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.

The contents of this presentation are current as of February 22, 2013.

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

(Slide 4)
2012 Highlights and 2013 Outlook

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 excludes reserve revisions and 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 December 31, 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 $313 per acre with a 15% royalty and average working interest of 74%.

*  We plan to drill approximately 385-390 operated wells in 2013.

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 holding total well costs decreased 14%.

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

Note: Finding and development costs exclude revisions and capital investments in our sand facility, drilling rig related and ancillary equipment.

(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 December 31, 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 December 31, 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 (4 well), 9-12 stages (40 wells), and greater than 12 stages (27 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 December 31, 2012. Gross operated production of approx. 300 MMcf/d as of December 31, 2012.

Notes: Data as of December 31, 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 and gas fields within the project. The map also displays SWN drilled wells, SWN 2013 Plan, and OBO wells. Included in the Lower Smackover Brown Dense map is the location of SWN’s first well Roberson (TA’d) Peak of 103 bo and 180 Mcf,  second well Garret (Shut-in) Peak of 301 bo of 1,720 Mcf, third well BML peak of 421 bo and 3,900 Mcf, fouth well Johnson-Vert (shut in after flowback) fifth well Dean- vertical testing peak of 214 bo and 1,207 Mcf,, and sixth well DolesPeak of 435 bo and 2,500 Mcf.

(Slide 14)
Denver Julesburg Basin Exploration Project

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  (shut-in), and Staner 5-58 #1-8H well (drilling Hz) is denoted.

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

(Slide 15)
Outlook for 2013

*  Production target of 628-640 Bcfe in 2013 (estimated growth of ~12%).

(3)    2012 projected book capitalization includes the effect of the $1,192.4 million (after-tax) non-cash ceiling test impairments recorded in 2012.

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.

(2)   Adjusted net income and adjusted diluted EPS in 2012 exclude $1,192.4 million (after-tax) in non-cash ceiling test impairments and $0.2 million (after-tax) unrealized gain on derivative contracts. Both are non-GAAP financial measures.

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

(Slide 19)
Gas Hedges in Place Through 2014

This slide contains a bar chart detailing gas hedges in place by quarter for year 2013 and year 2014.  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.

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 (sold Overton field in 2012) and Arkoma Basin for the period extending from 2000 to 2012, summarized as follows:

Arkoma Basin

Acreage: 114,287 net acres (at 12/31/12)

2012 Reserves: 160 Bcf (4% of total)

2012 Production: 14.1 Bcf (2% of total)

East Texas

Acreage: 49,340 net acres (at 12/31/12)

2012 Reserves: 53 Bcfe (1% of total)

2012 Production: 11.4 Bcfe  (2% of total)

Notes:  Conventional Arkoma acreage excludes 124,653 net acres in the conventional Arkoma Basin operating area that are also within the company’s Fayetteville Shale focus area.

(Slide 22)
New Brunswick, Canada Exploration 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.    

Fayetteville Shale - Horizontal Well Performance

Note: Data as of December 31, 2012.

Additionally, this slide contains a line graph displaying gross production in MMcf/d for the Fayetteville Shale from January 2006 to January 2013.  Gross operated production of approx. 2,090 MMcf/d as of December 31, 2012.  Periods of production affected by pipeline and heat related curtailment issues are denoted.

*  Gross operated production of approx. 2,090 MMcf/d as of December 31, 2012. 

*  2012 Fayetteville Shale F&D cost of $2.53/Mcf.

Fayetteville Shale - Horizontal Well Performance

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

Drilling & Completion Major Cost Categories

Average 2013 Fayetteville Shale Well Cost Estimate

This slide displays the estimated average 2013 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".

(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)

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 usage.

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.

(Slide 34)

Explanation and Reconciliation of Non-GAAP Financial Measures: EBITDA

The table below reconciles forecasted EBITDA with forecasted net income for 2013, assuming various NYMEX price scenarios and the corresponding estimated impact on the company's results for 2013, including current hedges in place:

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