123
3rd Qtr 2009	93	3,604	2,640 (92)	2,275 (92)	4,100
4th Qtr 2009	122	3,757	2,679 (121)	2,421 (85)	4,303

* Focusing on longer laterals, slick-water completions and larger frac jobs.  Average completed well cost for 2009 was $2.9 million.

* Over 98% of our 2010 planned wells will have the benefit of 3-D seismic (versus 70% in 2008).

Note: Data as of December 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 3,353 Mcf per day.

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

(Slide 13)
Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through December 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	Horizontal Wells with Laterals > 3,000 Feet	Horizontal Wells with Laterals > 4,000 Feet
30	1,031	746	283
60	988	698	250
120	912	627	208
180	852	571	175
240	800	527	151
300	724	450	106
360	628	356	78
420	564	299	52
480	513	255	39
540	469	212	27
600	423	172	17
660	374	126	5
720	320	86	4
780	279	62	1
840	245	33	1
900	194	17	0
960	155	7	0
1020	133	1	0
1080	89	1	0
1140	59	0	0
1200	38	0	0
1260	26	0	0
1320	11	0	0
1380	4	0	0
1440	1	0	0
1500	1	0	0

Notes:	Data as of December 31, 2009 and excludes wells with mechanical problems (28).
	"Wells with Laterals > 3,000 Feet" curve excludes the last 184 days of production for the Guinn 09-15 #2-06H due to positive response to offset frac which may not be typical.

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

(Slide 14)
Fayetteville Project - Gross Production

This slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2006 to February 20, 2010. Gross operated production of approx. 1,188 MMcf/d as of February 20, 2010.  2009 Fayetteville Shale F&D cost of $0.69/Mcf.  Periods of production affected by pipeline curtailment issues are denoted.

(Slide 15)
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 December 31, 2009, gathering approximately 1,304 MMcf per day through 1,137 miles of gathering lines, up from approximately 802 MMcf per day the same time a year ago.

* 2009 Midstream EBITDA⁽¹⁾ of $142 million and $180 - $185 million projected for 2010.

* Phase 1 Fayetteville Lateral of Boardwalk Pipeline placed in-service late December 2008.  Phase 2 Greenville Lateral placed in-service April 2009.  Phase 3 Fayetteville Lateral compression project placed in-service January 2010.

* Fayetteville Express Pipeline expected in-service late 2010 / early 2011 (FT volumes of 1,200,000 dkth/d).

Note:  Map as of December 31, 2009.

(1) EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 30.

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

(Slide 16)
Outlook for 2010

* Production target of 400 - 410 Bcfe in 2010 (estimated growth of ~35%).

	2009	2010 Guidance
	Actual	NYMEX Price Assumption
	$3.99 Gas	$4.00 Gas	$5.00 Gas	$6.00 Gas
	$58.36 Oil	$70.00 Oil	$70.00 Oil	$70.00 Oil
Adj. Net Income	$522.7 MM(1)	$435 - $445 MM	$640 - $650 MM	$845 - $855 MM
Adj. Diluted EPS	$1.52(1)	$1.24 - $1.27	$1.83 - $1.86	$2.41 - $2.44
EBITDA(2)	$1,368 MM	$1,365 - $1,375 MM	$1,690 - $1,700 MM	$2,010 - $2,020 MM
Net Cash Flow (2)	$1,441 MM	$1,355 - $1,365 MM	$1,680 - $1,690 MM	$1,990 - $2,000 MM
CapEx	$1,809 MM	$2,100 MM	$2,100 MM	$2,100 MM
Debt %	30%(3)	37% - 39%	29% - 31%	24% - 26%

(1)     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 29.

(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 28 and 30.

(3)    2009 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 17)
The Road to V⁺

* Invest in the Highest PVI Projects.
* Flexibility in 2010 Capital Program.
* 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 18)
Appendix

(Slide 19)
Financial & Operational Summary

	Year Ended December 31,
	2009	2008	2007
	($ in millions, except per share amounts)
Revenues	$2,145.8	$2,311.6	$1,255.1
EBITDA (1)	1,368.1(3)	1,362.3(2)	675.4
Adjusted Net Income	522.7(3)	567.9(2)	221.2
Net Cash Flow (1)	1,441.0	1,167.5	651.2
Adjusted Diluted EPS	$1.52(3)	$1.64(2)	$0.64(4)
Diluted CFPS (1)	$4.13	$3.37	$1.87(4)
Production (Bcfe)	300.4	194.6	113.6
Avg. Gas Price ($/Mcf)	$5.30	$7.52	$6.80
Avg. Oil Price ($/Bbl)	$54.99	$107.18	$69.12
Finding Cost ($/Mcfe) (5)	$0.86	$1.53	$2.55
Reserve Replacement (%) (5)	592%	523%	474%

(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 28 and 30.

(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 (while EBITDA excludes the pre-tax non-cash ceiling test impairment of $907.8 million).  See explanation and reconciliation of adjusted net income and adjusted diluted EPS on page 29.

(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 our sand facility, drilling rig related and ancillary equipment.

(Slide 20)
Gas Hedges in Place Through 2011

This slide contains a bar chart detailing gas hedges in place by quarter for year 2010 and year 2011.  A summary of these gas hedges is as follows:

			Average Price per Mcf	Percent
	Type	Hedged Volumes	(or Floor/Ceiling)	Hedged
2010	Swaps	36.0 Bcf	$9.04	9%
	Collars	30.0 Bcf	$6.80 / $8.43	7%
2011	Swaps	30.0 Bcf	$6.69	-
	Collars	7.3 Bcf	$5.75 / $7.06	-

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

(Slide 21)

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	$0.93
EOG Resources	$1.04
Noble Energy	$1.05
Ultra Petroleum	$1.08
Chesapeake Energy	$1.22
Range Resources	$1.23
Forest Oil	$1.25
Cabot Oil & Gas	$1.51
Devon Energy	$1.55
Quicksilver Resources	$1.56
Newfield Exploration	$1.57
Anadarko Petroleum	$1.68
Cimarex Energy	$1.73
Sandridge Energy	$1.80
Pioneer Natural Resources	$1.89
St. Mary Land & Exploration	$1.92
Apache	$1.97
Denbury Resources	$3.35

This slide also contains a bar graph comparing SWN to its competitors in terms of Finding & Development Cost per Mcfe (3 year average).

	Drillbit F&D Cost
	per Mcfe
	(3 year average)
Ultra Petroleum	$1.21
Southwestern Energy Company	$1.34
Range Resources	$1.93
EOG Resources	$1.93
Quicksilver Resources	$1.99
Denbury Resources	$2.30
Newfield Exploration	$2.52
Devon Energy	$2.54
Cabot Oil & Gas	$2.71
Anadarko Petroleum	$2.90
Forest Oil	$3.02
Chesapeake Energy	$3.36
Apache	$3.76
Pioneer Natural Resources	$3.99
Noble Energy	$4.10
Cimarex Energy	$4.19
Sandridge Energy	$7.56
St. Mary Land & Exploration	$7.79

Source:  John S. Herold Database and public filings.

Note:  All data as of December 31, 2007, 2008 and 2009.

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

F&D Cost per Mcfe defined as the three-year sum of costs incurred in natural gas and oil exploration and development divided by the three-year sum of reserve additions from extensions and discoveries, revisions and purchases.

(Slide 22)

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. 28 Vertical Wells/Year
1995-1999	Avg. 75 Vertical Wells/Year
2000	Vertical Wells Drilled Horizontal Wells Drilled	165 0
2001	Vertical Wells Drilled Horizontal Wells Drilled	408 1
2002	Vertical Wells Drilled Horizontal Wells Drilled	669 2
2003	Vertical Wells Drilled Horizontal Wells Drilled	663 70
2004	Vertical Wells Drilled Horizontal Wells Drilled	524 260
2005	Vertical Wells Drilled Horizontal Wells Drilled	351 701
2006	Vertical Wells Drilled Horizontal Wells Drilled	276 1,214
2007	Vertical Wells Drilled Horizontal Wells Drilled	178 2,117
2008	Vertical Wells Drilled Horizontal Wells Drilled	145 2,508
2009E	Vertical Wells Drilled Horizontal Wells Drilled	60 1,513

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	14 0
2005	Vertical Wells Drilled Horizontal Wells Drilled	37 13
2006	Vertical Wells Drilled Horizontal Wells Drilled	12 103
2007	Vertical Wells Drilled Horizontal Wells Drilled	13 419
2008	Vertical Wells Drilled Horizontal Wells Drilled	14 690
2009E	Vertical Wells Drilled Horizontal Wells Drilled	3 895

Source: Republic Energy Co., PI-Dwights (IHS Energy), Southwestern Energy

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

(Slide 23)

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 5-year period and the Barnett Shale over a more than 25-year period.  Total Fayetteville Shale Field average daily production for November 2009 was 1,798 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 24)

U.S. Gas Consumption and Sources

This slide displays U.S. dry 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 25)
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 26)
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 27)
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 28)

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.

	12 Months Ended December 31,
	2009	2008	2007
	(in thousands)
Net cash provided by operating activities	$1,359,376	$1,160,809	$622,735
Add back (deduct):
Change in operating assets and liabilities	81,652	6,685	28,435
Net cash flow	$1,441,028	$1,167,494	$651,170

	2010 Guidance
	NYMEX Commodity Price Assumption
	$4.00 Gas	$5.00 Gas	$6.00 Gas
	$70.00 Oil	$70.00 Oil	$70.00 Oil
	($ in millions)
Net cash provided by operating activities	$1,355 - $1,365	$1,680 - $1,690	$1,990 - $2,000
Add back (deduct):
Assumed change in operating assets and liabilities	--	--	--
Net cash flow	$1,355 - $1,365	$1,680 - $1,690	$1,990 - $2,000

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

(Slide 29)
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.

	12 Months Ended
	December 31, 2009
	($ in thousands)	(per share)
Net income (loss) attributable to SWN	$        (35,650)	$         (0.10)
Add back:
Impairment of natural gas and oil properties (net of taxes)	558,305	1.62
Adjusted net income	$       522,655	$           1.52

(Slide 30)

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.

	12 Months Ended December 31,
	2009(1)		2008	2007	2006	2005	2004	2003		2002	2001	2000
			($ in thousands)
Net income (loss) attributable to SWN	$(35,650)	(2)	$567,946	$221,174	$162,636	$147,760	$103,576	$48,897		$14,311	$35,324	$20,461	(6)
Add back:
Net interest expense	18,638		28,904	23,873	679	15,040	16,992	17,311		21,466	23,699	24,689
Provision (benefit) for income taxes	(16,363)	(3)	350,999	135,855	99,399	86,431	59,778	28,372	(5)	8,708	21,917	11,457
Depreciation, depletion and amortization	1,401,470	(4)	414,460	294,500	151,795	96,641	74,919	56,833		54,095	53,003	47,505
EBITDA	$1,368,095		$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 $73,950, depreciation, depletion and amortization was $19,213, net interest expense was $3,401 and provision for income taxes was $45,303.

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

(4)  Depreciation, depletion and amortization includes the $907.8 million non-cash 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 2010, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2010, including current hedges in place:

	2010 Guidance
	Overall Corporate
	NYMEX Commodity Price Assumption			Midstream
	$4.00 Gas	$5.00 Gas	$6.00 Gas	Services
	$70.00 Oil	$70.00 Oil	$70.00 Oil	Segment (1)
Net income (loss) attributable to SWN	$435 - $445	$640 - $650	$845 - $855	$80 - $84
Add back:
Provision (benefit) for income taxes	271 - 277	395 - 401	518 - 524	49 - 52
Interest expense	21 - 22	19 - 20	16 - 17	11 - 12
Depreciation, depletion and amortization	625 - 630	625 - 630	625 - 630	38 - 39
EBITDA	$1,365 - $1,375	$1,690 - $1,700	$2,010 - $2,020	$180 - $185

(1)    Midstream Services segment results assume NYMEX commodity prices of $5.00 per Mcf for natural gas and $70.00 per barrel for crude oil for 2010.

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