All statements, other than historical facts and 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.

(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 34.

(Slide 6)
Areas of Operations

This slide contains a map of Arkansas, Louisiana, Oklahoma, Texas and Pennsylvania with shadings to denote the Ark-La-Tex region, the Fayetteville Shale and the Marcellus Shale.

Exploration & Production Segment

New Ventures

Fayetteville Shale

Ark-La-Tex

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 (in $ Millions):

Additionally, this slide contains a pie chart of the company's planned 2012 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 September 30, 2012 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.

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

* SWN discovered the Fayetteville Shale and has first mover advantage – average acreage cost of $253 per acre with a 15% royalty and average working interest of 74%.

* We plan to drill approximately 460-470 operated wells in 2012.

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 – completed lateral length has increased 82% over the last four years while holding total well costs flat.

* Vertical integration and contiguous acreage position allow us significant economies of scale and operating flexibility.

(Slide 10)

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 September 30, 2012.

(1) EBITDA is a non-GAAP financial measure.  See explanation and reconciliation of EBITDA on page 34.

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

(Slide 11)

Marcellus Shale

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

(Slide 12)

Marcellus Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through September 30, 2012, 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 less than 9 stages (1 well), 9-12 stages (27 wells), and greater than 12 stages (22 wells).The production data is compared to 10 Bcf, 8 Bcf, 6 Bcf, and 4 Bcf typecurves from the company's reservoir simulation shale gas model. 

Additionally, this slide contains a line graph displaying gross production in MMcf/d for the Marcellus Shale from September 1, 2010 to September 30, 2012. Gross operated production of approx. 218 MMcf/d as of September 30, 2012.

Notes: Data as of September 30, 2012.

(Slide 13)
Brown Dense Exploration Project

This slide displays the location of 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 Lower Smackover Brown Dense map highlights oil fields within the following municipalities: Wesson, McKamie-Patton, Walker Creek, Dorcheat-Macedonia, Atlanta, Magnolia, Shuler, Lisbon, El Dorado, Shadow Bend, Champagnolle, and Ora.  The map also highlights gas fields within the following municipalities: Rodessa, Red Rock, Shangaloo, and Monroe.  Included in the Lower Smackover Brown Dense map is the location of SWN’s first well TA’d, second well Shut-in, third well WOP, fouth well vertical testing, fifth well vertical testing, and sixth well WOP.  

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

This slide displays the location of the Denver Julesburg Basin Exploration Project, located on the border of Colorado, Wyoming, Nebraska, and Kansas. The location of the Las Animas Arch, Ewertz Farm 1-58 #1-26 well (Testing), and Staner 5-58 #1-8 well (Testing) is denoted.

(Slide 15)

* Production target of 560-570 Bcfe in 2012 (estimated growth of ~13%).

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

(Slide 16)
The Road to V⁺

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

(Slide 17)
Appendix

(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 32 and 34.

(2)   Adjusted net income and adjusted diluted EPS in 2012 exclude a $855.5 million after-tax non-cash ceiling test impairment and the same measures 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 of adjusted net income and adjusted diluted EPS on page 33.

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

This slide contains a bar chart detailing gas hedges in place by quarter for 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 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).

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, 2009, 2010 and 2011.  APC - Anadarko Petroleum, APA - Apache, COG - Cabot Oil & Gas, CHK - Chesapeake Energy, XEC - Cimarex Energy, DNR - Denbury Resources, DVN - Devon Energy, EOG - EOG Resources, FST - Forest Oil, MRO - Marathon Oil, MUR - Murphy Oil, NFX - Newfield Exploration, NBL - Noble Energy, OXY - Occidental Petroleum, PXD - Pioneer Natural Resources, RRC - Range Resources, SD - Sandridge Energy, SM - SM Energy, SWN - Southwestern Energy, UPL - Ultra Petroleum.

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.

Ark-La-Tex 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 2011, summarized as follows:

Arkoma Basin

Acreage: 194,494 net acres (at 12/31/11)

2011 Reserves: 194 Bcf (3% of total)

2011 Production: 16.3 Bcf (3% of total)

East Texas

Acreage: 91,082 net acres (at 12/31/11)

2011 Reserves: 253 Bcfe (4% of total)

2011 Production: 23.5 Bcfe (5% of total)

* Sold Overton Field in May 2012 (24 MMcfe/d and 143 Bcfe).

Notes: Conventional Arkoma acreage excludes 125,056 net acres in the conventional Arkoma Basin operating area that are also within the company’s Fayetteville Shale focus area.

Overton Field production as of May 2012; total reserves as of December 2011.

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. 

Fayetteville Shale - Horizontal Well Performance

Note: Data as of September 30, 2012.

Additionally, this slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2006 to September 2012. Gross operated production of approx. 2,011 MMcf/d as of September 30, 2012.  Periods of production affected by pipeline curtailment issues are denoted.

* Gross operated production of approx. 2,011 MMcf/d as of September 30, 2012. 

* 2011 Fayetteville Shale F&D cost of $1.13/Mcf.

Fayetteville Shale - Horizontal Well Performance

The graph contained in this slide provides average daily production data through June 30, 2012, 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, 2012. Excludes wells with mechanical problems (31).

Drilling & Completion Major Cost Categories

Average 2012 Fayetteville Shale Well Cost Estimate

This slide displays the estimated average 2012 major well cost categories as a proportion to the total average well costs.

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

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)

25% Recycle/Reused Water SGW, FBW, & PW

75% Surface Water

A box accompanying the graphs states:

SWN Operations Less than 0.09% of State’s water demand

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)

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 28)
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 29)

U.S. Electricity Generation

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

Total 4,100 Billion kWh in 2011.

Additionally, this slide contains a chart displaying a comparison of Electricity Generation Capacities in 2010 compared to Trailing 12 Months Generation.

While coal and nuclear power plants operate at very high capacity, natural gas power plants are only running at 33% of their capacity.

Source: EIA

(Slide 30)
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 31)
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 1997 to present.

Source:  Bloomberg

(Slide 32)

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 33)

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.

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

(Slide 34)

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 2012, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2012, including current hedges in place:

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