EXHIBIT 99.1

Slide Presentation dated August 2011

(Cover)
Southwestern Energy

August 2011 Update

NYSE: SWN

The left side of this slide contains a photograph of a thin section of rock taken at 100 times magnification.  The caption of the photograph reads "Core Value +."  The company's formula is located in the bottom right corner of the picture.  The top-right corner of this slide contains the company logo.

(Slide 1)
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 August 4, 2011

Investor Contacts

Greg D. Kerley
Executive Vice President and Chief Financial Officer

Brad D. Sylvester, CFA
Vice President, Investor Relations

(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 fund the company’s planned capital investments; 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 impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over the counter derivatives; the costs and availability of oilfield personnel, services and drilling supplies, raw materials, and equipment, including pressure pumping equipment and crews; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation; the company’s future property acquisition or divestiture activities; the impact of the adverse outcome of any material litigation against the company; the effects of weather; increased competition and regulation; 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 August 4, 2011.

(Slide 3)
About Southwestern

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

(Slide 4)
Recent Developments

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.

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 36.

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

Conventional Arkoma

Fayetteville Shale

East Texas

Marcellus Shale

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:

This slide also contains a pie chart of the company's planned 2011 capital investments by area of operation, summarized as follows:

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

(Slide 8)
Fayetteville Shale Focus Area

This slide contains a map of the Fayetteville Shale Focus Area in Arkansas.  Well locations for all wells drilled from inception of the play through June 30, 2011 are indicated on the map by initial production rate in the following ranges: less than or equal to 3MMcf/d, greater than 3MMcf/d and greater than 6MMcf/d.  The Mississippi Embayment is also indicated on the map.

* At December 31, 2010, SWN held approximately 916,000 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 the first half of 2011, SWN placed 286 operated wells on production, all of which were horizontal wells fracture stimulated with slickwater.

* We plan to drill approximately 470-480 operated wells in 2011.

Notes:    Rates are AOGC Form 13 and Form 3 test rates.     

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

(Slide 9)
Fayetteville Shale – Continuous Improvement

* Continuous improvement in our Fayetteville Shale operations.

* Current remaining inventory of over 8,000 net wells on approximately 600,000 net acres drilled to date, greater than 15 years of drilling at current pace.

* Contiguous acreage position allows us economies of scale, vertical integration and operating flexibility.

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

(Slide 10)
Fayetteville Shale - Horizontal Well Performance

Note: Data as of June 30, 2011.

(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.  

(2)    In the first quarter of 2010, the company’s results were impacted by the shift of all wells to “green completions” and the mix of wells, as a large percentage of wells were placed on production in the shallower northern and far eastern borders of the company’s acreage.

(Slide 11)
Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through June 30, 2011, for the company's horizontal wells drilled in the Fayetteville Shale.  This graph displays four composite curves, one composite curve showing the SW/XL normalized production from all the company's horizontal wells and three composite curves showing the results of the company's horizontal wells with laterals greater than 3,000 feet, greater than 4,000 feet, and greater than 5,000 feet. The production data is compared to 2 Bcf, 3 Bcf, and 4 Bcf typecurves from the company's reservoir simulation shale gas model.  Well counts and respective days of production are also displayed, as follows:

Note:  Data as of June 30, 2011. Excludes wells with mechanical problems (31). 

(Slide 12)
Fayetteville Shale - Gross Production

This slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2006 to June 30, 2011. Gross operated production of approx. 1,775 MMcf/d as of June 30, 2011.  2010 Fayetteville Shale F&D cost of $0.86/Mcf.  Periods of production affected by pipeline curtailment issues are denoted.

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

(Slide 13)
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.

Note:  Map as of June 30, 2011.

(1) EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 36.

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

(Slide 14)

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 test wells are shown on the map: Greenzweig, Range Trust, Price and Lycoming.  Lines trace the Transco, Tennessee Gas, Millennium and Stagecoach transmission pipelines.

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

(Slide 15)

Marcellus Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through June 30, 2011, for the company's horizontal wells drilled in the Marcellus Shale.  This graph displays a composite curve showing the results of the company's horizontal wells with lateral lengths greater than 3,000 feet and another composite curve for a well with a lateral length less than 3,000 feet. The production data is compared to 8 Bcf, 6 Bcf, and 4 Bcf typecurves from the company's reservoir simulation shale gas model. 

Notes:

Data as of June 30, 2011.

Red curve represents production from one well.

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

(Slide 16)
New Ventures – Brown Dense Project

This slide displays the Lower Smackover Brown Dense play, located on the border of Arkansas and Louisiana, in comparison to East Texas, Arkoma Basin, and Fayetteville Shale plays.  The map of the Lower Smackover Brown Dense highlights the following oil fields: Wesson, McKamie-Patton, Walker Creek, Dorcheat-Macedonia, Atlanta, Magnolia, Shuler, Lisbon, El Dorado, Shadow Bend, Champagnolle, Smackover, and Ora.  The map also highlights the following gas fields: Rodessa, Shangaloo-Red Rock, and Monroe.  Included in the Lower Smackover Brown Dense map is the location of SWN’s first well to be drilled in Columbia County, Arkansas

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

(Slide 17)
New Ventures – 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 is 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 denoted on the map.  The 2010 2D Seismic Test locations of Doaktown and Killams Mills are also denoted on the map.

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

(Slide 18)
Outlook for 2011

* Production target of 483 - 491 Bcfe in 2011 (estimated growth of 20%).

 (1)     Net cash flow is net cash flow before changes in operating assets and liabilities.  Net cash flow and EBITDA are non-GAAP financial measures.  See explanation and reconciliation of non-GAAP financial measures on pages 34 and 36.

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

(Slide 19)
The Road to V⁺

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

(Slide 20)
Appendix

(Slide 21)
Financial & Operational Summary

(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 34 and 36.

(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 in 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 35.

(4)   Includes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.

 (Slide 22)
Gas Hedges in Place Through 2013

This slide contains a bar chart detailing gas hedges in place by quarter for year 2011, year 2012 and year 2013.  A summary of these gas hedges is as follows:

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

(Slide 23)

SWN is One of the Lowest Cost Operators

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

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

Source:     Public filings

Note:

All data as of December 31, 2008, 2009, and 2010.

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, improved recovery, revisions and purchases.

 (Slide 24)

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 more than 6-year period and the Barnett Shale over a more than 27-year period.  Total Fayetteville Shale Field average daily production for March 2011 was 2,433 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 25)

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

Fayetteville Shale Play

*Q2 2004 – 1^st Well Drilled

*Q1 2005 – 1^st Horizontal Well Drilled

*Q3 2005 – 1^st Slickwater Frac

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

(Slide 26)

Water Demand: Perspective

The graphs contained in this slide compare the daily statewide demand for water in Arkansas by source to the average daily amount used by Southwestern Energy by source.

Statewide Demand:

11,500 million gallons/day

33% Ground Water

66% Surface Water

SWN Operations Demand:

10 million gallons/day (600 Wells/year)

20% Recycle/Reused Water SGW, FBW, & PW

80% Surface Water

A box accompanying the graphs states:

SWN Operations Less than 0.5% of State’s water demand

* In Arkansas, 43,000 million gallons/day is generated in runoff.

* Capturing more surface water by building ponds utilizes water that would otherwise be lost.

Source: U.S. Geological Survey, Central Arkansas Water, Southwestern Energy Company estimates.

Shallow Ground Water (SGW) – Ground water recovered from shallow formations during the air drilling process.  

Flow Back Water (FBW) – Frac Fluid that is recovered from the well after the fracture stimulation.  

Produced Water (PW) – Natural formation water that is returned to the surface throughout the producing life of the well.

(Slide 27)

Drilling & Completion Major Cost Categories

Average 2011 Fayetteville Shale Well Cost Estimate

This slide displays the estimated average 2011 major well cost categories as a proportion to the total average well costs.

(Slide 28)

ArkLaTex Division

This slide contains a map of the ArkLaTex Division, which is composed of East Texas and Arkoma Basin, in relation to Texas, Oklahoma, Arkansas, and Louisiana. The slide also contains two graphs outlining the production, capital expenditures, and reserves for East Texas and Arkoma Basin for the period extending from 2000 to 2010, summarized as follows:

Arkoma Basin

Acreage: 308,123 net acres (at 12/31/10)

2010 Reserves: 226 Bcf (4% of total)

2010 Production: 19.2 Bcf (5% of total)

East Texas

Acreage: 125,563 net acres (at 12/31/10)

2010 Reserves: 328 Bcf (7% of total)

2010 Production: 34.3 Bcf (8% of total)

Note: Conventional Arkoma acreage excludes 124,986 net acres in the conventional Arkoma Basin operating area that are also within the company’s Fayetteville Shale focus area.

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 production rising in recent years.

Source: EIA

(Slide 30)
U.S. Electricity Consumption

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

Source:  Edison Electric Institute

(Slide 31)

U.S. Electricity Generation

This slide contains a chart showing Electricity Generation by Energy Source as a percentage of total.

Total 4,120 Billion kWh in 2010.

Source: EIA

Additionally, this slide contains a chart displaying a comparison of Electricity Generation Capacities in 2009 compared to Electricity Generated in 2010.

While coal and nuclear power plants operate at very high capacity, natural gas power plants are only running at 24% of their capacity.

*Excludes standby units

Source: EIA

(Slide 32)
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 33)
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 34)

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.

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

(Slide 35)
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.

(Slide 36)

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.

The table below reconciles forecasted EBITDA with forecasted net income for 2011, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2011, including current hedges in place:

(1)  Midstream Services segment results assume NYMEX commodity prices of $4.50 per Mcf for natural gas and $70.00 per barrel for crude oil for 2011.

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