### UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549



# Form 10-K

[X] Annual Report pursuant to Section 13 or 15( d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2012

Commission file number 1-08246


# Southwestern Energy Company

(Exact name of registrant as specified in its charter)

Delaware 71-0205415 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.)

2350 North Sam Houston Parkway East, Suite 125, Houston, Texas 77032 (Address of principal executive offices) (Zip Code)

(281) 618-4700 (Registrant’s telephone numbe r, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class Name of each exchange on which registered Common Stock, Par Value $0.01 New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  No 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Ye s  No 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Secu rities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been su bject to such filing requirements for the past 90 days. Yes  No 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Re gulation S-T (§ 232.405 of this chapte r) during the preceding 12 months (or for s uch shorter period that the registrant was required to submit and post such files). Yes  No 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will no t be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act

.

Large accelerated filer  Accelerated filer  N on-accelerated filer  Smaller reporting company 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes  No 

The aggregate market value of the voting stock held by non-affiliates of the registrant was $ 10,933,390,189 based on the New Y ork Stock Exchange

– Composite Transactions closing price on June 29, 2012 of $31.93. For purposes of this calculation, the registrant has assumed t hat its directors and executive

officers are affiliates.

As of February 15, 2013, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 351,097,392.

Document Incorporated by Reference Portions of the registrant’s definitive proxy statement to be filed with respect to the annual meeting of stockholders to be he ld on or about May 21, 2013 are incorporated by reference into Part III of this Form 10-K.1 SOUTHWESTERN ENERGY COMPANY

ANNUAL REPORT ON FORM 10-K For Fiscal Year Ended December 31, 2012

TABLE OF CONTENTS Page

PART I

Item 1. Business 3 Glossary of Certain Industry Terms 21

Item 1A. Risk Factors 26

Item 1B. Unresolved Staff Comments 37 Item 2. Properties 37 Item 3. Legal Proceedings 42 Item 4. Mine Safety Disclosures 43

PART II Item 5. Market for Registrant’s Common Equity, Relate d Stockholder Matters and Issuer Purchases of Equity
Securities 44

Stock Performance Graph 45

Item 6. Selected Financial Data 46 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 48

Overview 48 Results of Operations 50 Liquidity and Capital Resources 55 Critical Accounting Policies and Estimates 58 Cautionary Statement about Fo rward-Looking Statements 62 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 63 Item 8. Financial Statements and Supplementary Data 66

Index to Consolidated Financial Statements 66 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 111

Item 9A. Controls and Procedures 111

Item 9B. Other Information 111

PART III Item 10. Directors, Ex ecutive Officers and Corporate Governance 112 Item 11. Executive Compensation 113 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 113 Item 13. Certain Relationships and Related Transactions, and Director Independence 113 Item 14. Principal Accounting Fees and Services 114

PART IV Item 15. Exhibits, Financial Statement Schedules 114

EXHIBIT INDEX 1162 This Annual Report on Form 10-K includ es certain statements that may be deem ed to be “forward-looking” within the meaning of Section 27A of the Securities Act of 1933, or th e Securities Act, and Section 21 E of the Securities Exchange Act of 1934, or the Exchange Act. We refer you to “Risk Factors” in Item 1A of Part I and to “Management’s Discussion and Analysis of Financial Condition and Results of Oper ations — Cautionary Statement about Forward-Looking

Statements” in Item 7 of Part II of this Form 10-K for a discussion of factors that could cause actual results to differ materially from any such forw ard-looking statements. The electronic version of this Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those forms filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge as soon as reasonab ly practicable after they are filed with the Securities and Exchange Co mmission, or SEC, on our website at www.swn.com. Our corporate governance guidelines and the charters of the Audit, Compensation, Nominating and Governance and Retirement Committees of our

Board of Directors are available on our webs ite, and are available in print free of ch arge to any stockholder upon request.

We file periodic reports and proxy statements with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.3 ITEM 1. BUSINESS

Southwestern Energy Company is an independent energy company engaged in natural gas and oil exploration, development and production (E&P). We are also focused on creating and capturing additiona l value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services.

Exploration and Production - Our primary business is the exploration for and production of natural gas and oil, with our current operations being principally focused within the United States on development of an unconventional natural gas reservoir located on the Arkansas side of the Arkoma Basin, wh ich we refer to as the Fayettev ille Shale play. We are also actively engaged in exploration and production activities in Pennsylvania, where we are targeting the unconventional natural gas reservoir known as the Marcellu s Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin. We also actively seek to find and develop new oil and natural gas plays with significant exploration and exploitation potential, which we refer to as “New Ventures.” We primarily conduct our exploration and production operations through our wholly-owned subsidiaries, SEECO, Inc., or SEECO, and Southwestern Energy Production Company, or SEPCO. SEECO operates exclusively in Arkansas where it holds a large base of both developed and undeveloped natural gas reserves, and conducts the Fayetteville Shale drilling program and the conventional Arkoma Basin operations in the Arkoma Basin. SEPCO conducts development drilling, exploration programs and production operations in Pennsylvania, Oklahoma, Texas, Arkansas and Louisiana. SWN Drilling Company, Inc., formerly known as DeSoto Drilling, Inc., a wholly-owned subsidiary of SEPCO, operates drilling rigs in Arkansas, Pennsylvania and Louisiana, as well as other operating areas. We also provide oilfield pro ducts and services through DeSoto Sand, L.L.C. and SWN Well Services, L.L.C., both of which are wholly-owned subsidiari es of SWN E&P Services, L.L.C. Our Canadian operations are conducted by our subsidiary, SWN Resources Canada Inc.

Midstream Services - We engage in natural gas gathering activities in Arkansas, Texas and Pennsylvania through our gathering subsidiaries, DeSoto Gathering Company, L.L.C ., or DeSoto Gathering, and Angelina Gathering Company, L.L.C., or Angelina Gathering. DeSoto Gathering and Angelina Gathering prim arily support our E&P operations and generate revenue from fees associated with gathering of na tural gas. Our natural gas marketing subsidiary, Southwestern Energy Services Company, or SES, captures downstr eam opportunities which arise through the marketing and transportation of the natural gas pr oduced in our E&P operations.

The vast majority of our operating income and earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA, is derived from our E&P business. In 2012, 64% of our operating income and 79% of our EBITDA were generated from our E&P business, absent our $1,939.7 million, or $1,192.4 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties, compared to 77% of our operating income and 84% of our EBITDA in 2011, and 81% of our operating income and 86% of our EBITDA in 2010. In 2012, 36% of our operating income and 21% of our EBITDA were generated from Midstream Services, absent the non-cash ceiling test impairment of our natural gas and oil properties, compared to 23% of our operating income and 16% of our EBITDA in 2011, and 19% of our operating income and 14% of our EBITDA in 2010. EBITDA is a non-GAAP measure. We refer you to “Business —
Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA to net income (loss).

Our Business Strategy

Since 1999, our management has been guided by our formula, which represents the essence of our corporate philosophy and how we operate our business:

Our formula, which stands for “The Right People doing the Right Things, wisely investing the cash flow from our underlying Assets will create Value+,” also guides our business strategy. We are focused on providing long-term growth in the net asset value of our business. In our E&P business, we prepare an economic analysis for each investment opportunity based upon the expected presen t value added for each dollar to be invest ed, which we refer to as Present ValueIndex, or PVI. The PVI for each project is determined using a 10% discount rate. We target creating at least $1.30 of pretax PVI for each dollar we invest in our E&P projects. Our actual PVI results are utilized to help determine the allocation of our future capital investments. The key elements of our business strategy are:

 Exploit and Develop Our Positions in the Faye tteville Shale and the Marcellus Shale Plays. Our primary focus is to maximize the value of our significant acrea ge position in the Fayetteville Shale play, which has provided significant4 production and reserve growth since we began drilling in the play in 2004. As of December 31, 2012, we held approximately 913,502 net acres in the Fayetteville Shale play, accounting for approximate ly 75% of our total proved oil and natural gas reserves and approximately 86% of our total oil and natural gas production during 2012. Additionally, we are actively drilling on portions of our 17 6,298 net acres in the Marcellus Shale and believe our production and reserves from this play w ill grow substantially over the next few years. We intend to further develop our acreage positions in the Fayetteville Shale and the Marcellus Shale plays and improve our well results through the use of advanced technologies and detailed technical analysis of our properties.

 Grow through New Exploration and Development Activities Focusing on Emerging Unconventional Plays . We actively seek to find and develop new oil and natural gas plays with significant exploration and exploitation potential,
which we refer to as “New Ventures.” Our New Ventures prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria, and can be located both inside and outside of the United States. As of December 31, 2012, we held 3,81 9,128 net undeveloped acres in connectio n with our New Vent ures prospects, of which 2,518,518 net acres are located in New Brunswick, Canada.

 Maximize Efficiency through Vertical Integration and Economies of Scale

. In our key operating areas, the concentration of our properties allows us to achieve economies of scale that result in lower costs. We seek to serve as the operator of the wells in which we have a significant in terest. As the operator, we are better positioned to control the enhancing, drilling, completing and producing of wells and the marketing of production to minimize costs and maximize both production volumes and realized price. In the Fayetteville Shale play, we have achieved significant cost savings through ownership of our sand mine that is a source of proppant for our well completions and from our other associated oilfield services including operating a fleet ofdrilling rigs designed specifically for the play. In late2012, we also began providing pressure pumping services for a certain number of our operated well completions in the Fayetteville Shale play.

 Enhance the Value of Our Midstream Operations

. We have continued to design and improve our gas gathering infrastructure to better manage the physical movement of our production and the costs of our operations. As of December 31, 2012, we have invested ap proximately $1,038 million in the 1,8 52 mile gas gathering system built for our Fayetteville Shale play, which was gathering approxima tely 2.3 Bcf per day at y ear-end, and have invested approximately $203 million in 82 miles of gas gathering lines in Pennsylvania and in East Texas. Our gathering system in the Fayetteville Shale play has developed into a strategic asset that not only supports our E&P operations but also has improved our overall re turns on a stand-alone basis.

Recent Developments

2013 Planned Capital Investments and Production Guidance. Our planned capital investment program for 2013 is approximately $2.0 billion, which includes approximately $1.8 billion for our E&P segment, $160 million for our Midstream Services segment and $40 million for corporate and other purposes. Our 2013 capital program is expected to be funded primarily by our cash flow from operations and bo rrowings under our $1.5 billion unsecured revolving credit facility. The planned capital program for 2013 is flexible an d we will reevaluate our proposed investments as needed to take into account prevailing market conditions. Based on our capital program, we also announced our targeted 2013 natural gas and oil production of approximately 628 to 640 Bcfe, an increase of approximately 12% over our 2012 production, using midpoints.

Exploration and Production

Overview

Our operations in our E&P segment are focused primarily on the Fayetteville Shale, an unconventional reservoir
located in the Arkoma Basin in Arkansas. In addition to ou r Arkansas operations, we are also continuing to expand our drilling program on our acreage in Pennsylvania targeting the Marcellus Shale and we will conduct both conventional and unconventional operations targeting various formations as part of our New Ventures projects, which include unconventional horizontal oil plays targeting the Lower Smackover Brown Dense, or LSBD, formation in Arkansas and Louisiana, the Marmaton and Atoka format ions in the Denver-Julesburg Basin in Colorado, the Bakken and Three Forks formations in Montana and exploration activities in New Brunswick, Canada. We continue to actively seek to develop both conventional and unconventional natural gas and oil resource plays with significant exploration and exploitation potential.5 Our E&P segment recorded an operating loss of $1,411.2 million in 2012 as a result of the recognition of a $1,939.7 million, or $1,192.4 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties recorded for the twelve months ended December 31, 2012. Our E&P segmen t recorded operating income of $825.1 million in 2011 and operating income of $829.5 million in 2010. Our operating income in 2012 decreased as the revenue impact of our 13% increase in production was more than offset by the 18% d ecline in our average realized gas prices, the ceiling test impairment and an increase in operating costs and expenses that resulted from our significant production growth. The slight decrease in operating income in 2 011 was primarily due to lower prices realized from the sale of our natural gas production and an increase in operating costs and expenses which was largely offset by a 24% increase in our total natural gas and oil production. EBITDA from our E&P segment was $1.3 billion in 2012, compared to $1.5 billion in 2011 and $1.4 billion in 2010. Our EBITDA decreased in 2012 as our increased production was more than offset by lower average realized gas prices and increased operating costs and expenses that resulted from our significant production growth. The
increase in our EBITDA in 2011 was due to our increased production volumes which was partially offset by lower average realized gas prices and increased operating costs and expe nses. EBITDA is a non-GAAP measure. We refer you to
“Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a reconciliation of EBITDA to net income (loss) attributable to Southwestern Energy.

Our Proved Reserves

Our estimated proved natural gas and oil reserves were 4,018 Bcfe at year-end 2012, compared to 5,893 Bcfe at yearend 2011 and 4,937 Bcfe at year-end 2010. The overall decrease in to tal estimated proved reserves in 2012 was primarily due to the low natural gas price environment. Since our proved reserves are primarily natural gas and as such our reserve estimates and the after-tax PV-10 measure is highly dependent upon the natural gas price used in the after-tax PV-10 calculation. The average prices utilized to value our estimated proved natural gas and oil reserves as of December 31, 2012 were $2.76 per MMBtu for natural gas and $91.21 per ba rrel for oil compared to $4.12 per MMBtu for natural gas and $92.71 per barrel for oil at December 31, 2011 and $4.38 per MMBtu for natura l gas and $75.96 per barrel for oil at December 31, 2010.

The after-tax PV-10, or standardized measure of discounted future net cash flows relating to proved natural gas and oil reserve quantities, was $2.1 billion at year-end 2012, compared to $3.5 billion at year-end 2011 and $3.0 billion at yearend 2010. The decrease in our after-tax PV-10 value in 2012 was primarily caused by the low natural gas price
environment. The increase in our after-t ax PV-10 value in 2011 over 2010 was primarily due to the increase in our reserves, partially offset by a decrease in average 2011 prices for natural gas from average 2010 prices. The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2012 Proved Reserves by Category and Summary Operating Data table below) is the discounted valu e of future income taxes on the estimated cash flows. Ouryear-end 2012 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pretax PV-10, of $2.3 billion, compared to $4.8 billion at year-end 2011 and $4.3 billion at year-end 2010.

We believe that the pre-tax PV-10 value of the estimated cash flows related to our estimated proved reserves is a useful supplemental disclosure to the after-tax PV-10 value. While pre-tax PV-10 is based on prices, costs and discount factors that are comparable fro m company to company, the after-tax PV-10 is dependent on the unique tax situation of each individual company. We understand that securities analysts us e pre-tax PV-10 as one measure of the value of a company’s current proved reserves and to compare re lative values among peer companies withou t regard to income taxes. We refer you to Note 4 in the consolidated financial statements for a discussion of our standardized measure of discounted future cash flows related to our proved gas and oil reserves, to the ri sk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-K, and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Pa rt II of this Form 10-K for a discussion of the risks inherent in utilization of
standardized measures and estimated reserve data.

Approximately 100% of our year-end 2012 estimated proved reserves were natural gas and 80% were classified as proved developed, compared to approximately 100% and 55%, respectively, in both 2011 and 2010. We operate approximately 97% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index approximated 7.1 years at year-end 2012. Natural gas sale s accounted for nearly 100% of total operating revenues for this segment in 2012, 2011 and 2010.6 The following table provides an overall an d categorical summary of our oil and natu ral gas reserves, as of fiscal yearend 2012 based on average fiscal year prices, and our well co unt, net acreage and PV-10 as of December 31, 2012 and sets forth 2012 annual information related to production and capital investments for each of our operating areas:

2012 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA

Ark-La-Tex
Fayetteville Marcellus East Arkoma New

Shale Play Shale Play Texas Basin Ventures Total

Estimated Proved Reserves:

Natural Gas (Bcf):

Developed (Bcf) 2,624 374 51 146 1 3,196
Undeveloped (Bcf) 364 442 1 14 – 821

2,988 816 52 160 1 4,017

Crude Oil (MMBbls):

Developed (MMBbls) – – 0.1 – 0.1 0.2
Undeveloped (MMBbls) – – – – – –

– – 0.1 – 0.1 0.2

Total Proved Reserves (Bcfe) (1) :

Proved Developed (Bcfe) 2,624 374 52 146 1 3,197
Proved Undeveloped (Bcfe) 364 442 1 14 – 821

2,988 816 53 160 1 4,018

Percent of Total 75% 20% 1% 4% – 100%

Percent Proved Developed 88% 46% 97% 91% 100% 80%
Percent Proved Undeveloped 12% 54% 3% 9% – 20%

Production (Bcfe) 486 54 11 14 – 565
Capital Investments (millions) (2) $ 991 $ 507 $ 5 $ 6 $ 337 $ 1,846

Total Gross Producing Wells (3) 3,228 132 173 1,180 4 4,717
Total Net Producing Wells (3) 2,186 71 110 570 4 2,941

Total Net Acreage 788,849 (4) 176,298 (5) 49,340 (6) 238,940 (7) 3,822,344 (8) 5,075,771

N et Undeveloped Acreage 308,924 (4) 159,078 (5) 1,874 (6) 63,341 (7) 3,819,128 (8) 4,352,345

PV-10:

Pre-tax (millions) (9) $ 1,693 $ 483 $ 30 $ 112 $ 6 $ 2,324

PV of taxes (millions) (9) 199 57 3 14 – 273

After-tax (millions) (9) $ 1,494 $ 426 $ 27 $ 98 $ 6 $ 2,051

Percent of Total 73% 21% 1% 5% – 100%
Percent Operated (10) 97% 99% 97% 89% 100% 97%

(1) We have no reserves from synthetic ga s, synthetic oil or nonrenewable natural res ources intended to be upgraded into synth etic gas or oil. We used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis offset statistical analogy of performance data, volumetric ev aluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with est imated reservoir parameters (including reservoir temperature and pressure, formation dept h and formation volume factor s), geological analysis, i ncluding structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.

(2) Our Total and Fayetteville Shale play capital investments ex clude $15 million related to ou r drilling rig related equipment , sand facility and other equipment.

(3) Represents all producing wells, including wells in which we only have an overriding royalty interest, as of December 31, 20 12.

(4) Assuming successful wells are not drilled to develop the acreag e and leases are not extended, leasehold expiring over the n ext three years will be 46,007 net acres in 2013, 183,824 net acres in 2014, which include s 153,863 net acres held on federal lands, and 39,071 net acr es in 2015.

(5) Assuming successful wells are not drilled to develop the acreag e and leases are not extended, leasehold expiring over the n ext three years will be 41,860 net acres in 2013, 13,467 net acres in 2014 and 3,835 net acres in 2015.7 (6) Assuming successful wells are not drilled to develop the acreag e and leases are not extended, leasehold expiring over the n ext three years will be 1,340 net acres in 2013, 152 net acres in 2014 and 202 net acres in 2015.

(7) Includes 123,442 net developed acres and 1, 211 net undeveloped acres in the Arkoma Basin that are also within our Fayettevi lle Shale focus area but not included in the Fayetteville Shale acreage in the table a bove. Assuming successful wells are not drilled to develop the acr eage and leases are not extended, leasehold expiring over the next three years will be 1,200 net acres in 2013, 670 net acres in 2014 and 17,788 net ac res in 2015.

(8) Assuming successful wells are not drilled to develop the acreag e and leases are not extended, leasehold expiring over the n ext three years, excluding New Brunswick, Canada and the LSBD area will be 1,120 net acres in 2013, 60,294 net acres in 2014 and 142,294 net acres in 2015 . With regard to the company’s acreage in New Brunswick, Cana da, 2,518,518 net acres will expire in Marc h 2015. We have applied for an additiona l 1-year option to extend our exploration license agreements a nd, if granted by the Province of New Brus nwick, this would extend our exploration l icense agreements until March 2016. With regard to our acreage in the LSBD play , assuming successful wells are not drilled and leases are not ex tended, leasehold expiring over the next three years will be 68,023 net acres in 2013, 237,181 net acres in 2014 and 159,718 net acres in 2015.

(9) Pre-tax PV-10 (a non-GAAP measure) is one measure of the value of a company’s proved reserves that we believe is used by se curities analysts to compare relative values among peer companies without regard to in come taxes. The reconciling di fference in pre-tax PV-10 and t he after-tax PV-10, or standardized measure, is the discounted value of future in come taxes on the estimated cash flows from our proved oil and nat ural gas reserves.

(10) Based upon pre-tax PV-10 of pr oved developed producing properties.

We refer you to Note 4 in our consolidated financial statements for a more detailed discussion of our proved gas and oil reserves as well as our standardized measure of discounted future net cash flows related to our proved gas and oil reserves. We also refer you to the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-K a nd to “Man agement’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about ForwardLooking Statements” in Item 7 of Part II of this Form 10- K for a discussion of the risks inherent in utilization of
standardized measures and estimated reserve data.

Proved Undeveloped Reserves

As of December 31, 2012, we had 821 Bcfe of proved undeveloped reserves, none of which were proved undeveloped reserves that remain undeveloped for five years or more af ter initially being disclosed by us. During 2012, we invested $518 million in connection with converting 493.2 Bcfe or 19% of our proved undeveloped reserves as of December 31, 2011 into proved developed reserves and added 336.8 Bcfe of proved undeveloped reserve additions, primarily in the Fayetteville and Marcellus Shale plays. Our 2012 proved unde veloped reserve additions are expected to be developed and to begin to generate cash inflows over the next five years. At December 31, 2011, we had 2,633 Bcfe of proved undeveloped reserves, none of which were proved undeveloped re serves that remained undeveloped for five years or more after initially being disclosed by us. During 2011, we invested $509.3 million in connection with converting 403.3 Bcfe or 18% of our proved undeveloped reserves as of December 31, 2010 into proved developed reserves and added 847.8 Bcfe of proved undeveloped reserve additions, primarily in the Fayetteville Shale play.

The development of our proved undeveloped reserves will requi re us to make significant additional investments. We expect that the development costs for our proved undeveloped reserves of 821 Bcfe as of December 31, 2012 will require us to invest an additional $698 million in order for those reserves to be brought to production. Our ability to make the necessary investments to generate these cas h inflows is subject to factors that may be beyond our control. A significant decrease in price levels for an extended period of time could result in certain reserves no longer being economic to produce, leading to both lower proved reserves and cash flows. We refer you to the risk factors “A substantial or extended decline in natural gas and oil prices would have a material adverse effect on us,” “We may have difficulty financing our planned capital investments, which could adversely affect our growth” and “Our level of indebtedness and the terms of our financing arrangements may adversely affect operations and limit our growth” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Co ndition and Results of Operations — Cautionary Statement about Forward-Looking Statements ” in Item 7 of Part II of this Form 10-K for a more detailed discussion of these factors
and other risks.

Our Reserve Replacement

The ability of an E&P company to add ne w reserves to replace the reserves that are being depleted by its current production volumes is viewed by many investors as an indication of its long-term prospects. The reserve replacement ratio, which we discuss below, is an important analytical measure used within the E&P industry by investors and peers to evaluate performance results. There are li mitations as to the usefulness of this measure as it does not reflect the type of reserves or the cost of adding th e reserves or indicate the potential value of the reserve additions.

In 2012, we replaced our production volum es with 919.5 Bcfe of proved reserv e additions as a result of our drilling program, but also incurred net downward revisions of 2,088.2 Bcfe principally due to a decrease in the price of natural gas and to a lesser extent due to downward performance revisions of 336.4 Bcfe. Of the reserve additions, 582.8 Bcfe were8 proved developed and 336.7 Bcfe were proved undeveloped. The total downward reserve revisions were primarily impacted by the low commodity price environment in 2012 and to a lesser extent by downward performance revisions.

In 2011, we replaced 299% of our produc tion volumes with an increase of 1,459.4 Bcfe of proved gas and oil reserves as a result of our drilling program and net upward revisions of 33.7 Bcfe. Of the reserve additions, 611.6 Bcfe were proved developed and 847.8 Bcfe were proved undeveloped. The upwa rd reserve revisions during 2011 were primarily due to 102.6 Bcf in upward revisions related to the improved performance of wells in our Marcellus Shale play, partially offset by downward performance revisions of 27.5 Bcfe and 18.2 Bcfe in our East Texas and conventional Arkoma Basin operating areas, respectively. We also had downward performance revisions in our Fayetteville Shale play of 14.0 Bcfe. Additionally, our reserves decreased by 9.2 Bcfe due to a comparative decrease in the av erage gas price for 2011 as compared to 2010. In addition, our reserves decreased by 37.3 Bcfe as a result of our sale of oil and natural gas leases and
wells in 2011.

In 2010, we replaced 430% of our produc tion volumes with an increase of 1,431.1 Bcfe of proved gas and oil reserves as a result of our drilling program and net upward revisions of 309.6 Bcfe. Of the reserv e additions, 698. 0 Bcfe were proved developed and 733.2 Bcfe were pr oved undeveloped. The upward reserve revisions during 2010 were primarily due to 266.7 Bcf in upward revisions related to the improved perf ormance of wells in our Fayetteville Shale play and positive
reserve revisions of 78.4 Bcfe due to a comparative increase in th e average gas price for 2010 as compared to 2009. Additionally, we had net upward revisions of 2.7 Bcfe and 34.2 Bcf in our East Texas and conventional Arkoma Basin operating areas, respectively. Additionally, our reserves decreased by 55.4 Bcfe as a result of our sale of oil and natural gas leases and wells in 2010.

For the period ending December 31, 2012, our three-year average reserve repl acement ratio, including revisions, was 141%. Our reserve replacement ratio for 2012 , excluding the effect of reserve revisi ons, was 163%, comp ared to 292% in 2011 and 354% in 2010. Excluding reserve revisions, our three-year average reserve replacement ratio is 259%.

Since 2005, the substantial majority of our reserve additi ons have been generated from our drilling program in the Fayetteville Shale play. Over the past several years, the Mar cellus Shale play has contributed an increasing amount to our reserve additions. We expect our drilling programs in the Fayetteville Shale and Marcellus Shale plays to continue be the primary source of our reserve additions in the future; however, our ability to add reserves depends upon many factors that are beyond our control. We refer you to the risk factors “O ur drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to change” and “Our exploration, de velopment and drilling efforts and our operation of our wells may not be profitable or achieve our targeted returns” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about ForwardLooking Statements” in Item 7 of Part II of this Form 10-K for a more detailed discussion of these factors and other risks.

Our Operations

Fayetteville Shale Play

Our Fayetteville Shale play is currently a primary focus of our E&P business. The Fayetteville Shale is a Mississippian-age unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, ranging in thickness from 50 to 550 feet and ranging in dept h from 1,500 to 6,500 feet . As of December 31, 2012, we held leases for approximately 913,502 net acres in the play area (310,135 net undeveloped acres, 479,925 net developed acres held by Fayetteville Shale production and 123,442 net acres held by co nventional production in the traditional Fairway portion of the Arkoma Basin), compared to approximately 925,842 net acres at year-end 2011 and 915,884 net acres at year-end

2010.

Approximately 2,988 Bcf of our reserves at year-end 2012 were attributable to our Fayetteville Shale play, compared to approximately 5,104 Bcf at year-end 2011 and 4,345 Bcf at year-end 2010. Our reserves in the Fayetteville Shale play decreased by 2,116 Bcf, which included net downward price revisions of 1,684 Bcf, 362 Bcf of downward revisions due to well performance, and production of 486 Bcf, partially offset by reserve additions of 415 Bcf. Gross production from our operated wells in the Fayetteville Shale play increased from approximately 1,947 MMcf per day at the beginning of 2012 to approximately 2,090 MMcf per day by year-end. Our net production from the Fayetteville Shale play was 485.5 Bcf in 2012, compared to 436.8 Bcf in 2011 and 350.2 Bcf in 2010. In 2013, we estimate our net production from the Fayetteville Shale play will be in the range of 475 to 480 Bcf.

At year-end 2012, after excluding our ac reage in the traditional Fairway and the federal acreage we hold in the Ozark Highlands Unit, approximately 80% of our 605,409 total net leasehold acres remaining in the Fayetteville Shale was held by production. For more information about our acreage and well count, we refer you to “Properties” in Item 2 of Part 1 of9 this Form 10-K. Excluding our acreage in the traditional Fa irway, our acreage position was obtai ned at an average cost of approximately $313 per acre and has an average royalty intere st of 15%. In 2013, we ex pect to earn 13 sections or approximately 5,700 net acres, representi ng 3% of our drilling program. As of December 31, 2012, excluding our acreage in the traditional Fairway and our federal acreage, the undevelo ped portion of our acreage had an average remaining lease term of 1.3 years. We refer you to the risk factor “If we fail to drill all of the wells that ar e necessary to hold our acreag e, the initial lease terms could expire, which would result in the loss of certain leasehold rights” in Item 1A of Part I of this

Form 10-K.

As of December 31, 2012, we had spud a total of 3,586 wells in the play si nce its commencement in 2004, 3,034 of which were operated by us and 552 of which were outside-opera ted wells. Of the wells spud, 491 were in 2012, 650 were in 2011 and 658 were in 2010. Of the wells spud in 2012, 485 were designated as horizontal wells. At year-end 2012, 2,874 operated wells had been drilled and completed overall, in cluding 2,783 horizontal wells. Of the 2,783 horizontal wells, 2,765 wells were fracture stimulated using either s lickwater or crosslinked gel stimulation treatments, or a
combination thereof.

Over the past several years, we have seen continual im provement in our drilling practices in the Fayetteville Shale play. Our operated horizo ntal wells had an average completed well cost of $2.5 million per well, average horizontal lateral length of 4,833 feet and average time to drill to total depth of 6. 7 days from re-entry to re-entry in 2012. This compares to an average completed operated well cost of $2.8 million per well, average horizontal lateral length of 4,836 feet and average time to drill to total depth of 7.9 days from re-ent ry to re-entry during 2011. In 2010, our average completed operated well cost was $2.8 million per well with an average hori zontal lateral length of 4,528 feet and average time to drill to total depth of 10.9 days from re-ent ry to re-entry. The operated wells we placed on production during 2012 averaged initial production rates of 3,629 Mcf per day, compared to av erage initial production rates of 3,330 Mcf per day in 2011 and 3,364 Mcf per day in 2010. The incr ease in initial production rates in 2012 was primarily due to the optimization of our drilling plan in the first quarter of 2012 toward areas in th e field with the highest-return wells. As a result, our avera ge initial production rates on a per well basis were significantly hi gher, particularly during the last half of 2012. The decreas e in initial production rates in 2011 was primarily due to incr eased well density and locational differences in the mix of wells. During 2012, we placed 60 operated wells on produc tion with initial production rate s that exceeded 5.0 MMcf per day.

Our total proved net reserves booked in the play at year-end 2012 were from a total of 3,508 locations, of which 3,175 were proved developed producing, 123 were proved developed non-producing and 210 were proved undeveloped. Of the3,508 locations, 3,468 were horizontal. The average gross proved reserves for the undeveloped wells included in our yearend 2012 was approximately 2.8 Bcf per well, compared to 2.4 Bcf per well at both year-end 2011 and year-end 2010. Total proved net natural gas reserves booked in the play in 2011 totaled approximately 5,104 Bcf from a total of 4,376 locations, of which 2,735 were proved developed producing , 59 were proved developed non-producing and 1,582 were proved undeveloped. Total proved net natural gas reserves booked in the play in 2010 totaled approximately 4,345 Bcffrom a total of 3,682 locations, of which 2,120 were proved developed producing, 36 were proved developed nonproducing and 1,526 were proved undeveloped.

In 2012, we invested approximately $991 million in our Fayetteville Shale play, which included approximately $877 million to spud 491 wells, 453 of which we operated. Included in our total capital investments in the play during 2012 was $110 million in capitalized costs and other expenses and $4 million for acquisition of properties. In 2011, we invested approximately $1.3 billion in our Fayetteville Shale play, whic h included $1.2 billion to spud 650 wells, $10 million for acquisition of properties, and $132 million in capitalized costs and other expenses. In 2010, we invested approximately $1.3 billion in our Fayetteville Shale play, which included $1.2 billion to spud 658 wells, $48 million for acquisition of properties and $111 million in capitalized costs and other expenses. As of December 31, 2012, we had acquired approximately 1,324 square miles of 3-D seismic data, which provides us with seismic data on approximately 65% of our net acreage position in the Fayetteville Shale, excluding ou r acreage in the traditional Fairway portion of the Arkoma
Basin.

In 2013, we plan to invest approximately $830 million in our Fayetteville Shale play, which includes participating in approximately 385 to 390 gross wells, all of which we plan to operate.

We believe that our Fayetteville Shale acreage continues to ha ve significant development potential. Our strategy is to continue our development drilling, increase the amount of acreage we hold by production and determine the economic viability of the undrilled portion of our acreage. Our drilling pr ogram with respect to our Fayetteville Shale play is flexibl e and will be impacted by a number of factors, including the re sults of our horizontal drilling efforts, our ability to determine the most effective and economic fracture stimulation methods and well spacing, the extent to which we can replicate the results of our most successful Fayetteville Shale wells in other Fayetteville Shale acreage and the natural gas commodity10 price environment. As we continue to gather data about th e Fayetteville Shale, it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all. We refer you to the risk factor “Our dr illing plans for the Fayetteville Shale play and Marcellus Shale play are subject to change” in Item 1A of Part I of this Form 10-K.

Marcellus Shale Play

We began leasing acreage in northeastern Pennsylvania in 2007 in an effort to gain a position in the emerging Marcellus Shale play. As of December 31, 2012, we had appr oximately 176,298 net acres in Pennsylvania under which we believe the Marcellus Shale play is present (159,078 net undeveloped acres and 17,220 net developed acres held by production), compared to approximately 186,893 net acres at year-end of 2011 and 173,009 net acres at year-end 2010. Our undeveloped acreage position as of December 31, 2012 had an average remaining lease term of three years and an average royalty interest of 15% and was obtained at an aver age cost of approximately $1,273 per acre.

As of December 31, 2012, we had spud 160 operated wells, 72 of which were on production and 153 of which will be horizontal wells. In 2012, we invested approximately $507 million in the Marcellus Shal e play and spud 92 operated wells, resulting in reserve additions of 500 Bcf. Of these 92 wells, 34 will be horizontal wells located in our Greenzweig area in Bradford County, 15 will be horizontal wells located in Lycoming County and the remaining 43 wells are located in our Price and Range Trust areas in Susquehanna County. Our operated horizontal wells had an average completed well cost of $6.1 million per well, average horizontal lateral length of 4,070 feet and an average of 12 fracture stimulation stages in 2012. This compares to an average completed operated well cost of $7.0 mil lion per well, average horizontal lateral length of 4,223 feet and an average of 14 fracture stimulation stages in 2011. In 2010, ou r average completed operated well cost was $6.0 million per well with an average horizontal lateral length of 3,602 feet and an average of nine fracture stimulation stages. Included in our total capital investments in the play during 2012 was approximately $400 million for drilling and completions, $24 million for acquisition of propertie s, $6 million for seismic and $77 million in facilities, capitalized costs and other expenses. In 2011, we invested approximately $332 million in the Marcellus Shale play and spud 43 operated wells, resulting in net reserve additions and revisions of 327 Bcf. In 2010, we invested approximately $118 million in the Marcellus Shale play and spud 21 operated wells, resulting in net reserve additions of 38 Bcf.

Approximately 816 Bcf of our total proved net reserves at yea r-end 2012 were attributable to the Marcellus Shale play. The company had a total of 71 operated horizontal wells and one operated vertical well which were on production as of December 31, 2012, resulting in ne t production from this area of 53.6 Bcf in 2012, compared to 23.4 Bcf in 2011 and 1.0 Bcf in 2010. Our reserves booked in the Marcellus Shale play included a total of 203 locations, of which 129 were proved developed producing, one was proved developed non-producing and 73 were proved undeveloped. The average gross proved reserves for the undeveloped wells included in our year-end reserves for 2012 was approximately 7.6 Bcf per well, up from 7.5 Bcf per well at year-end 2011 and 3.0 Bcf per well in 2010.

In 2013, we plan to invest approximat ely $705 million in the Marcellus Shale play and expect to participate in a total of 86 to 88 gross wells in 2013, all of which will be operated by us. In 2013, we estimate our net production from the Marcellus Shale play will be in the range of 134 to 139 Bcf. Our ability to bring our Marcellus Shale production to market will depend on a number of factors including the construction of and/or the availability of capacity on gathering systems and pipelines that we do not own. We refer you to “Mid stream Services — Gas Marketing” for a discussion of our gathering and transportation arrangements for the Marcellus Shal e production and to the risk factor “Our ability to sell our natural gas and oil and/or to receive market prices for ou r production may be adversely affected by constraints or interruptions on gathering systems, pipelines, processing and transportation systems owned or operated by us or others.” in
Item 1A of Part I of this Form 10-K.

We believe that our Marcellus Shale acreage has significan t development potential. Our drilling program with respect to our Marcellus Shale play is flexible and will be impacted by a number of factors, including the results of our horizontal drilling efforts, our ability to de termine the most effective and economic fract ure stimulation methods and well spacing and the natural gas commodity price environment. As we continue to gather data about the Marcellus Shale, it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all. We refer you to the risk factor “Our drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to cha nge” in Item 1A of Part I of this Form 10-K.11 Ark-La-Tex

Our Ark-La-Tex division includes our conventional assets in the Arkoma Basin in Arkansas and Oklahoma and our
conventional and unconventional assets in East Texas. Produc tion from these assets was 25.6 Bcfe in 2012, compared to 39.8 Bcfe in 2011 and 53.5 Bcfe in 2010. The decline in production from these areas during 2012 and 2011 was primarily driven by asset dispositions as well as natural field producti on declines and lower capital investments in these areas since 2009. In May 2012, we sold our oil and natural gas leases, wells and gathering equipment in approximately 19,800 net acres in the Overton Field in East Texas for approximately $166.0 million. In May 2011, we sold the producing rights to the Haynesville and Middle Bossier Shale intervals in approx imately 9,717 net acres for appr oximately $118.1 million. In June 2010, we sold the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 20,063 net acres for approximately $357.8 million. We expect these sales, together with ou r planned decrease in capital investments and the natural production decline in existing wells, to decrease our net production from the Ark-La-Tex division in 2013. In 2012, we invested approximately $11 million in our Ark-La-Tex division and added new reserves of 3 Bcfe. Total proved net reserves from these areas were approximately 21 3 Bcfe as of December 31, 2012, compared to 447 Bcfe at year-end 2011 and 554 Bcfe at year-end 2010. In 2013, we expect to invest ap proximately $15 million in our Ark-La-Tex

division.

New Ventures

We actively seek to find and develop new oil and natura l gas plays with significant exploration and exploitation potential, which we refer to as “New Ventures.” We have been focusing on both oil and natural gas unconventional plays, and the technological methods best suited to developing thes e plays, such as horizontal drilling and fracture stimulation techniques. New Ventures prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria and may be located both inside and outside of the United Stat es. As of December 31, 2012, we held 3,819,128 net undeveloped acres in connection with our New Ventures prospects, of which 2,518,518 net acres were located in New Brunswick, Canada. This compares to 3,600,314 net undeveloped acres held at year-end 2011 and 3,009,643 net undeveloped acres held at year-end 2010.

In March 2010, we successfully bid for exclusive licenses fr om the Department of Natura l Resources of the Province of New Brunswick, Canada to search and conduct an exploration program covering 2,518,518 net acres in the province in order to test new hydrocarbon basins. As a condition unde r our licenses, we are require d to make investments of approximately $47 million USD in the province by March 31, 201 3. In December 2012, we received two one-year extensions to our exploration license agreements which expire on March 16, 2014 and March 16, 2015, respectively. Since 2010, we have conducted airborne gravity and magnetics surveys, surface geochemi stry surveys and, as of December 31, 2012, had acquired 248 miles of 2-D seismic data. While preliminary interpretation has already begun, in 2013 we intend to acquire an additional 130 additional miles of 2-D seismic data. Through December 31, 2012, we have invested approximately $25.8 million USD in our New Brunswick exploration program towards our commitment, which represents

our first venture outside of the United States.

In July 2011, we announced that we would begin testing a new unconventional horizontal oil play targeting the LSBD formation, an unconventional oil reservoir that ranges in vertical depths from 8,000 to 11,000 feet and appears to be laterally extensive over a large area ranging in thickness from 300 to 550 feet. As of December 31, 2012, we held approximately 504,486 net undeveloped acres in the area, obta ined at an average cost of $419 per acre. Our leases currently have approximat ely an 81% average net revenue interest and an average primary lease term of approximately four years, which may be extended for approximately four additio nal years. We have drilled six operated wells in the play area to date, including two that are currently shut-in for further testing and one that was temporarily abandoned. Three wells are currently producing, two of which are horizontal wells. We are encouraged by our results to date and if our drilling program yields positive results, we expect that activity in the play could increase significantly over the next severa l

years.

We have approximately 301,918 net acres in the Denver-Julesburg Basin in eastern Colorado where we have begun testing an unconventional oil play targeting middle and late Pe nnsylvanian to Permian-age carbonates and shales. We have drilled a horizontal well and a vertical well, both of which are testing multiple intervals.

We also have drilled a horizontal oil well in Sheridan County, Montana, targeting the Bakken and Three Forks objectives. We are continuing to lease acreage and plan to permit and drill additional wells in the area in 2013.

While we believe that our New Ventures projects have significant exploration and exploitation potential, there can be no assurance that all prospects will result in viable projects or that we will not abandon our initial investments. We refer you to the risk factors “The success of our New Ventures pr ojects is subject to drilling and completion technique risks and12 enhanced recovery methods. Our drilling re sults may not meet our expectations for reserves or production and the value of our undeveloped New Venture acreage could decline,” and “O ur exploration, development and drilling efforts and our operation of our wells may not be profitable or achieve our targeted returns” in Item 1A of Part I of this Form 10-K.

Divestitures

In May 2012, we sold certain oil and natural gas leases, wells and gathering equipment in the Overton Field in East Texas for approximately $166 million. The sale included a pproximately 19,800 net acres in Smith County, Texas. Net production from the field was approximately 24 MMcfe per day as of the closing date and proved net reserves were approximately 143 Bcfe as of year-end 2011.

In May 2011, we sold certain oil and natural gas leas es, wells and gathering equipment in East Texas for approximately $118.1 million. The sale included only the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 9,717 net acres. The net production from the Haynesville and Middle Bossier Shale intervals in this acreage was approximately 7.0 MMcf per day and proved net reserves were approximately 37.1 Bcf when the sale was completed in May 2011.

Capital Investments

During 2012, we invested a total of $1.9 billion in our E&P business and participated in drilling 595 wells, 383 of which were successful, and 203 which were in progress at year-end. Of the 203 wells in progress at year-end, 133 were located in our Fayetteville Shale play. Of the approximately $1.9 billion invested in our E&P business in 2012, approximately $991 million was invested in our Fayetteville Shale play, $507 million in our Marcellus Shale play, $5 million in East Texas, $6 million in our conventional Arkom a Basin program and $337 million in New Ventures projects.

Of the $1.9 billion invested in 2012, approximately $1.4 billion was invested in exploratory and development drilling and workovers, $186 million for acquis ition of properties, $10 million for seismic expenditures and $254 million in capitalized interest and other expenses. Additionally, we i nvested approximately $15 million in our drilling rig related equipment, sand facility and other equipment. In 2011, we invested approximately $2.0 billion in our primary E&P business activities and participated in drilling 708 wells. Of the $2.0 billion invested in 2011, approximately $1.5 billion was invested in exploratory and development drilling and workovers, $227 million for acquisition of properties, $30 million for seismic expenditures and $199 million in capitalized interest and expenses and other technology-related expenditures. Additionally, we invested approximately $21 million in our drilling rig related equipment, sand facility, and other equipment. In 2010, we invested approximately $1.8 billion in our primary E&P business activities and participated in drilling 713 wells. Of the $1.8 billion invested in 2010 , approximately $1.4 billion was invested in exploratory and development drilling and workovers, $200 million for acquisiti on of properties, $17 million for seismic expenditures and $172 million in capitalized interest and expenses and other technology-related expenditures. Additionally, we invested approximately $13 million in drilling rig related and ancillary equipment.

In 2013, we plan to invest approximately $1.8 billion in our E&P program and participate in drilling 480 to 490 gross wells, all of which we plan to operate. The Fayetteville Shal e play and Marcellus Shale play will be the primary focus of our capital investments, with planned investments of appr oximately $830 and $705 million, respectively. Our planned 2013 capital investments also include approximately $235 million in unconventional exploration and New Ventures projects and $15 million in our Ark-La-Tex division.

Of the $1.8 billion allocated to our 2013 E&P capital budget, approximately $1.3 billion will be invested in development and exploratory drilling, $14 million in seismic and other geological and geophysical expenditures, $109 million in acquisition of properties and $318 million in capita lized interest and expenses as well as equipment, facilities and technology-related expenditures. We refer you to “Manag ement’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Ca pital Investments” for additional discussion of the factors that could impact our planned capital investments in 2013.

Sales, Delivery Commitments and Customers

Sales. Our daily natural gas equivalent production averaged 1,543.7 MMcfe in 2012, compared to 1,370.0 MMcfe in 2011 and 1,108.8 MMcfe in 2010. Total natural gas equivalent production was 565.0 Bcfe in 2012, up from 500.0 Bcfe in 2011 and 404.7 Bcfe in 2010. Our natural gas production was 564.5 Bcf in 2012, compared to 499.4 Bcf in 2011 and 403.6 Bcf in 2010. The increase in production in 2012 resulted primarily from a 48.7 Bcf increase in net production from our Fayetteville Shale play, a 30.3 Bcf increase in net producti on from our Marcellus Shale play, and a 0.3 Bcfe increase in13 net production from our New Ventures plays, which more than offset a combined 14.3 Bcfe decrease in net production from our East Texas and Arkoma Basin properties. The increase in production in 2011 resulted primarily from an 86.6 Bcf increase in production from the Fayetteville Shale play and a 22.4 Bcf increase in our Marcellus Shale play production, which more than offset a combined 13.7 Bcfe decrease in net production from our East Texas and Arkoma Basin properties. We also produced 83,000 barrels of oil in 2012, compared to 97,000 barrels of oil in 2011 and 171,000 barrels of oil in 2010. Our oil production has decreased between 2012 and 2011 primarily due to the divestiture of certain East Texas properties and the natural production decline in existing wells. For 2013, we are targeting total net natural gas and oil production of approximately 628 to 6 40 Bcfe, which represents a growth rate of approximately 12% over our 2012 production volumes, using midpoints.

Sales of natural gas and oil production are conducted under contracts that reflect current prices and are subject to seasonal price swings. We are unable to predict changes in the market demand and price for natural gas, including changes that may be induced by the effects of weather on demand for our production. We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and oil production in order to support certain desired levels of cash flow and to minimize the impact of price fluctuations. Our policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. As of December 31, 2012, we had New York Mercantile Exchange, or NYMEX commodity price he dges in place on 185.6 Bcf, or approximately 29% of our targeted 2013 natural gas production and 18.3 Bcf of our expected 2014 natural gas production. We intend to hedge additional future production volumes to the extent natural gas prices rise to levels that we
believe will achieve certain desired levels of cash flow. We refer you to Item 7A of this Form 10-K, “Quantitative and Qualitative Disclosures about Market Risk s,” for further information regarding our hedge position as of December 31,

2012.

Including the effect of hedges, we reali zed an average wellhead pr ice of $3.44 per Mcf for our natural gas production in 2012, compared to $4.19 per Mcf in 2011 and $4.64 per Mcf in 2010. Our hedging activities increased our average realized natural gas sales price $1.10 per Mcf in 2012, $0.63 per Mcf in 2011 and $0.71 per Mcf in 2010. Our average oil price realized was $101.54 per barrel in 2012, compared to $94.08 per barrel in 2011 and $76.84 per barrel in 2010. None of our oil production was hedged during 2012, 2011 or 2010.

During 2012, the average pr ice received for our natural gas production, excluding th e impact of hedges, was approximately $0.45 Mcf lower than average NYMEX prices. Assuming a NYMEX commodity price for 2013 of $3.50 per Mcf of natural gas, we expect to receive an average sa les price for our natural gas pr oduction $0.50 to $0.55 per Mcf below the NYMEX Henry Hub average settlement price, excludi ng the impact of hedges. In 2013, we expect to incur average third-party transportation charges in the range of $0.35 to $0.40 per Mcf and average fuel charges in the range of 0.35% to 0.50% of our sales price for natural gas and we expect our average basis differential to be approximately $0.10 per Mcf less than NYMEX.

Delivery Commitments. As of February 1, 2013, we had natural gas delivery commitments of 337 Bcf in 2013 and 86 Bcf in 2014 under existing agreements. These commitments require the delivery of natural gas in Arkansas, Pennsylvania and Texas. These amounts are well below our forecasted 2013 and anticipated 2014 production from our available reserves in our Fayetteville Shale, Marcellus Shale and East Texas operations, which are not subject to any priorities or curtailments that may affect quantities delivered to our custom ers or any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factor s beyond our control that may affect our ability to meet our contractual obligations other than those discussed in Item 1A. “Risk Factors.” We expect to be able to fulfill all of our short-term or long-term contractual obligations to provide natural gas from our own production of available reserves, however, if we are unable to do so, we may have to pu rchase natural gas at market to fulfill our obligations.

Customers. Our customers include major energy companies, utilitie s and industrial consumers of natural gas. During the years ended December 31, 2012, 2011 and 2010, no single third-party customer accounted for 10% or more of our
consolidated revenues.

Impact of Federal Regulation of Sales of Natural Gas and Oil

The natural gas industry historically has been heavily regulated and from time to time proposals are introduced by Congress and the FERC and judicial decisions are rendered that impact the conduct of business in the natural gas industry. There can be no assurance that the current, less stringent regulatory approach pursued by the FERC and Congress will continue. We refer you to “Other Items — Environmental Ma tters” and the risk factor “We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future” in Item 1A of Part I of this Form 10-K for a discussion of the impact of government regulation
on our business.14 Competition

All phases of the oil and natural gas industry are highly comp etitive. We compete in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and oil and the securing of labor and equipment required to conduct our operations. Our competitors include major oil and natural gas companies, other independent oil and natural gas companies and individual pr oducers and operators. Many of these competitors have

financial and other resources that substa ntially exceed those available to us.

Competition in Arkansas has increased in recent years due largely to the development of improved access to interstate pipelines and our discovery of the Fayetteville Shale play. While improved intrastate and inte rstate pipeline transportation
in Arkansas has increased our access to markets for our natura l gas production, these markets are also served by a number of other suppliers. Consequently, we will encounter competiti on that may affect both the price we receive and contract terms we must offer. Outside Arkansas, we are less esta blished and face competition from a larger number of other producers.

We cannot predict whether and to what extent any market reforms initiated by the FERC or any new energy legislation will achieve the goal of increasing competition, lessening pref erential treatment and enhancing transparency in markets in which our natural gas is sold. However, we do not believe that we will be disproportionately affected as compared to other natural gas producers and marketers by any action taken by the FERC or any other legislative body.

Regulation of Hydraulic Fracturing

We utilize hydraulic fracturing in our E&P operations as a m eans of maximizing the productivity of our wells. It is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas, and associated liquids from dense subsurface rock formations. The knowledge and expertise in fracturing techniques we have developed through our operations in the Fayetteville Shale play are being utilized in our other operating areas, currently including our Marcellus Shale acreage and, in the near future, expected to include our exploration programs in New Brunswick, Canada. Successful hydraulic fracturing techniques are also expected to be critical to the developm ent of our recen tly announced unconventional horizontal oil play targeting the LSBD formation in Arkansas and Louisiana and potentially other New Venture areas. Hydraulic fracturing involves using water, sa nd, and certain chemicals to fr acture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. In our Fayetteville Shale and Marcellus Shale plays, the fracturing fluids we use are comprised of over 99.9% water and sand. The remaining 0.1% is comprised of small quantities of additives which contain chemical compounds such as hydrochloric acid, phosphoric acid, glutaraldehyde and sodium chloride which is used in common household products.

In the past few years, there has been an increased focus on environmental aspects of hydr aulic fracturing practices in the United States and Canada. In the United States, hydraulic fracturing is typically regulated by state oil and natural gas
commissions but there have recen tly been a number of regulatory initiatives at the federal and local levels as well as by other state agencies.

The Environmental Protection Agency, or EPA, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, the EPA issued final rules effective as of October 15, 2012 that subject oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS programs. The EPA final rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion, or REC techniques developed in the EPA's Natural Gas STAR program. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the final regulations under NESHAPS include maximum achievable control technology, or MACT, standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. Based on our current operations and practices, management believes, such newly promulgated rules will not have a material adverse impact on our financial position, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future.

In October 2011, the EPA also announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to publicly owned trea tment works or POTWs. The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014.15 In addition to the EPA’s efforts, legislation has been intr oduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regula tion of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governme ntal reviews either underway or being proposed that focus on environmental aspects of hydrau lic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of e nvironmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, and while initial results were expected to be ava ilable by late 2012 and final results by 2014, to date the EPA has not released any results from the study. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

Certain states in which we operate have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste di sposal and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohib it the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currentl y conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailm ent in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.

In the Province of New Brunswick in Canada there are presently no hydraulic fracturing regulations, however the provincial government has been working on a new comprehensive regulatory framework that is e xpected to be released to the public in late 2013.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations an d cash flows. We refer you to th e risk factor “Our financial condition and results of operation could be adversely affected by legislative and regulatory initiatives in the United States and Canada relating to hydraulic fracturing that could result in increased costs and additional operating restrictions or delays or prevent us from realizing the value of undeveloped acreage” in Item 1A of Part I of this Form 10-K.

Midstream Services

We believe our Midstream Services segment is well-positioned to complement our E&P initiatives and to compete with other midstream providers for unaffiliated business. We generate revenue from gathering fees associated with the transportation of natural gas to market and through the marke ting of natural gas. Our gath ering assets support our E&P operations and are currently concentrated in our Fayetteville Shale play in Arkansas and our Marcellus Shale play in Pennsylvania.

Our operating income from this segment was $294.3 million on revenues of $2.4 billion in 2012, compared to $248.0 million on revenues of $2.9 billion in 2011 and $191.6 million on revenues of $2.5 billion in 2010. Revenues increased in 2012 and 2011 primarily due to increased gathering revenues and increased volumes marketed. EBITDA generated by our Midstream Services segment was $338.8 million in 2012, compared to $285.1 million in 2011 and $220.5 million in 2010.

The increases in 2012 and 20 11 operating income and EBITDA were primar ily due to increased gathering revenues and margins, partially offset by increased op erating costs and expenses. We expect that the operating income and EBITDA of our Midstream Services segment will increase over the next few years as we continue to develop our Fayetteville Shale and Marcellus Shale acreage positions. EBIT DA is a non-GAAP measure. We refer you to “Business — Other Items —
Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA to net income (loss) attributable to Southwestern Energy.

Gas Gathering

We engage in gas gathering activities through our gatheri ng subsidiaries, DeSoto Gathering and Angelina Gathering. DeSoto Gathering engages in gathering activities in Arkansas primarily related to the development of our Fayetteville Shale play. In 2012, we invested approximately $165.0 mil lion related to these activities and had gathering revenues of16 $474.0 million, compared to $160.8 million invested and revenues of $408.2 million in 2011 and $271.3 million invested and revenues of $316.0 million in 2010.

DeSoto Gathering is expanding its network of gathering lin es and facilities throughout the Fayetteville Shale play area. During 2012, DeSoto Gathering gathered approximately 780.7 Bcf of natural gas volumes in the Fayetteville Shale play area, including 56.0 Bcf of natural gas from third-party operated wells. During 2011, DeSoto Gathering gathered approximately 703.6 Bcf of natural gas volumes in the Fayetteville Shale play area, including 57.4 Bcf of natural gas from third-party wells. In 2010, DeSoto Gath ering gathered approximately 562.6 Bcf of natural gas volumes in the Fayetteville Shale play area, including 56.6 Bcf of natural gas from third-party wells. The increase in volumes gathered over the past three years was primarily due to our growing production volumes from the Fayetteville Shale play. At the end of 2012, DeSoto Gathering had approximately 1,852 miles of pipe from the individual wellheads to the transmission lines and compression equipment representing in aggregate approximately 531,470 horsepower had been installed at 61 central point gathering facilities in the field.

Angelina Gathering currently engages in gathering activities in Pennsylvania and in East Texas. Angelina Gathering is expanding its network of gathering lines and facilities thro ughout the Marcellus Shale play area. During 2012, Angelina Gathering gathered approximately 64.7 Bcf of natural gas vo lumes in the Marcellus Shale play and East Texas areas, including 0.1 Bcf of natural gas from third-party operated wells. During 2011, Angelina Gathering gathered approximately 42.1 Bcf of natural gas volumes in the Marcellus Shale play and East Texas areas, including 0.2 Bcf of natural gas from third-party wells. In 2010, Angelina Gath ering gathered approximately 25.6 Bcf of natural gas volumes in the Marcellus Shale play and East Texas areas, including 0.7 Bcf of natural gas from third-party wells. The increase in volumes gathered over the past three years was primarily due to our growing production volumes from the Marcellus Shale play. At year-end 2012, Angelina Gathering had approximately 57 miles of pipe in Pennsylvania and 25 miles of pipe in Texas. As of December 31, 2012, compression equipment representing in aggr egate approximately 28,195 horsepower had also been installed at 3 central point gathering facilities in Pennsylvania.

Gas Marketing

Our gas marketing subsidiary, SES, a llows us to capture downstream opportunities related to marketing and transportation of natural gas. SES purch ases natural gas and sells it to end-users, manages basis risk and marketing portfolio and acquires transportation rights on third-party pipelin es. Our current marketing operations primarily relate to the marketing of our own natural gas production and some third-party natural gas. During 2012, we marketed 676.2 Bcf of natural gas, compared to 611.4 Bcf in 2011 and 495.8 Bcf in 2010. Of the total volumes marketed, production from our E&P operated wells accounted for 95% in 2012, compared to 94% in 2011 and 95% in 2010.

SES is a “foundation shipper” on two pipeline projects serv ing the Fayetteville Shale play growth, the Fayetteville Express Pipeline LLC, or FEP, a 2.0 Bcf per day pipeline that is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P., and two pipeline laterals called the Faye tteville and Greenville Laterals, which have already been constructed by Texas Gas Transmission, LLC, or Texas Gas, a subsidiary of Boardwalk Pipeline Partners, LP, or Boardwalk Pipeline Partners. FEP wa s placed in-service in January 2011. SES has a maximum aggregate commitment of 1,200,000 Dekatherms per day for an initial term of ten years from the in-service date. SES has maximum aggregate commitments of 800,000 MMBtu per day on the Fayetteville Lateral and 640,000 MMBtu per day on the Greenville
Lateral.

Prior to the commencement of service on the Fayetteville and Greenville Laterals and the Fayetteville Express Pipeline, the majority of our natural gas from the Arkoma Basin was moved to markets in the Midwest and was sold primarily based on two indices, “NGPL TexOk” and “Centerpoi nt East.” The Fayetteville and Greenville Laterals and the Fayetteville Express Pipeline allow us to tr ansport our natural gas to markets in the eastern United States and interconnect with Texas Gas Zone 1, Tennessee Gas Pipeline 100, Trunkline Zone 1A, ANR, Tennessee Gas Pipeline 800, Columbia Gulf Mainline, TETCO M1 30" and Sonat price indices. We rely in part upon the Fayetteville and Greenville Laterals and the Fayetteville Express Pipeline to service our increased production from the Fayetteville Shale play.

During 2011 and 2012, SES entered into a number of short- and long-term firm transportation service and gathering agreements in support of our growing Ma rcellus Shale operations in Pennsylvania. In March 2011, SES entered into a precedent agreement with Millennium Pipeline Company, L.L.C. pursuant to which it will enter into short- and long-term firm natural gas transportation services on Millennium’s existing system. Expansions of the system are expected to be inservice by the second quarter of 2013. In June 2011, SES ente red into separate 15 year agr eements with each of Bluestone Pipeline Company of Pennsylvania, LLC (“Bluestone Gathering”), and Susquehanna Gathering Company I, LLC, both wholly owned subsidiaries of DTE Pipeline Company, an affiliate of DTE Energy Company. Bluestone Gathering committed to build and operate a natural gas gathering system in Susquehanna County, Pennsylvania and Broome County,17 New York, and provide gathering services to SES in support of a portion of our future Marcellus Shale natural gas production. This gathering system was initially placed into service in November 2012 and is expected to be fully completed during the first quarter of 2013. Susquehanna Gathering Company I, LLC. committed to build and operate gathering infrastructure from well pad recei pt locations for deliveries into the Blue stone Gathering system as well as other potential field delivery points. This system was first placed into service November 2012 and will be constructed as necessary to support the company’s activities primarily in Su squehanna County. SES also executed firm transportation agreements with Tennessee Gas Pipeline Company (“TGP”) that increase our ability to move our Marcellus Shale natural gas production in the short term to market as well as a pre cedent agreement for an expansio n project with a projected inservice date of November 2013 pursuant to which SES has subscribed for 100,000 Dekatherm per day of capacity. TGP’s expansion project will expand its 300 Line in Pennsylvania to provide natural gas transportation from the Marcellus Shale supply area to existing delivery points on the TGP system. TGP filed a certificate applica tion for the project with the Federal Energy Regulatory Commission issued a certificate on August 9, 2012. Construction would begin in second quarter 2013, with a projected November 1, 2013 in-service date. On March 23, 2012, SES entered into a precedent agreement with Constitution Pipeline Co. LLC for a proposed 121-mile pipeline connecting to the Iroquois Gas Transmission and Tennessee Gas Pipeline sy stems in Schoharie County, New York. Subject to the receipt of regulatory approvals and satisfaction of other conditions, SES agreed to enter a 15 year firm transportation agreement with a total capacity of 150 MMcf per day on this project. The project is expected to be in service by the second quarter of 2015. In March 2012, SES entered into a firm transportation agreemen t with TGP to utilize existing transportation capacity to various delivery points on TGP’s system. SES agreed to enter into a 10 year firm transportation agreement with a total capacity of 130 MMcf per day on this project. The project went into service in November 2012. We have provided certain guarantees of a portion of SES’s obligations under these agreem ents. We refer you to the risk factor “If our Fayetteville Shale and Marcellus Shale drilling programs fail to produce our projected supply of natural gas, our investments in our gathering operations could be lost. In addition, our commitments for transportation on third-party pipelines and gathering systems could make the sale of our natural gas uneconomic, which could have an adverse effect on our results of operations financial condition and cash flows.”

As of December 31, 2012, SES’s and SEPCO’s obligatio ns for demand and similar charges under the firm transportation agreements and gatherin g agreements totaled approximately $2.8 billion and the Company has guarantee obligations of up to $100.0 million of that amount.

Competition

Our gas gathering and marketing activities compete with numerous other companies offering the same services, many of which possess larger financial and other resources than we have. Some of these competitors are other producers and affiliates of companies with extensive pipeline systems that ar e used for transportation from producers to end-users. Other factors affecting competition are the cost and availability of alte rnative fuels, the level of consumer demand and the cost of and proximity to pipelines and other transportation facilities. We believe that our ability to compete effectively within themarketing segment in the future depends upon establishing and maintaining strong relationships with producers and endusers.

Regulation

We refer you to “Other Items — Environmental Matters” and the risk factor “We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future” in Item 1A of Part I of this Form 10-K for a discussion of the impact of government regulation on our
Midstream Services business.

In November 2008, the FERC issued a Final Rule in Order No. 720, which requires, in relevant part, major noninterstate natural gas pipelines to post, on a daily basis, sp ecific scheduled flow information at each receipt or delivery point with a design capacity of 15,000 MMBtu per day or more. A “major non-interstate pipeline” is a pipeline that is not classified as a natural gas company under the Natural Gas Act of 1938, or NGA, and delivers on average more than 50 million MMBtu of natural gas annually over a three-year peri od. Our gathering system in Arkansas constitutes a “major non-interstate pipeline” under Order No. 720. In October 20 11, the United States Court of Appeals for the Fifth Circuit issued a decision granting the Texas Pipeline Association and the Railroad Commission’s petition for review and vacating
FERC’s Order Nos. 720 and 720-A. In its order, the 5th Circuit held that Order Nos. 720 and 720-A exceeded the scope of FERC’s authority under the NGA and that the FERC cannot re quire a non-interstate pipeline to post capacity and scheduling information. Notwithstanding the ruling, Order No. 720 remains in effect. Compliance with Order No. 720 has not had a material adverse impact on our operations.18 Other

Our other operations have primarily consisted of real es tate development activities concentrated on tracts of land located in Arkansas. During 2012, we sold our office complex in Fayetteville, Arkansas, our interest in approximately 9.5 acres of real estate near the Fayetteville complex and our office complex in Conway, Arkansas for approximately $32.2 million. Subsequently, we leased back our Conway complex from the buyer for a 15 year term. We also purchased 26 acres near The Woodlands, Texas for a future office site. There were no sales of co mmercial real estate in 2011 or 2010.

Our sand mining operations, in support of our E&P business, are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and H ealth Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.1 06) is included in Exhibit 95.1 to this Form 10-K.

Other Items

Reconciliation of Non-GAAP Measures

EBITDA is defined as net income (loss) attributable to Southwestern Energy plus interest, income tax expense, impairment of natural gas and oil properties, and depreciation, depletion and amortization. We have included information concerning EBITDA in this Form 10-K 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 m easure commonly used in our industry. EBITDA should not be considered in isolation or as a substitute for net income (lo ss) attributable to Southwestern Energy, net cash provided by operating activities or other income or cas h flow data prepared in accordance w ith generally accepted accounting principles in the United States, or GAAP, or as a measure of our prof itability or liquidity. EBITDA as defined above may not be comparable to similarly titled measures of other companies.

We believe that net income (loss) attributable to So uthwestern Energy is the financial measure calculated and presented in accordance with GAAP that is most directly comparable to EBITDA as defined. The following table reconciles EBITDA, as defined, with net income (loss) attributable to Southwestern Energy for the years-ended December 31, 2012, 2011 and 2010:

Midstream

E&P Services Other Total

2012

N et income (loss) attributable to S outhwestern Energy $ (884,126) $ 175,570 $ 1,492 $ (707,064)
Impairment of natural gas and oil properties 1,939,734 – – 1,939,734 Depreciation, depletion and amortization 765,368 44,395 1,190 810,953

N et interest expense 20,315 14,341 1,001 35,657 Provision (benefit) for income taxes (548,556) 104,522 895 (443,139) EBITDA $ 1,292,735 $ 338,828 $ 4,578 $ 1,636,141

2011

N et income attributable to Southwes tern Energy $ 493,726 $ 142,591 $ 1,452 $ 637,769
Depreciation, depletion and amortization 666,125 37,261 1,125 704,511

N et interest expense 9,026 15,049 – 24,075
Provision for income taxes 322,714 90,221 286 413,221 EBITDA $ 1,491,591 $ 285,122 $ 2,863 $ 1,779,576

2010

N et income attributable to Southw estern Energy $ 498,346 $ 105,636 $ 136 $ 604,118
Depreciation, depletion and amortization 561,018 28,765 549 590,332

N et interest expense 7,888 18,275 – 26,163 Provision (benefit) for income taxes 323,748 67,834 77 391,659 EBITDA $ 1,391,000 $ 220,510 $ 762 $ 1,612,272

Environmental Regulation

Our operations are subject to regulation in the jurisdictions in which we operate. We have operations in the United States and, to a much lesser extent, in Canada. In the United States, we are subj ect to numerous federal, state and local19 laws and regulations including the Comprehensive Enviro nmental Response, Compensation and Liability Act, or the CERCLA, the Clean Water Act, the Clean Air Act and similar st ate statutes. These laws and regulations require permits for drilling wells and the maintenance of bonding requirements in order to drill or operate wells and also regulate the spacing and location of wells, the method of drilling and casi ng wells, the surface use and rest oration of properties upon which wells are drilled, the plugging and abandoning of wells and the prevention and cleanup of pollutants and other matters. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relie f. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely a ffect our operations and financial position, as well as those in the natural gas and oil industry in general. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing require ments will not have a material adverse impact on us, there
can be no assurance that this will continue in the future.

The Oil Pollution Act, as amended, or the OPA, and regulations thereunder impose a variety of requirements on “responsible parties” related to the prev ention of oil spills and liability for damages resulting from such spills in United States’ waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is lo cated. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligen ce or willful misconduct or resulted from violation of a federal safety, construction or operating regulati on. If the party fails to report a spill or to cooperate full y in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the pr eparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration cost s that could be incurred in connection with an oil spill.

CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for th e release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardou s substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous subs tances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighbor ing landowners and other third parties to file claims for personal injury and property damage allegedly caused by th e hazardous substances released into the environment.

The Resource Conservation and Recovery Act, as ame nded, or the RCRA, generally does not regulate wastes generated by the exploration and production of natural gas a nd oil. The RCRA specifically excludes from the definition of hazardous waste “drilling fluids , produced waters and other wastes associat ed with the exploration, development or production of oil, natural gas or geothermal energy.” Howe ver, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and pr oduction wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant imp act on our operating costs, as well as the natural gas and oil industry in general. Moreover, ordinary industrial wastes, such as paint wastes , waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

Our activities in Canada have to date been limited to certa in geological and geophysical activities that are not subject to extensive environmental regulation. Once we begin expl oration activities in New Brunswick, we will be subject to federal, provincial and local environmental regulations that we believe require compliance efforts comparable to those required in the United States.

We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration and production of natural ga s and oil. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties have be en operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the Clean Water Act, the RCRA and analogous state laws . Under such laws, we could be required to remove or20 remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

The Federal Water Pollution Control Act, as amended, or the FWPCA, imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct co nstruction activities in waters and wetlands. The FWPCA and similar state laws provide for civil, criminal and administra tive penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elim ination System general permits issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Although the costs to comply with zero discharge mandates under federal or state law may be significant, the entire industry is expected to expe rience similar costs and we believe that these costs will not have a material adverse impact on our results of operations or financial position. The EPA has adopted regulations requiring certain natural gas and oil exploration and produc tion facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.

In the past few years, there has been an increased focus on environmental aspects of hydra ulic fracturing practices at the federal, state and local levels of government although hydra ulic fracturing is typically regulated by state oil and natural gas commissions. The EPA has asserted fe deral regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition to the EPA’s effort s, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fr acturing process. There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For a discussion of hydraulic fracturing related environmental legislation, we refer you to “Exploration and Production — Regulation of Hydraulic Fracturing” and the risk factor “Our financial condition and results of operation could be adversely affected by legisla tive and regulatory initiatives in the United States and Canada relating to hydraulic fracturing that could result in increased costs and additional operating restrictions or delays or preven t us realizing the value of undeveloped acreage” in Item 1A of Part I of this Form 10-K.

Employees

As of December 31, 2012, we had 2,427 total employees. None of our employees we re covered by a collective bargaining agreement at year-end 2012. We believe that our relationships with our employees are good.21 GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below apply to the indicated terms as used in this Form 10-K. All natural gas reserves and production reported in this Form 10-K are stated at the legal pr essure base of the state or area where the reserves exist and at 60 degrees Fahrenheit.

“Acquisition of properties ” Costs incurred to purchase, lease or otherwis e acquire a property, including costs of lease bonuses and options to purchase or lease properties, the por tion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties. For additional information, see the SEC’s definition in Rule 4-10(a) (1) of Regulation S-X, a link for which is available at the SEC’s website, http://www .sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Analogous reservoir ” Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and dr ive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
For additional information, see the SEC’s definition in Rule 4- 10(a) (2) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Available reserves ” Estimates of the amounts of oil and natural gas which the registrant can pr oduce from current proved developed reserves using presently installed equipment under existing economic and operating conditions and an estimate of amounts that others can deliver to the registrant under long-term contracts or agreements on a per-day, per-month, or per-year basis. For additional information, see the SEC’s defi nition in Item 1207(d) of Regulation S-K, a link for which is available at the SEC's website, http://www.s ec.gov/divisions/corpfin/ecfrlinks.shtml.

“Bbl ” One stock tank barrel, or 42 U.S. gallons liquid volume, us ed herein in reference to oil or other liquid hydrocarbons.

“Bcf ” One billion cubic feet of natural gas.

“Bcfe ” One billion cubic feet of natural gas equivalent. Determ ined using the ratio of one barrel of oil to six Mcf of natural gas.

“Btu ” British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Dekatherm ” One million British thermal units (Btu).

“Deterministic estimate ” The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. For additional information, see the SEC’s definition in Rule 4-10(a) (5) of Regulation S-X, a link for which is available at the SEC’s website, http ://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Developed oil and gas reserves ” Developed oil and natural gas reserves are rese rves of any category that can be expected
to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
For additional information, see the SEC’s definition in Rule 4- 10(a) (6) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.22 “Development costs ” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and othe r costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well loca tions for the purpose of determining specific development drilling sites, clearing gr ound, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stra tigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii) Acquire, construct, and install prod uction facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.
For additional information, see the SEC’s definition in Rule 4- 10(a) (7) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Development project ” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. For additional information, see the SEC’s definition in Rule 4-10(a) (8) of Regulation S-X, a link for which is available at the SE C’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

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“Development well ” A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. For additional information, see the SE C’s definition in Rule 4-10(a) (9) of Regulation S-X, a link for which is available at the SEC’s website, h ttp://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Downspacing ” The process of drilling additional wells within a defi ned producing area to increase recovery of natural gas and oil from a known reservoir.

“EBITDA ” Represents net income (loss) attributable to Southwestern Energy common stock plus interest, income taxes, depreciation, depletion and amortization and the impairment of natural gas and oil properties. We refer you to “Business
— Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA with our net income (loss) attributable to Sout hwestern Energy from our audited financial statements.

“Economically producible ” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operatio n. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities. For additional information, see the SEC’s definition in Rule 4-10(a) (10) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divis ions/corpfin/ecfrlinks.shtml

.

“Estimated ultimate recovery (EUR) ” Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. For additional inform ation, see the SEC’s definition in Rule 4-10(a) (11) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divis ions/corpfin/ecfrlinks.shtml

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“Exploitation ” The development of a reservoir to extract its gas and/or oil.

“Exploratory well ” An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigra phic test well as those items are defined in this section. For additional information, see the SEC’s definition in Rule 4-10(a) (13) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Field ” An area consisting of a single reservoir or multiple rese rvoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. Th ere may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that ar e associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify locali zed geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. For additional information, see the SEC’s definition in Rule 4-10(a) (15) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.23 “Fracture stimulation ” A process whereby fluids mixed with proppants are injected into a wellbore under pressure in order to fracture, or crack open, reservoir rock , thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.

“Gross well or acre ” A well or acre in which the registrant owns a work ing interest. The number of gross wells is the total number of wells in which the registrant owns a working inte rest. For additional information, see the SEC's definition in Item 1208(c)(1) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Gross working interest ” Gross working interest is the working interest in a given property plus the proportionate share of any royalty interest, including overriding royalty interest, associated with the working interest.

“Infill drilling ” Drilling wells in between established producing wells to increase recovery of natural gas and oil from a
known reservoir.

“MBbls ” One thousand barrels of oil or other liquid hydrocarbons.

“Mcf ” One thousand cubic feet of natural gas.

“Mcfe ” One thousand cubic feet of natural gas equivalent. Determined using the ratio of one barrel of oil to six Mcf of natural gas.

“MMBbls ” One million barrels of oil or other liquid hydrocarbons.

“MMBtu ” One million British thermal units (Btu).

“MMcf ” One million cubic feet of natural gas.

“MMcfe ” One million cubic feet of natural gas equivalent. Determined using the ratio of one barrel of oil to six Mcf of natural gas.

“Net revenue interest ” Economic interest remaining after deducting all royalty interests, overriding royalty interests and other burdens from the working interest ownership.

“Net well or acre ” Deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals
one. The number of net wells or acres is the sum of the fracti onal working interests owned in gross wells or acres expressed
as whole numbers and fractions of whole numbers. For additiona l information, see the SEC's definition in Item 1208(c)(2) of Regulation S-K, a link for which is available at the SE C's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“NGL ” Natural gas liquids.

“NYMEX ” The New York Mercantile Exchange.

“Operating interest ” An interest in natural gas and oil that is burdened with the cost of development and operation of the
property.

“Overriding royalty interest ” A fractional, undivided interest or right to production or revenues, free of costs, of a lessee with respect to an oil or natural gas well, that overrides a working interest.

“Play ” A term applied to a portion of the exploration and pr oduction cycle following the identification by geologists and geophysicists of areas with poten tial oil and natural gas reserves.

“Present Value Index” or “PVI ” A measure that is computed for projects by dividing the dollars invested into the PV-10 resulting from the investment.

“Probabilistic estimate ” The method of estimation of reserves or resour ces is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. For additional information, see24 the SEC’s definition in Rule 4-10(a) (19) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

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“Producing property ” A natural gas and oil property with existing production.

“Productive wells ” Producing wells and wells mechanically capable of production. For additional information, see the SEC's definition in Item 1208(c)(3) of Regulation S-K, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

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“Proppant ” Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or speci ally engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

“Proved developed producing ” Proved developed reserves that can be expected to be recovered from a reservoir that is currently producing through existing wells.

“Proved developed reserves ” Proved gas and oil that are also developed gas and oil reserves.

“Proved oil and gas reserves ” Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reason able certainty to be economi cally producible—from a given date forward, from known reservoirs, and under existin g economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether determinis tic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Also referred to as “proved reserves.” For additiona l information, see the SEC’s definition in Rule 4-10(a) (22) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Proved reserves ” See “proved oil and gas reserves.”

“Proved undeveloped reserves ” Proved oil and gas reserves that are also undeveloped oil and gas reserves.

“PV-10 ” When used with respect to natural gas and oil reserv es, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of esti mated production and future development costs, using prices
and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. Also referred to as “present value.” After-tax PV-10 is also referred to as “standardized measure” and is net of future income tax expense.

“Reserve life index ” The quotient resulting from dividing total reserves by annual production and typically expressed in

years.

“Reserve replacement ratio ” The sum of the estimated net proved reserves added through discoveries, extensions, infill drilling and acquisitions (which may include or exclude reserve re visions of previous estimates) for a specified period of time divided by production for that same period of time.

“Reservoir ” A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. For additional information, see the SEC’s definition in Rule 4-10(a) (27) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/di visions/corpfin/ecfrlinks.shtml

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“Royalty interest ” An interest in a natural gas and oil property entitling the owner to a share of oil or natural gas production free of production costs.

“Tcf ” One trillion cubic feet of natural gas.

“Tcfe ” One trillion cubic feet of natural gas equivalent. Determined using the ratio of one barrel of oil to six Mcf of natural gas.25 “Unconventional play ” A term used in the natural gas and oil industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2 ) coal beds, or (3) natural gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals a nd discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to produce economic flow rates.

“Undeveloped acreage ” Those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardle ss of whether such acreage contains proved reserves. For additional information, see the SEC's definition in Item 1208(c )(4) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Undeveloped oil and natural gas reserves ” Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Also referred to as “undevelo ped reserves.” For additional information, see the SEC’s definition in Rule 4-10(a) (31) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml

.

“Undeveloped reserves ” See “undeveloped oil and natural gas reserves.”

“USD ” United States Dollar.

“Well spacing ” The regulation of the number and location of wells over an oil or natural gas reservoir, as a conservation measure. Well spacing is normally accomplished by order of the regulatory conservation commission in the applicable jurisdiction. The order may be statewide in its application (subject to change for local conditions) or it may be entered for each field after its discovery. In the operational context, “we ll spacing” refers to the area attributable between producing wells within the scope of what is permitted under a regulatory order.

“Working interest ” An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

“Workovers ” Operations on a producing well to restore or increase production.

“WTI ” West Texas Intermediate, the benchmark oil in the United States.26 ITEM 1A. RISK FACTORS

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. The risk factors described below represent what we believe are the most significant risk factors with respect to us and our business. In assessing the risks relating to our business, investors shoul d also read the other information included in this Form 10-K, including our financial statements and the related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Cautionary Statement about Forward-Looking Statements.”

A substantial or extended decline in natural gas and oil prices would have a material adverse effect on us.

In the first half of 2008, natural gas and oil prices were at or near their highest historical levels but have subsequently declined significantly. Natural gas prices declined in 2012 as compared with 2011. Further significant decline in natural gas and oil prices would have a material adverse effect on our financial position, our results of operations, our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period would negatively affect us in several ways including the following:

 our cash flow would be reduced, decreas ing funds available for capital invest ments employed to replace reserves or increase production;

 certain reserves would no longer be economic to produce, leading to both lower proved reserves and cash flow;
and



###  access to other sources of capital, such as equity or long-term debt markets, coul d be severely limited or
unavailable.

Consequently, our revenues and profitability would suffer.

Lower natural gas and oil prices and/ or increased development costs may ca use us to record ceiling test writedowns.

We use the full cost method of accounting for our natural gas and oil operations. Accordingly, we capitalize the cost to acquire, explore for and develop natura l gas and oil properties. Under the fu ll cost accounting rule s of the SEC, the capitalized costs of natural gas and oil properties – net of accumulated depreciation, depletion and amortization, and deferred income taxes – may not exceed a “ceiling limit” on a co untry-by-country basis. This is equal to the present value of estimated future net cash flows from proved natural gas and oil reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects.

These rules generally require pricing future natural gas and oil production at the unescalated natural gas and oil prices in effect at the end of each fiscal quart er, including the impact of derivatives qu alifying as cash flow hedges, utilizing the average price in the 12-month period prior to the end of each fiscal quarter. The av erage price for this period is defined as the unweighted arithmetic averag e of the first-day-of -the-month price for each month with in such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. These rules also require a write-down if the ceiling limit is exceeded. Once a write-down is taken, it cannot be reversed in future periods even if natural gas and oil prices increase.

For the year ended December 31, 2012, we incurred a ceiling test write-down of $1,939.7 million which resulted in an operating loss for our company for 2012. If natural gas and oil prices decline below levels utilized in our ceiling limit test as of December 31, 2012 and/or operating costs, development co sts, transportation costs or ba sis differentials increase, awrite-down may occur, which would adversely impact our results of operation and financial condition. Using the first-dayof-the-month prices of natural gas for the first two months of 2013 and NYMEX strip prices for the remainder of 2013, as applicable, the prices required to be used to determine th e ceiling limit could result in a ceiling test write-down in 2013.

Our level of indebtedness and the terms of our financing arrangements may adversely affect operations and limit our growth.

As of December 31, 2012, we had total indebtedness of $1 ,669.4 million, w ith no borrowings under our revolving credit facility. At February 15, 2013, we had long-term inde btedness of $1,709.6 million, including borrowings of $40.2 million under our revolving credit facility. We currently exp ect to utilize the borrowing availability under our revolving27 credit facility in order to fund a portion of our capital investment s in 2013. See also our risk factor headed “We may have difficulty financing our planned capital investments which could adversely affect our growth,” below.

The terms of our various financing agreements, including but not limited to the indentures relating to our outstanding senior notes, our revolving credit facility and the master lease agreement relating to our drilling rigs and our other equipment leases, which we collectively refer to as our “finan cing agreements,” impose restrictions on our ability and, in some cases, the ability of our subsidiaries to take a number of actions that we may otherwise desire to take, including one or more of the following:

 incurring additional debt, including guarantees of indebtedness;

 creating liens on our assets; and

 selling all or substantially all of our assets.

Our level of indebtedness and off-balance sheet obligations, and the covenants contained in our financing agreements, could have important consequences for our operations, including:

 requiring us to dedicate a substantial portion of our cash flow from operations to required payments, thereby reducing the availability of cash flow for working capital, capital investments and other general business activities;

 limiting our ability to obtain additional financing in the future for working capital, capital investments, acquisitions and general corporate and other activities;

 limiting our flexibility in pl anning for, or reacting to, changes in ou r business and the industry in which we operate; and

 detracting from our ability to succes sfully withstand a downturn in ou r business or the economy generally.

Our ability to comply with the covenants and other restrictions in our financing agreements may be affected by events beyond our control, including prevailing economic and financial conditions. If we fail to comply with the covenants and other restrictions, it could lead to an event of default and the acceleration of our obligations under those agreements. We may not have sufficient funds to make such payments. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from a public offering of securities. We cannot assure you that we will be able to generate sufficien t cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations. The terms of our financing agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through a public offering, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure you that any such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.

We may have difficulty financing ou r planned capital investments, which could adversely a ffect our growth.

We have experienced and expect to con tinue to experience substantial capital investment and working capital needs as a result of our drilling program. Our planned capital investment s for 2013 are expected to exceed the net cash generated by our operations under current natural gas prices. We expect to borrow under our revolving credit facility to fund capital
investments that are in excess of our net cash flow and cash on hand. Our ability to borrow under our revolving credit facility is subject to certain conditions. As of December 31, 2012, we were in co mpliance with the borrowing conditions of our revolving credit facility. If we are not in compliance with the terms of our revolving credit facility in the future or if the lenders under our revolving credit fac ility are unable to fulfill their commitments , we may not be able to borrow under the revolving credit facility to fund our capital investments. We also cannot be certain that other financing will be available to us on acceptable terms or at all. In the event additional capital resources are un available, we may curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our results and future operations.

Natural gas and oil prices are volatile. Volatility in natu ral gas and oil prices can adversely affect our results and the price of our common stock. This volatility also ma kes valuation of natural gas and oil producing properties difficult and can disrupt markets.

Natural gas and oil prices have historically been, and are like ly to continue to be, volatile. In recent years, there has been a significant decline in natural gas prices as evidenced by NYMEX natural gas prices ranging from a high of $13.58 per MMBtu in 2008 to a recent low of $1.91 per MMBtu in Ap ril 2012. The prices for natural gas and oil are subject to28 wide fluctuation in response to a number of factors, including:

 relatively minor changes in the supply of and demand for natural gas and oil;

 market uncertainty;

 worldwide economic conditions;

 weather conditions;

 import prices;

 political conditions in major oil producing regions, especially the Middle East;

 actions taken by OPEC;

 competition from other sources of energy; and

 economic, political and regulatory developments.

Historically we have also experienced price volatility as a result of locational differentials for our production from the Arkoma Basin and East Texas, which at any time may further widen due to pipeline or other constraints. Price volatility makes it difficult to project the return on exploration and development projects involving our natural gas and oil properties and to estimate with precision the value of producing properties that we may own or propose to acquire. In addition, unusually volatile prices often disrupt the market for natura l gas and oil properties, as buyers and sellers have more difficulty agreeing on the purchase price of such properties. Our results of oper ations may fluctuate significantly as a result of, among other things, variations in natural gas and oil prices and production performan ce. In recent years, natural gas and oil price volatility has b ecome increasingly severe.

The recent adoption of financial reform legislation could have an adverse eff ect on our ability to use derivative
instruments to reduce the effect of co mmodity price, interest ra te and other risks associ ated with our business
which could have a material adverse effect on our financial position, results of opera tions and cash flows.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was passed by Congress and subsequently signed into law. The new legislation require d the Commodities Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementi ng the new legislation within 360 days from the date of enactment. The CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade execution requirements in connection with ou r derivative activities. At this time it is not possible to predict whether or when the CFTC will adopt those rules or in clude comparable provisions in its rulemaking under the new legislation or how those rules will apply to us. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and such developments may affect the business relationships we have with those counterparties. The new legislation and any new regulations co uld significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available li quidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks, reduce our ability to monetize or restructure our existing derivative contract s, increase our exposure to less creditw orthy counterparties and limit our access to the capital necessary to grow our business. If, as a result of the legislation and regulations, we are no longer able to use derivatives as we have in the past, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan fo r and fund capital investments. Our revenues could also be adversely affected if a consequence of the legislation and regulations is lower comm odity prices. Any of these consequences could have a material adve rse effect on our financial position, results of operations and cash flows.

Working interest owners of some of our properties may be unwilling or unable to cover their portion of development costs, which could change our exploration and development plans.

Some of our working interest owners may have difficulties obtaining the capital needed to finance their activities, or may believe that estimated drilling and completion costs are excessive. As a result, these working interest owners may choose not to participate in certain wells or be unable or unwilling to pay their share of well costs as they become due. These actions could cause us to change our development plans for the affected properties.29 Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to
be inaccurate.

Our reserve data represents the estimates of our reservoir engineers made under the supervision of our management. Our reserve estimates are audited each year by Netherland, Se well & Associates, Inc., or NS AI, an independent petroleum engineering firm. In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently develop reserve estimates. NSAI’s audit consis ts primarily of substantive testing, which includes a detailed review of major properties that account fo r approximately 93% of present worth of our total proved reserves. NSAI’s audit process consists of sorting all fields by descending presen t value order and selecting the fields from highest value to descending value until the selected fields account for more th an 80% of the present worth of our reserves. The properties in the bottom 20% of the total present worth are not reviewed in the audit. The fields included in approximately the top 93% present value as of December 31, 2012 accounted for approximately 95% of our to tal proved reserves and approximately 98% of our proved undeveloped reserves. In the conduct of its audit, NSAI did not independently verify the data we provided to them with respect to ownership interests, oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. NSAI has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data. On January 17, 2013, NSAI issued its audit opinion as to the reasonableness of our reserve estimates for the year ended December 31, 2012, stating that our estimated proved oil and natural gas reserv es are, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Natural gas and oil reserves cannot be measured exactly. Our estimate of natural gas and oil reserves requires extensive judgments of reservoir engineering data and projections of cost that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates u nder the supervision of our management. Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team to which the property is assigned. The reservoir engineering and financial data included in these estimates are reviewed by senior engineers who are not part of the asset management teams and our Manager – Capital Budgeting & Reserves, who is the technical person primarily responsible for the preparation of our reserve estimates, and has over ten years of experience in petroleum engineering, including the estimation of oil and natural gas reserves. He reports to our Senior Vice President – Corporate Development, who has more than 31 years of experience in reservoir engineering, including the estimation of oil and natural gas reserves in multiple basins, both in the United States and internationally. On our behalf, the Senior Vice President – Corporate Development engages NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in
more detail below. The financial data included in the reserv e estimates are also separately reviewed by our accounting staff. Following these reviews and the au dit, the reserve estimates are submitted by our Senior Vice President – Corporate Development, to our Chief Executive Officer for his review and approval prior to the presentation to our Board of Directors. NSAI reports the results of its reserve audit to the Board of Directors with whom final authority over the estimates of our proved reserves rests. We incorporate many factors and assumptions into our estimates including:

 expected reservoir characteristics based on geological, geophysical and engineering assessments;

 future production rates based on historical performance and expected future operating and investment activities;

 future oil and natural gas prices and quality and locational differentials; and

 future development and operating costs.

Although we believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates, our actual reserves could va ry considerably from estimated quantities of proved natural gas and oil reserves (in the aggregate and for a particular geographic location), production, revenues, taxes and development and operating expenditures. In addition, our estimates of reserves may be subject to downward or upward revision based upon production history, results of future exploration and developm ent, prevailing natural gas and oil prices, severance taxes, operating and development costs and other factors. In 2012, our reserves were revised downward by 2,088.2 Bcfe, which was primarily an effect of the low natura l gas price environment encount ered during the 2012 year and was also a result of downward performance revisions. In 2011, our reserves were revised upward by 33.7 Bcfe, primarily due to improved performance in our Marcellus Shale properties, partially offset by downward performance revisions in our East Texas, Arkoma and Fayetteville properties and downward price revisi ons due to a comparative price decrease in the average 2011 price from the average 2010 price. In 2010, our reserves were revised upward by 309.6 Bcfe, primarily due to improved performance in our Fayetteville Shale properties and upward price revisions due to a comparative price increase in the average 2010 price from the average 2009 price, partially offset by downward performance revisions in our East Texas30 properties. Because we review our reserve projections for every property at the end of every year, any material change in a
reserve estimate is included in subsequent reserve reports.

Finally, recovery of undeveloped reserves generally re quires significant capital investments and successful drilling operations. As of December 31, 2012, appr oximately 821 Bcfe of our estimated prov ed reserves were undeveloped. Our reserve data assume that we can and will make these expe nditures and conduct these operations successfully, which may not occur. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for additional information regarding the uncertainty of reserve estimates.

If we fail to find or acquire additional reserves, our res erves and production will d ecline materially from their

current levels.

The rate of production from natural gas and oil properties generally declines as reserves are depleted. Unless we acquire additional properties containing proved reserves, conduct successf ul exploration and development activities, successfully apply new technologies or id entify additional behind-pipe zones or se condary recovery reserves, our proved reserves will decline materially as rese rves are produced. Future natural gas and oil production is, therefore, highly dependent upon our level of success in ac quiring or finding additional reserves.

Our drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to change.

As of December 31, 2012, we had drilled and completed 2,87 4 operated wells relating to our Fayetteville Shale play and 76 operated wells relating to our Marcellus Shale play. At year-end 2012, after the exclusion of our acreage in the traditional Fairway and the approximately 153,000 net federal acres we hold in the Ozark Highlands Unit, approximately 80% of our leasehold acreage in the Fayetteville Shale was held by production. Approximately 10% of our leasehold acreage in the Marcellus Shale was held by production at yea r-end 2012. Our drilling plans are flexible and are dependent upon a number of factors, including the extent to which we can replicate the results of our mo st successful wells in addition to the natural gas and oil commodity price environment. The de termination as to whether we continue to drill wells in our operating areas may depend on any one or more of the following factors:

 our ability to determine the most effec tive and economic fracture stimulation;

 our ability to transport our production to the most favorable markets;

 material changes in natural gas prices (including regional basis differentials);

 changes in the costs to drill, complete or operate wells and our ability to reduce drilling risks;

 the extent of our success in drilling and completing horizontal wells;

 the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services;

 success or failure of wells drilled in similar formations or which woul d use the same production facilities;

 receipt of additional seismic or other geolog ic data or reprocessi ng of existing data;

 the extent to which we are able to e ffectively operate our own drillings rigs;

 availability and cost of capital; or

 the impact of federal, state and lo cal government regulation, includin g any increase in severance taxes.

We continue to gather data about our prospects in our operating areas, and it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all.

If we fail to drill all of the wells that are necessary to ho ld our acreage, the initial le ase terms could expire, which would result in the loss of certain leasehold rights.

Leases on approximately 268,902 net acres of our Fayetteville Shale acreage will expire in the next three years if we do not drill successful wells to develop th e acreage or otherwise take action to ex tend the leases, of which 153,863 net acres are held on federal lands. Approximately 59,162 net acres of our Marcellus Shale acreage will expire in the next three years if we do not drill successful wells to develop th e acreage or otherwise take action to extend the leases. As31 discussed above under “Our drilling plans for the Fayetteville Sh ale play and Marcellus Shale play are subject to change,” our ability to drill wells depends on a number of factors, includi ng certain factors that are beyond our control. With the exception of the Ozark Highlands Unit, which is federally leased , the current rules in Arkansas relating to the Fayetteville Shale provide that each drilling unit would consist of a governme ntal section of approximatel y 640 acres and operators are permitted to drill up to 16 wells per drilling unit for each unconventional source of supply. In Pennsylvania, the location of our Marcellus Shale acreage, there are currently no rules esta blishing requirements for drilling units. However, current rules in Arkansas may change and rules may be implemented in Pennsylvania that could impair our ability to drill or maintain our acreage position. In addition, other E&P oper ator drilling activity could impair our ability to drill and maintain acreage positions. To the extent that any field ru les prevent us from successfully drilling wells in certain areas, we may not be able to drill the wells required to maintain our leasehold rights and our leasehold investments could be lost.

If our Fayetteville Shale and Marcellus Shale drilling programs fail to produce our projected supply of natural gas, our investments in our gas gathering operations could be lost. In addition, our commitments for transportation on third-party pipelines and gathering systems could make th e sale of our natural gas uneconomic, which could have an adverse effect on our results of operations, financial condition and cash flows.

Through December 31, 2012, we had invested approximately $1,038 million in our gas gathering system built for the Fayetteville Shale play and approximately $203 million in our gas gathering system built for the Marcellus Shale play. To the extent necessary to gather our production, we may make further substantial investments in the expansion of our gas gathering systems. Our gas gathering business will largely rely on natural gas sourced from our operations. Our marketing subsidiary has also entered into multiple firm transportation agreements relating to natural gas volumes produced from our Fayetteville Shale play as well as a number of firm transporta tion and gathering agreements relating to the Marcellus Shale play. As of December 31, 2012, our ag gregate demand charge commitments under these firm transportation agreements and gathering agreements were approximately $2.8 billion. If our Fayetteville Shale and Marcellus Shale drilling programs fail to produce significant supplies of natural gas, our investments in our gas gathering operations could be lost, and we could be forced to pay demand or other charges for transporta tion on pipelines and gathering systems that we would not be using. These events could have an adverse effect on our results of operations, financial condition and cash flows.

Our exploration, development and drilling efforts and our op eration of our wells may not be profitable or achieve our targeted returns.

Exploration, development, drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We invest in property, including undeveloped leasehold acreage that we believe will result in projects that will add value over time. However, we cannot assure you that all prospects will result in viable projects or that we will not abandon our initia l investments. Additionally, there can be no assurance that leasehold acreage acquired by us will be profitably developed, th at new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of ou r investment in such leasehold acreage or wells. Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after de ducting drilling, operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target PVI results is dependent upon the current and future market prices for natural gas and oil, costs associated with pr oducing natural gas and oil and our ability to add reserves at an acceptable cost. We rely to a significant extent on seismic data and other advanced technologies in identifying leasehold acreage prospects and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively prior to acquisition of leasehold acreage or drilling a well whether natural gas or oil is present or may be produced econom ically. The use of seismic data and other technologies also requires greater pre-drilli ng expenditures than traditional drilling strategies.

In addition, we may not be successful in implementing ou r business strategy of controlling and reducing our drilling and production costs in order to improve our overall return. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economi cs of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous fa ctors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, environmental and other governmental requirements and the cost of, or shortages or delays in the availability of, drilling rigs, equipment and
services.32 The success of our New Ventures projects is subject to drilling and completion technique risks and enhanced recovery methods. Our drilling results may not meet our expe ctations for reserves or production and the value of our undeveloped New Venture acreage could decline.

Many of our operations involve utilizing the latest drilling and completion techniques as developed by ourselves and our service providers in order to maximize cumulative recoveries and therefore genera te the highest possible returns. Risks that we face while drilling include, but ar e not limited to, landing our wellbore in the desired drilling z one, staying in the desired drilling zone while drilling horizontally through the form ation, running our casing the entire length of the wellbore, and being able to run tools and other eq uipment consistently throug h the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during co mpletion operations, and successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

We may inject water into formations on some of our properties to increase the production of oil, natural gas and associated liquids or employ other enhanced recovery methods in our operati ons. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of oil, natural gas and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such project s. In addition, if proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially.

Ultimately, the success of drilling and completion techniques and enhanced recovery methods can only be evaluated over time as more wells are drilled and production profiles ar e established over a sufficiently long time period. If our drilling results are less than antic ipated or we are unable to execute our dr illing program because of capital constraints, lease expirations, limited access to gather ing systems and takeaway capacity, and/ or oil, natural gas and NGL prices decline, the return on our inve stment for a particular project may not be as a ttractive as we anticipated and the value of our undeveloped acreage could decline in the future.

Our financial condition and results of operation could be ad versely affected by legislativ e and regulatory initiatives in the United States and Canada relating to hydraulic frac turing that could result in in creased costs and additional operating restrictions or delays or prevent us from realizing the value of undeveloped acreage.

We utilize hydraulic fracturing in our E&P operations as a m eans of maximizing the productivity of our wells. It is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas, and associated liquids from dense subsurface rock formations. The knowledge and expertise in fracturing techniques we have developed through our operations in the Fayetteville Shale play are being utilized in our other operating areas, currently including our Marcellus Shale acreage and in th e future expected to also include our exploration program in New Brunswick, Canada. Successful hydraulic fracturing techniques are also expected to be critical to the developm ent of our recen tly announced unconventional horizontal oil play targeting the LSBD formation in Arkansas and Louisiana. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-beari ng rock formation to allow the flow of hydrocarbons into the wellbore. In our Fayetteville Shale an d Marcellus Shale plays, the fracturing fluids we use are comprised of over 99.9% water and sand. The remaining 0.1% is comprised of small quantities of additives which contain chemical compounds such as hydrochloric acid, phosphoric acid, glutaraldehyde and sodium chloride which is used in common household products.

In the past few years, there has been an increased focus on environmental aspects of hydr aulic fracturing practices in the United States and Canada. In the United States, hydraulic fracturing is typically regulated by state oil and natural gas commissions but there has recently been a number of regulatory initiatives at the federal and local levels as well as by other state agencies. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority.

In addition, the EPA issued final rules effective as of October 15, 2012 that subject oil and gas operations (production, processing, transmission, stor age and distribution) to regulation under th e NSPS and NESHAPS programs. The EPA final rules also include NSPS standards for completions of hydrau lically fractured gas wells. Th ese standards include the REC techniques developed in the EPA's Natural Gas STAR progra m. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured . Further, the final regulations under NESHAPS include MACT standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. Based on our current operations and pr actices, management believes, such newly promulgated rules33 will not have a material adverse impact on our financial positi on, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future.

In October 2011, the EPA also announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to POTWs. The regulati ons will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014.

In addition to the EPA’s efforts, legislation has been intr oduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regula tion of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governme ntal reviews either underway or being proposed that focus on environmental aspects of hydrau lic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of e nvironmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, and while initial results were expected to be ava ilable by late 2012 and final results by 2014, to date the EPA has not released any results from the study. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

Certain states in which we operate have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste di sposal and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohib it the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currentl y conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailm ent in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.

In the Province of New Brunswick in Canada there are presently no hydraulic fracturing regulations, however the provincial government has been working on a new comprehensive regulatory framework that is e xpected to be released to the public in late 2013.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increase d operating costs in the production of oil, natural gas, and associated liquids including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federa l, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

We incur substantial costs to comply with government regulations, especi ally regulations relating to environmental protection, and could incur even greater costs in the future.

Our exploration, production, development and gas gathering and marketing operations are regulated extensively at the federal, state and local levels. We have made and will conti nue to make large expenditures in our efforts to comply with these regulations, including environmental regulation. The na tural gas and oil regulatory environment could change in ways that might substantially increase th ese costs. Hydrocarbon-pr oducing states regulate conservation practices and the protection of correlative rights. These regulations affect ou r operations and limit the quantity of hydrocarbons we may produce and sell. In addition, at the U.S. federal level, th e FERC regulates interstate transportation of natural gas under th e NGA. Other regulated matters include marketing, pric ing, transportation and valuation of royalty payments.

As an owner or lessee and operator of natural gas and oil properties, an owner of gas gathering systems, a sand mine and provider of pressure pumping services, we are subject to various federal, state and local regulations relating to discharge of materials into, and protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, an d require suspension or cessation of operations in affected areas. Changes in or additions to regulations regarding the protection of the environment could significantly increase our costs of compliance, or otherwise adversely affect our
business.34 One of the responsibilities of owning and operating natura l gas and oil properties is paying for the cost of abandonment. We may incur significant abandonment costs in the future which could adversely affect our financial results.

Natural gas and oil drilling and producing operations involv e various operating and environmental risks that could
result in substantial losses.

Our operations are subject to all the risks normally incident to the operation and development of natural gas and oil properties, the drilling of natural gas and oil wells and the sale of natural gas and oil, including but not limited to encountering well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, na tural gas, brine or well fluids, hydrocarbon drainage from adjacent third-party production,
release of contaminants into the enviro nment and other environmental hazards and risks and failure of counterparties to perform as agreed.

We maintain insurance against many potential losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent. However, our insurance does not protect us against all operational risks. For example, we generally do not maintain business interruption insurance. Additionally, pollution and environmental risks generally are not fully insurable. These risks could give rise to significant costs not covered by insurance that could have a material adverse effect upon our financial results.

Our ability to sell our natural gas and oil and/or to receive market prices for our production may be adversely affected by constraints or interruptio ns on gathering systems, pipelines, pr ocessing and transp ortation systems owned or operated by us or others.

The marketability of our natural gas and oil production depend s in part on the availability, proximity, and capacity of gathering systems, processing and pipeline and other transportation systems owned or operated by third parties. The lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lo wer price realizations. Although we have some contractual control over the transportation and gathering of our productio n, material changes in these business relationships could materially affect our operations. Federal and state regul ation of natural gas and oil production, processing and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and gene ral economic conditions could adversely affect our ability to produce, gather, and transport natural gas.

In particular, if drilling in the Mar cellus Shale play continues to be succes sful, the amount of natural gas being produced by us and others could exceed the capacity of, and result in strains on, the various gathering, and transportation systems, pipelines, and other infrastructure available in th ese areas. It will be necessary for additional infrastructure, pipelines, gathering, and transportation systems and pro cessing facilities to be expanded, built or developed to accommodate anticipated production from th ese areas. Because of the current econo mic climate, certain processing or pipeline and other gathering or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing, construction and permitting delays, permitting costs, well fees proposed in Pennsylvania, or other constraints. In addition, capital and other constraints could limit our ability to build or access intrastate gathering and transportation syst ems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansio n and/or sell production at significantly lower prices than those quoted on NYMEX, which would adversely affect our results of operations and cash flows.

A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processi ng or transportation system access or capacity, field labor issues or st rikes, or we might voluntarily curtail pr oduction in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows and results of operations.

Shortages of oilfield equipment, serv ices, supplies, raw material s and qualified personnel could adversely affect our results of operations.

The demand for qualified and experience d field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These factors also cause significant increases in costs for equipment, services, personnel and raw materials (such as sand, cement, manufactured proppants and other materials utilized in the provision of the oilfield services). Higher natural gas and oil prices generally stimulate increased35 demand and result in increased prices for drilling rigs, crew s and associated supplies, equipment, services and raw materials. In addition, our E&P opera tions also require local access to large qu antities of water supplies and disposal services for produced water in connection with our hydraulic fracture stimulations due to prohibitive transportation costs. We cannot be certain when we will expe rience shortages or price increases, which could adversely affect our profit margin, cash flow and operating results or restrict our ability to drill wells and conduct ordinary operations.

Our business could be adversely affected by competition with other companies.

The natural gas and oil industry is highly competitive, and our business could be adversely affected by companies that are in a better competitive position. As an independent natural gas and oil company, we frequently compete for reserve acquisitions, exploration leases, licenses, concessions, marke ting agreements, equipment and labor against companies with financial and other resources substantially larger than those we possess. Many of our competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties a nd prospects than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors have been operating in some of our core areas for a much longer time than we have or have established strategic long-term positions in geographic regions in which we may seek new entry.

We have made significant investments in our oilfield service operations, including our drilling rig, pressure pumping equipment and sand mine operations in order to meet certain of our oilfield service and resource needs,
lower our costs and increase of the effici ency of our operations. If our expl oration and production activities are curtailed or disrupted, these operations may adversely impact our results of operations. In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers.

We have made significant investments in order to meet certain of our oilfield services needs, including establishing our own drilling rig operations and sand mine. In 2012, we invested in and commenced providing pressure pumping services for a portion of our operated wells. We may make additional investments to expand these operations in the future. Our drilling operations are conducted through our subsidiary , DeSoto Drilling, Inc., which had 371 employees as of December 31, 2012. We have lease co mmitments for 14 drilling rigs and relate d equipment with respect to DDI's operations and we also own one drilling rig. In addition to these rigs, we have contracts with third-party drilling companies for use of their rigs which may not be terminable without penalty. In 2009, another of our subsidiaries, DeSoto Sand, L.L.C., began operating our first sand mine in Arkansas in order to meet a portion of our sand needs for the Fayetteville Shale play. We also purchase sand for use in our operations from various third parties, including certain of our oilfield service providers. Our drilling rig and sand mine ope rations may have an adverse effect on our relationships with our existing third-party service and resource providers or ou r ability to secure these services and resources from other providers. We may also compete with third-party providers for qualified personnel, which could adversely affect our relationships with such providers. If the operations of our dr illing rigs and/or sand mine are disrupted or our existing thirdparty providers discontinue their relationships with us, we may not be able to secure alternative services or resources on a timely basis, or at all. Even if we are able to secure alte rnative services or resources, ther e can be no assurance that such services or resources will be of equivalent quality or that pricing and other terms will be favorable to us. If we are unable to secure third-party services or resources or if the terms are not favorable to us, our financial condition and results of operations could be adversely affected.

We depend upon our management team and our operations req uire us to attract and retain experienced technical personnel.

The successful implementation of our business strategy and hand ling of other issues integral to the fulfillment of our business strategy depends, in part, on our experienced manage ment team, as well as certain key geoscientists, geologists, engineers and other professionals employed by us. The success of our technological initiatives that support our business enterprise is also dependent upon attracting and retaining experienced technical professionals. The loss of key members of our management team or other highly qualified technical prof essionals could have a materi al adverse effect on our business, financial condition and operating results.

If natural gas prices decline further, our failure to hedge the remaining portion of our expected 2013 production could adversely affect our results of operations and financial condition.

To reduce our exposure to fluctuations in the prices of natu ral gas and oil, historically, we have entered into hedging arrangements with respect to a significant portion of our expected production. As of February 15, 2013, we had NYMEX commodity price hedges on approximately 29% of our targeted 2013 natural gas production as compared to approximately36 30% for 2010, 52% for 2011 and 47% for 2012. Our price risk management activities increased natural gas sales by $617.6 million in 2012, increased natural gas sales by $315.6 million in 2011 and increased natural gas sales by $290.3 million in 2010. If natural gas prices decline in 2013, unle ss we enter into additional hedging arrangements, our revenues would be adversely affected. To the extent that we engage in additional hedging activities in the current price environment, we would not realize the benefit of pr ice increases above the levels of the hedges.

In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances
in which:

 our production is less than expected;

 there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

 the counterparties to our futures contr acts fail to perform the contracts; or

 a sudden, unexpected event materially impacts natural gas or oil prices.

Finally, future market price volatility could create significant changes to the hedge positions recorded on our financial statements. We refer you to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of Part II of this

Form 10-K.

Certain U.S. federal income tax deducti ons currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

The elimination of certain key U.S. federal income tax deduc tions currently available to oil and natural gas exploration and production companies has been pro posed in recent years. These changes have included, among other proposals:

 the repeal of the percentage depletion allo wance for oil and natural gas properties;

 the elimination of current deductions for intangible drilling and development costs;

 the elimination of the deduction for certain domestic production activities; and

 an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enact ed. The passage of these or any similar changes in federal income tax laws to eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development could have an adverse effect on our financial position, results of operations and cash
flows.

Our ability to produce natural gas could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable
environmental rules.

Our inability to locate sufficient amounts of water, or dispose of or recycle wa ter used in our E&P operations, could adversely impact our operations, particularly with respect to our Fayetteville Shale and Marcellus Shale operations, and also possibly our recently announced unco nventional oil play targeting the LSBD formation in Arkansas and Louisiana. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploratio n, development or production of natural gas. The Federal Water Pollution Control Act, as amended, or the FWPCA, imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The FWPCA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of o il and other hazardous substances. Many stat e discharge regulations and the Federal National Pollutant Discharge Elimination System general perm its issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydrau lic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.37 Climate change and global warming concerns could lead to additional regulatory measures that may adversely impact our operations and financial condition.

Our E&P operations are currently focused on the production of hydrocarbons from unconventional sources, and we expect to continue to focus on such resources in the futu re. The production of hydrocarbons from these sources has an energy intensity that is a number of times higher than that for production from conventional sources. Therefore, we expect that the carbon dioxide, or CO2, intensity of our production will increase in the long-term. We actively seek to reduce the environmental impact of our operations by pursuing more efficient use of natural resources such as hydrocarbons and water and managing and mitigating the emissions to the air, water and soil, with a focus on the reduction of greenhouse gas emissions. With the efforts of our Health, Safety and Environmental Department, we have been able to plan for and comply with environmental in itiatives without materially altering our opera ting strategy. We anticipate making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment that will increase the cost of equipment, ma terials and services whose production utilizes hydrocarbons. We may also face increased competition from alternative energy so urces that do not rely on hydrocarbons. We cannot predict with any reasonable degree of certainty our future expo sure concerning such matters and if we are unable to find solutions to environmental initiatives as they arise, including reducing the CO2 emissions for our existing projects, we may have additional costs as well as compliance and operational risk s with respect to our existing operations as well as facing difficulties in pursuing new projects.

Our certificate of incorporation and, bylaws contain provisions that could ma ke it more difficult for someone to either acquire us or affect a change of control.

Certain provisions of our certificate of incorporation and bylaws, together with any stockholder rights plan that we might have in place, could discourage an effort to acquire us, gain control of the company, or replace members of our executive management team. These provisions could potentially deprive our stockholders of opportunities to sell shares of our common stock at above-market prices.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES

The summary of our oil and natural gas reserves as of fis cal year-end 2012 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2012 Proved Reserves by Category and Summary Operating Data” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Form 10-K and incorporated by reference into this Item 2. Our proved reserves are based upon esti mates prepared for each of our properties annually by the reservoir engineers assigned to the asset management team in the geographic locations in which the property is located. These estimates ar e reviewed by senior engineers who are not part of the asset management teams and by our Manager – Capital Budgeting & Reserves, who is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Manager – Capital Budgeting & Reserves has more than ten years of experience in petroleum engineering, including the estimation of oil and natural gas reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining us in 2009, our Manager – Capital Budgeting & Reserves served in various reservoir engineering roles for Kinder Morgan CO2 and Citati on Oil & Gas and is a member of the Society of Petroleum Engineers. He reports to our Senior Vice President – Corporate Development who has more than 31 years of experience in reservoir engineering including the estimation of oil and natura l gas reserves in multiple basins both in the United States and internationally. Prior to joining Southwestern in 2008, our Senior Vice President – Corp orate Development served in various engineering and senior management roles for Tenneco Oil Company, Enron Oil & Gas Company, Enron Global Exploration & Production, El Paso Energy and The Houston Exploration Company, and is a member of the Society of Petroleum Engineers, IPAA, Tipro and the Houston Producer’s Forum. On our behalf, the Senior Vice President – Corporate Development engages Netherland, Sewell & Associ ates, Inc., or NSAI, a worl dwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves estimates (1) have over 26 y ears and over 11 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 22 years and over 11 years of experience in the estimation and evaluation of reserves, respectively; (3) each has a college degree; (4) each is a Licensed Professional
Geoscientist in the State of Texas or a Li censed Professional Engineer in the Stat e of Texas; (5) each meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and (6) each is proficient in judiciously38 applying industry standard practices to engineering and ge oscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates are also separately reviewed by our accounting staff. Our proved reserves estim ates, as internally reviewed and audite d by NSAI, are submi tted for review and approval to our Chief Executive Officer. Finally, upon his appr oval, NSAI reports the results of its reserve audit to the Board of Directors with whom final authority over the estimates of our proved reserves rests. A copy of NSAI's report has
been filed as Exhibit 99.1 to this Form 10-K.

The information regarding our proved undeveloped reserves required by Item 1203 of Regulation S-K is included under the heading “Proved Undeveloped Reserves” in “Business – Exploration and Production – Our Proved Reserves” in
Item 1 of this Form 10-K.

The information regarding delivery commitments required by Item 1207 of Regulation S-K is included under the heading “Sales, Delivery Commitments and Customers” in the “Business – Exploration and Production – Our Operations” in Item 1 of this Form 10-K and incorporated by reference into this Item 2. For additional information about our natural gas and oil operations, we refer you to Note 4 to the consolidat ed financial statements. For information concerning capital investments, we refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Investments.” We also refer you to Item 6, “Selected Financial Data” in Part II of this Form 10-K for information concerning natural gas and oil produced.

The information regarding oil and gas properties, wells, operations and acreage required by Item 1208 of Regulation
S-K is set forth below:

Leasehold acreage as of December 31, 2012:

Undeveloped Developed

Gross Net Gross Net

Fayetteville Shale Play (1) 529,863 308,924 798,720 479,925 Marcellus Shale Play (2) 174,238 159,078 17,900 17,220

Ark-La-Tex:

Conventional Arkoma (3) 70,316 63,341 194,313 175,599

East Texas (4) 4,427 1,874 65,911 47,466

N ew Ventures:

USA New Ventures – LSBD (5) 740,058 504,486 2,573 2,573

USA New Ventures – Other (6) 1,104,672 741,724 643 643

Canada New Ventures (7) 2,572,918 2,572,918 – –
5,196,492 4,352,345 1,080,060 723,426

(1) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the n ext three years will be 46,007 net acres in 2013, 183,824 net acres in 2014, which includes 153, 863 net acres held on federal lands, and 39,071 net acres
in 2015.

(2) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the n ext three years will be 41,860 net acres in 2013, 13,467 net acr es in 2014 and 3,835 net acres in 2015.

(3) Includes 123,442 net developed acres and 1, 211 net undeveloped acres in the Arkoma Basin that are also within our Fayettevi lle Shale focus area but not included in the Fayetteville Shale acreage in the table above. Assuming successful wells are not drilled to develop the acreage and leases are not extended, lease hold expiring over the next three years w ill be 1,200 net acres in 2013, 670 net acre s in 2014 and 17,788 net acres in 2015.

(4) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the n ext three years will be 1,340 net acres in 2013, 152 net acres in 2014 and 202 net acres in 2015.

(5) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the n ext three years will be 68,023 net acres in 2013, 237,181 net acres in 2014 a nd 159,718 net acres in 2015.

(6) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the n ext three years will be 1,120 net acres in 2013, 60,294 net acres in 2014 and 142,294 net acres in 2015.

(7) Assuming successful wells are not drilled to develop the acreag e and our exploration license ag reements are not extended, 2 ,518,518 net acres in New Brunswick will expire in Marc h 2015. We have applied for an additional 1-year option to extend our exploration lic ense agreements in New Brunswick and, if gran ted by the Province, this would extend our exploration license agreements until March 2 016.39 Producing wells as of December 31, 2012:

Natural Gas Oil Total Gross Wells Gross Net Gross Net Gross Net Operated

Fayetteville Shale Play 3,228 2,186 – – 3,228 2,186 2,725 Marcellus Shale Play (1) 132 71 – – 132 71 72

Ark-La-Tex:

Conventional Arkoma (2) 1,180 570 – – 1,180 570 550

East Texas (3) 166 106 7 4 173 110 134

N ew Ventures 3 3 1 1 4 4 4
4,709 2,936 8 5 4,717 2,941 3,485

(1) As of December 31, 2012, this includes 58 gross natural gas wells in which we own an overriding royalty interest.

(2) As of December 31, 2012, this includes 148 gross natura l gas wells in which we own an overriding royalty interest.

(3) As of December 31, 2012, this includes 1 gross oil well a nd 12 gross natural gas wells in which we own an overriding royal ty interest.

The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation S-K is set forth below:

Exploratory (1)

Productive Wells Dry Wells Total

Year Gross Net Gross Net Gross Net

2012 7.0 7.0 – – 7.0 7.0

2011 1.0 0.6 – – 1.0 0.6

2010 – – – – – –

Development (1)

Productive Wells Dry Wells Total

Year Gross Net Gross Net Gross Net

2012 (2) 376.0 257.0 9.0 6.7 385.0 263.7

2011 446.0 307.7 – – 446.0 307.7

2010 (3) 483.0 305.5 3.0 1.9 486.0 307.4

(1) We have not drilled any exploratory or developm ent wells in Canada in the past three years.

(2) 2012 dry wells include 5 gross wells that were use for scien ce in the Ozark Highlands Unit th at were not intended to produc e.

(3) 2010 dry wells include 2 gross wells (1.6 net wells) in th e Fayetteville Shale play that were plugged and abandoned due to mechanical issues encountered during drilling.40 The following table presents the information regarding our present activities required by Item 1206 of Regulation S-K:

Wells in progress as of December 31, 2012: (1)

Gross Net

Drilling: Exploratory – – Development 94.0 78.7

Total 94.0 78.7

Completing: Exploratory 1.0 1.0 Development 108.0 85.2

Total 109.0 86.2

Drilling & Completing: Exploratory 1.0 1.0 Development 202.0 163.9

Total 203.0 164.9

(1) As of December 31, 2012, we did not have any drilling activities in Canada.

The information regarding oil and gas production, production prices and production costs required by Item 1204 of Regulation S-K is set forth below:

Production, Average Sales Pri ce and Average Production Cost:

For the years ended December 31,

2012 2011 2010

Natural Gas

Production (Bcf):

Fayetteville Shale 485.5 436.8 350.2

Marcellus Shale 53.6 23.4 1.0

Total 564.5 499.4 403.6

Average gas price per Mcf, excluding hedges:

Fayetteville Shale $ 2.30 $ 3.52 $ 3.89

Marcellus Shale 2.55 3.80 3.78

Total $ 2.34 $ 3.56 $ 3.93

Average gas price per Mcf, including hedges $ 3.44 $ 4.19 $ 4.64

Oil

Oil production (MBbls) (1) 83 97 171 Average oil price per Bbl (1) $ 101.54 $ 94.08 $ 76.84

Average Production Cost

Cost per Mcfe, excluding ad valorem and severance taxes:

Fayetteville Shale $ 0.83 $ 0.88 $ 0.86

Marcellus Shale 0.46 0.27 0.57

Total $ 0.80 $ 0.84 $ 0.83

(1) Our Fayetteville Shale and Marcellus Shale operations did not produce any oil for the years ended December 31, 2012, 2011 a nd 2010.

During 2012, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas Reserves,” with the U.S. Department of Energy. The basis for reporting reserves on Form 23 is not comparable to the reserve data included in Note
4 to the consolidated financial statements in Item 8 to this Form 10-K. The primary differ ences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we are the
operator.41 Miles of Pipe

As of December 31, 2012, our Midstream Services segment had 1,852 miles, 57 miles and 25 miles of pipe in its gathering systems located in Arkansas, Pennsylvania, and Texas, respectively.

Title to Properties

We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas indu stry. Our properties are subject to cu stomary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for cu rrent taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped prop erties, we endeavor to perform a title investigation that is thorough but less vigorous than that we endeavor to conduct pr ior to drilling, which is consistent with standard practice in the oil and natural gas industry. Generally, before we commence drilling operations on properties that we operate, we endeavor to conduct a thorough title examination and perfor m curative work with respect to significant defects before proceeding with operations. We believe that we have perfor med a thorough title examination with respect to substantially all of our active properties that we operate.42 ITEM 3. LEGAL PROCEEDINGS

We are subject to laws and regulations relating to the protection of the e nvironment. Our policy is to accrue environmental and cleanup related costs of a non-capital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Manageme nt believes any future remediation or other compliance
related costs will not have a material effect on our financ ial position, results of operations, and cash flows.

Tovah Energy

In February 2009, SEPCO was added as a defendant in a Third Amended Petition in the matter of Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al. In the Sixth Amended Petition, filed in July 2010, in the 273rd District Court in Shelby County, Texas (collectively, the “S ixth Petition”), plaintiff alleged that, in 2005, they provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom. Among other things, the plainti ff’s allegations in the Sixth Petition included various statutory and common law claims, including, but not limited to claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduci ary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 15, 2005 and February 15, 2006. In the Sixth Petition, plaintiff sought actual damages of over $55.0 million as well as other remedies, including special damages and punitive damages of four times the amount of actual damages established at trial.

Immediately before the commencement of the trial in November 2010, plaintiff was permitted, over SEPCO’s objections, to file a Seventh Amended Petition claiming actual damages of $46.0 million and also seeking the equitable remedy of disgorgement of all profits fo r the misappropriation of trade secrets a nd the breach of fiduciary duty claims. In December 2010, the jury found in favor of the plaintiff with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages. The jury did not, however, award the plaintiff any special, punitive or other damages. In addition, the jury separately determined that SEPCO’s profits for purpose s of disgorgement were $381.5 million. This profit determination does not constitute a judgment or an award. The plaintiff’ s entitlement to disgorgement of profits as an equitable remedy will be determined by th e judge and it is within the judge’s discretion to award none, some or all the amount of prof it to the plaintiff. On Decem ber 31, 2010, the plaintiff file d a motion to enter the judgment based on the jury’s verdict. On February 11, 2011, SEPCO filed a motion for a judgment notwithstanding the verdict and a motion to disregard certain findings. On March 11, 2011, the plaintiff filed an amended motion for judgment and intervenor filed its motion for judgment seeking not only the monetary damages and the profits determined by the jury but also seeking, as a new remedy, a constructive trust for prof its from 143 wells as well as future drilling and sales of properties in the prospect areas. A hear ing on the post-verdict motions was held on March 14, 2011. At the suggestion of the judge, all parties voluntarily agreed to participate in non-binding mediation efforts. The mediation occurred on April 6, 2011 and was unsuccessful. On June 6, 2 011, SEPCO received by mail a letter date d June 2, 2011 from the judge, in which he made certain rulings with respect to the post-verdict motions and responses filed by the parties. In his rulings, the judge denied SEPCO’s motion for judgment, judgment notwithstanding th e verdict and to disregard certain findings. Plaintiff’s
and intervenor’s claim for a constructive trust was denied but the judge ruled that plaintiff and intervenor shall recover from SEPCO $11.4 million and a reasonable attorney’s fee of 40% of the total damages awarded and are entitled to recover on their claim for disgor gement. The judge instructed that SEPCO calcu late the profit on the designated wells for each respective period. SEPCO performed the calculation and provided it to the judge in June 2011. On July 5, 2011, plaintiff and intervenor filed a letter with the court raising objections to the accounting provided by SEPCO, to which SEPCO filed a response on July 11, 2011. On July 12, 2011, the judge sent a letter to the parties in which he ruled that after reviewing the parties’ respective position letters, he was awarding $23.9 million in disgorgement damages in favor of the plaintiff and intervenor. In the July 12, 2011 letter, the judge instructed the plaintiff and intervenor to prepare a judgment for his approval prior to July 21, 2011 consistent with his findings in his June 2, 2011 letter and the disgorgement award. On August 24, 2011, a judgment was entered pursuant to which plaintiff and intervenor are entitled to recover approximately $11.4 million in actual damages and approximately $23.9 milli on in disgorgement as well as prejudgment interest and attorneys' fees which currently are estimated to be up to $8.9 million and all costs of court of the plaintiff and intervenor. On September 23, 2011, SEPCO filed a motion for a new trial and on November 18, 2011 filed a notice of appeal. On November 30, 2011, the court approved SEPCO’s supersedeas bo nd in the amount of $14.1 mi llion, which stays executionon the judgment pending appeal. The bond covers the $11.4 million judgment for actual damages, plus $1.3 million in prejudgment interest, $1.3 million in post-judgment interest (estimating two years for the duration of appeal), and court costs.43On June 22, 2012, SEPCO filed its appellate brief and, on June 25, 2012, plaintiff and intervenor filed a crossappellate brief seeking limited remand to reassess the disgorgement determination. The parties filed their responses to the appellate and cross-appellate briefs on or about November 7, 2012. Both sides filed replies to the opposing party’s responses in January 2013. Oral argument s are expected to o ccur in spring 2013. Based on the Company's understanding and judgment of the facts and merits of this case, including appellate defenses, and after considering the advice of counsel, the Company has determined that, although reasonably possible after exhaustion of all appeals, an adverse final outcome to this lawsuit is not probable. As such, the Company has not accrued any amounts with respect to this lawsuit. If the plaintiff and intervenor were to ultimately prevail in the ap pellate process, the Company currently estimates, based on the judgments to date, that SEPCO’s potential liability would be up to $44.2 million, including interest and attorney’s fees. The Company’s assessment may change in the future due to occurrence of certain even ts, such as denied appeals, and such re-assessment could lead to the determination that the potential liability is probable and could be material to the Company's results of operations, financial position or cash flows.

Muncey

On February 20, 2012, the Company b ecame aware that SEPCO was named as a defendant in the matter of Gery Muncey v. Southwestern Energy Production Company, et al filed in the District Court of San Augustine County in Texas on January 31, 2012. The plaintiff in this case is also the intervenor in the Tovah Energy matter described above and alleged various claims including fraud, misappropriation and breach of fiduciary duty that are purportedly independent of the claims alleged in the Tovah Energy matter but arise from the substantially same circumstances involved in the Tovah Energy matter. SEPCO’s motion for summary judgment was granted on July 9, 2012. On August 22, 2012, the court signed a final take-nothing judgment in SEPCO’s favor. The de adlines for filing appeals have expired, so this matter has
been resolved in SEPCO’s favor.

Bureau of Land Management

In March 2010, the Company’s subsidiary, SEECO, was serv ed with a subpoena from a federal grand jury in Little Rock, Arkansas. Based on the documents requested under the subpoena and subsequent discussions described below, the Company believes the grand jury is investigating matters in volving approximately 27 horizontal wells operated by SEECO in Arkansas, including whether appropriate leases or permits were obtained therefor and whether royalties and other production attributable to federal lands have been proper ly accounted for and paid. The Company believes it has fully complied with all requests related to the federal subpoena an d delivered its affidavit to that effect. The Company and representatives of the Bureau of Land Management and the U.S. Attorney have had discussions since the production of the documents pursuant to the subpoena. In January 2011, the Company voluntarily produced additional materials informally requested by the government arising from these discussions. Although, to the Company’s knowledge, no proceeding in this matter has been initiated against SEECO, the Company cannot predict whether or when one might be initiated. The Company intends to fully comply with any further requests a nd to cooperate with any relate d investigation. No assurance
can be made as to the time or resources that will need to be de voted to this inquiry or the impact of the final outcome of the discussions or any related proceeding.

Other

We are subject to various litigation, claims and proceedings that have arisen in the ordinary course of business. Management believes, individually or in aggregate, such litigation, claims and pro ceedings will not have a material adverse impact on our financial position, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future. If an un favorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such ite ms when a liability is both probable and the amount can be reasonably estimated.

ITEM 4. MINE SAFETY DISCLOSURES

Our sand mining operations in support of our E&P business, are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and H ealth Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.1 06) is included in Exhibit 95.1 to this Form 10-K.44 PART II

ITEM 5. MARKET FOR REGISTRANT’S COMM ON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is traded on the New York Stock Exchange, or the NYSE, under the symbol “SWN.” On February 15, 2013, the closing price of our stock was $33.04 and we had 3,110 stockholders of record. The following table presents the high and low sales prices for closing mark et transactions as reported on the NYSE.

Range of Market Prices Quarter Ended 2012 2011 2010

March 31 $ 35.60 $ 29.06 $ 43.49 $ 36.12 $ 51.65 $ 37.70

June 30 $ 32.46 $ 25.82 $ 43.86 $ 38.02 $ 44.99 $ 35.86 September 30 $ 35.76 $ 30.55 $ 49.00 $ 33.33 $ 38.83 $ 31.44

December 31 $ 36.60 $ 32.78 $ 44.21 $ 31.94 $ 38.45 $ 32.73

We have indefinitely suspended payment of quarterly cash dividends on our common stock.

Issuer Purchases of Equity Securities

During 2012, we retired 11,357 shares for the payment of withholding taxes due on employee stock plan share issuances. All changes in common stock in treasury in 2012 were due to purchases and sales of shares held on behalf of participants in a non-qualified deferred compensation supplemental retirement savings plan. We refer you to Note 1 to our

consolidated financial statements in Item 8 of Part II.

Recent Sales of Unregistered Equity Securities

We did not sell any unregistered equity securities during 2012.45 STOCK PERFORMANCE GRAPH

The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index. The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2007, and that all dividends were reinvested. Th e stock performance shown on the graph below is not indicative of future price performance.

12/31/07 12/31/08 12/31/09 12/31/10 12/31/11 12/31/12 Southwestern Energy Company 100 104 173 134 115 120 Dow Jones U.S. Exploration & Production 100 63 80 92 94 109

S&P 500 Index 100 60 84 98 94 10046 ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth a summary of selected historical fina ncial information for each ofthe years in the fiveyear period ended December 31, 2012. This information and th e notes thereto are derived from our consolidated financial statements. We refer you to “Managemen t’s Discussion and Analysis of Financ ial Condition and Results of Operations”
and “Financial Statements and Supplementary Data.”

2012 2011 2010 2009 2008 (in thousands except share, per shar e, stockholder data and percentages)

Financial Review Operating revenues:

Exploration and production $ 1,948,222 $ 2,100,488 $ 1,890,444 $ 1,593,231 $ 1,491,302

Midstream services 2,363,480 2,859,519 2,453,840 1,603,332 2,173,971

Gas distribution and other 2,865 3,268 984 687 118,399 Intersegment revenues (1,599,524) (2,010,369) (1,734,605) (1,051,471) (1,472,120) 2,715,043 2,952,906 2,610,663 2,145,779 2,311,552 Operating costs and expenses:

Gas purchases – midstream services 592,466 709,091 611,161 482,836 710,129 Gas purchases – gas distribution

– – – – 61,439 Operating and general 419,882 398,985 337,334 259,159 209,536 Depreciation, depletion and amortization 810,953 704,511 590,332 493,658 414,408 Impairment of natural gas and oil properties 1,939,734 – – 907,812 –
Taxes, other than income taxes 67,584 65,518 50,608 37,280 29,272 3,830,619 1,878,105 1,589,435 2,180,745 1,424,784 Operating income (loss) (1,115,575) 1,074,801 1,021,228 (34,966) 886,768

Interest expense, net 35,657 24,075 26,163 18,638 28,904
Other income, net 1,030 264 427 1,449 4,404 Gain on sale of utility assets

– – – – 57,264
Income (loss) before income taxes (1,150,203) 1,050,990 995,492 (52,155) 919,532
Provision (benefit) for income taxes:

Current 18,689 4,198 11,939 (64,969) 122,000

Deferred (461,828) 409,023 379,720 48,606 228,999
(443,139) 413,221 391,659 (16,363) 350,999

N et income (loss) (707,064) 637,769 603,833 (35,792) 568,533 Less: net income (loss) attributable to

noncontrolling interest

– – (285) (142) 587

N et income (loss) attribut able to Southwestern

Energy $ (707,064) $ 637,769 $ 604,118 $ (35,650) $ 567,946
Return on equity (1) (23.3%) 16.1% 20.4% (1.5%) 22.6%

N et cash provided by operating activities $ 1,653,942 $ 1,739,817 $ 1,642,585 $ 1,359,376 $ 1,160,809

N et cash used in investing activities $ (1,906,677) $ (2,024,790) $ (1,725,631) $ (1,780,604) $ (792,078)

N et cash provided by (used in) financing

activities $ 290,889 $ 284,303 $ 86,240 $ 238,135 $ (174,286)

Common Stock Statistics Earnings per share:

N et income (loss) attribut able to Southwestern

stockholders – Basic $ (2.03) $ 1.84 $ 1.75 $ (0.10) $ 1.66

N et income (loss) attribut able to Southwestern

stockholders – Diluted $ (2.03) $ 1.82 $ 1.73 $ (0.10) $ 1.64 Book value per average diluted share (1) $ 8.71 $ 11.34 $ 8.49 $ 6.82 $ 7.27 Market price at year-end $ 33.41 $ 31.94 $ 37.43 $ 48.20 $ 28.97

N umber of stockholders of record at yea r -end 3,122 3,083 3,043 2,639 2,497 Average diluted shares outstanding 348,610,503 349,921,413 349,310,666 343,420,568 346,245,938

(1) The return on equity and the book value per average diluted share calculations have been r ecalculated for 2008 and now incl ude an addition to equity for the Company’s noncontrolling interest in partnership.47 2012 2011 2010 2009 2008

Capitalization (in thousands)

Total debt $ 1,669,473 $ 1,343,300 $ 1,094,200 $ 998,700 $ 735,400 Total equity 3,035,872 3,969,304 2,964,876 2,340,981 2,517,963 Total capitalization $ 4,705,345 $ 5,312,604 $ 4,059,076 $ 3,339,681 $ 3,253,363

Total assets $ 6,737,527 $ 7,902,897 $ 6,017,463 $ 4,770,250 $ 4,760,158
Capitalization ratios:

Debt 35.5% 25.3% 27.0% 29.9% 22.6% Equity 64.5% 74.7% 73.0% 70.1% 77.4%

Capital Investments (in millions) (1)
Exploration and production 1,860.7 1,977.5 1,775.5 1,565.5 1,595.8

Midstream services 165.0 160.8 271.3 214.2 183.0

Other 54.9 68.9 73.3 29.4 17.4 $ 2,080.5 $ 2,208.0 $ 2,120.1 $ 1,809.1 $ 1,796.2

Exploration and Production Natural gas:

Production, Bcf 564.5 499.4 403.6 299.7 192.3 Average price per Mcf, including hedges $ 3.44 $ 4.19 $ 4.64 $ 5.30 $ 7.52 Average price per Mcf, excluding hedges $ 2.34 $ 3.56 $ 3.93 $ 3.34 $ 7.73

Oil:

Production, MBbls 83 97 171 124 385 Average price per barrel, including hedges $ 101.54 $ 94.08 $ 76.84 $ 54.99 $ 107.18 Average price per barrel, excluding hedges $ 101.54 $ 94.08 $ 76.84 $ 54.99 $ 107.18 Total natural gas and oil production, Bcfe 565.0 500.0 404.7 300.4 194.6 Lease operating expenses per Mcfe $ 0.80 $ 0.84 $ 0.83 $ 0.77 $ 0.89

General and administrativ e expenses per Mcfe $ 0.26 $ 0.27 $ 0.30 $ 0.35 $ 0.41 Taxes, other than income taxes per Mcfe $ 0.10 $ 0.11 $ 0.11 $ 0.11 $ 0.13 Proved reserves at year-end:

Natural gas, Bcf 4,017 5,887 4,930 3,650 2,176
Oil, MMBbls 1 1 1 1 2
Total reserves, Bcfe 4,018 5,893 4,937 3,657 2,185

Midstream Services
Gas volumes marketed, Bcf 676.2 611.4 495.8 382.5 258.0
Gas volumes gathered, Bcf 845.5 745.7 588.3 387.1 224.1

(1) Capital investments include a decrease of $36.9 million for 2012, and increases of $4.3 mi llion for 2011, $14.4 million for 2010, $12.2 million for 2009 and $36.2 million for 2008 related to the ch ange in accrued expenditures between years.48 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

This Form 10-K contains forward-looking statements that involve risks and uncertaintie s. Our actual results could differ materially from those anticipated in forward-looking st atements for many reasons, including the risks described in the “Cautionary Statement About Forward-Looking Statements” belo w, in Item 1A, “Risk Factors” in Part I and elsewhere in this annual report. You should read the following discussion with the “Item 6. Selected Financial Data” and our
consolidated financial statements and the related notes included in this Form 10-K.

OVERVIEW

Background

Southwestern Energy Company is an independent energy company engaged in natural gas and oil exploration, development and production, or E&P. We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services. We operate principally in two segments:
E&P and Midstream Services.

Our primary business is the exploration for and production of natural gas and oil, with our current operations being principally focused within the United States on development of an unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, which we refer to as the Fayettev ille Shale play. We are also actively engaged in exploration and production activities in Pennsylvania, where we are targe ting the unconventional gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkom a Basin. We have recently commenced exploration operations in Arkansas and Louisiana testing an unconventional oil play targeting the Lower Smackover Brown Dense, or LSBD, formation, as well as in Colorado a nd Montana. In 2010, we commenced an exploration program in New Brunswick, Canada, which represents our first operations outside of the United States.

We are focused on providing long-term growth in the net asse t value of our business. We derive the vast majority of our operating income and cash flow from the natural gas production of our E&P business and expect this to continue in the future. We expect that growth in our operating income and re venues will depend primarily on natural gas prices and our ability to increase our natural gas production. We expect ou r natural gas production volumes will continue to increase due to our ongoing development of the Fayetteville Shale play in Arkansas and the Marcellus Shale play in Pennsylvania. The price we expect to receive for our natural gas is a critical fact or in the capital investments we make in order to develop our properties and increase our production. In recent years, there has been a signif icant decline in natural gas prices as evidenced by New York Mercantile Exchange, or NYMEX, natu ral gas prices ranging from a high of $13.58 per MMBtu

in 2008 to a recent low of $1.91 per MMBtu in Ap ril 2012. Natural gas prices fluctu ate due to a variety of factors we cannot control or predict. Thes e factors, which include increas ed supplies of natural gas due to greater exploration and development activities, weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which in turn determines the sale prices for our production. In addition to the factors identified above, the prices we realize for our produc tion are affected by our hedging activities as well as locational differences in market prices.

Recent Financial and Operating Results

Due to a significant non-cash ceiling test impairment of our United States natural gas properties in 2012, we reported a net loss attributable to Southwestern Energy of $707.1 million, or $2.03 per diluted share, down from net income attributable to Southwestern Energy of $637.8 million, or $1.82 per diluted share in 2011. We reported net income attributable to Southwestern Energy of $604.1 million, or $1.7 3 per diluted share, in 2010. In 2012, we incurred a $1,939.7 million, or $1,192.4 million net of taxes, non-cash ceiling test impairment of our United States natural gas and oil properties that resulted from a significant decline in natu ral gas prices during 2012. Our cash flow from operating activities decreased 5% to $1,653.9 million in 2012 due to a de crease in net income adjusted for non-cash expenses which was partially offset by changes in wo rking capital accounts, and increased 6% to $1,739.8 million in 2011 due to an increase in net income adjusted for n on-cash expenses which was partially offset by changes in working capital.

In 2012, our natural gas and oil production increased 13% to 565.0 Bcfe, up from 500.0 Bcfe in 2011. The 65.0 Bcfe increase in our 2012 production resulted from a 48.7 Bcf increas e in net production from our Fayetteville Shale play, a 30.3 Bcf increase in net production from our Marcellus Shale properties and a 0.3 Bcfe increase in net production in our New Ventures properties, which more than offset a combined 14.3 Bcfe decrease in net production from our East Texas and Arkoma Basin properties. In 2011, our natural gas and oil production increased to 500.0 Bcfe, up from 404.7 Bcfe in 2010. We are targeting 2013 natural gas and oil production of 628.0 to 640.0 Bcfe, an increase of approximately 12% over our49 2012 production, using midpoints. Our year-end reserves decreased 32% in 2012 to 4,018 Bcfe, down from 5,893 Bcfe at the end of 2011 and 4,937 Bcfe at the end of 2010, primarily due to the low natural gas price environment.

Our E&P segment reported an operating loss of $1,411.2 million in 2012, down from operating income of $825.1 million in 2011. The operating loss in 2012 included a $1,939.7 million non-cash ceiling test impairment of our United States natural gas and oil properties. Excluding the non-cas h ceiling test impairment, operating income in 2012 decreased $296.6 million over 2011 as the revenue impact of our 13% increase in production was more than offset by the 18% decline in our average realized natural gas prices and a $ 144.3 million increase in operating costs and expenses that resulted from our significant production growth. Operating income of $825.1 million in 2011 decreased $4.3 million over 2010 as the revenue impact of our 24% increase in production was more than offset by the 10% decline in our average realized natural gas prices and a $214.4 million increase in operating costs that resulted from our significant production growth.

Operating income for our Midstream Services segment was $294.3 million in 2012, up from $248.0 million in 2011 and $191.6 million in 2010. Operating income for our Midstream Services segment increased in 2012 due to an increase of $65.8 million in gathering revenues, which was partially offset by a decrease of $2.5 million in the margin generated from our natural gas marketing activities and $16.9 million increase in operating costs and expenses, exclusive of natural gas purchase costs, that resulted from our continued significant growth in volumes gathered. Volumes gathered grew to 845.5 Bcf in 2012 compared to 745.7 Bcf in 2011. Operating income for our Midstream Services segment increased in 2011 due to an increase of $92.2 million in gathering revenues and an increase of $5.8 million in the margin generated from our natural gas marketing activities, which were partially offset by a $41.6 million increase in operating costs and expenses, exclusive of natural gas purchase costs, that resulted from our significant growth in volumes gathered. Volumes gathered grew to 745.7 Bcf in 2011 compared to 588.3 Bcf in 2010.

We had total capital investments of $2,080.5 million in 2012, compared to $2,207.2 million in 2011 and $2,120.1 million in 2010. Of our total capital investments, $1,860.7 million was invested in our E&P segment in 2012 compared to $1,977.5 million and $1,775.5 million invested in our E&P segment in 2011 and 2010, respectively.

Outlook

We believe the outlook for our business is favorable despite the continued uncertainty of natural gas prices in the United States and the legislative and regulatory challenges facing our industry. Our resource base, financial strength and disciplined investment of capital provide us with an opportu nity to exploit and develop our position in the Fayetteville Shale play and Marcellus Shale play, maximize efficiency th rough economies of scale in our key operating areas, enhance our overall returns through expansion of our Midstream Services operations and grow through new exploration and development activities. Our capital investment plan for 2013 is flexible and is based on our expectation that natural gas prices will remain at current price levels. Should prices fl uctuate materially from their curre nt levels we will adjust our capital investment plans accordingly.50 RESULTS OF OPERATIONS

The following discussion of our results of operations for ou r segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discus s their results prior to any intersegment eliminations. Interest expense, interest income, income tax expense and stock-based compensation are
discussed on a consolidated basis.

Exploration and Production

Year Ended December 31,

2012 2011 2010

Revenues (in thousands) $ 1,948,222 $ 2,100,488 $ 1,890,444 Impairment of natural gas an d oil properties (in thousands) $ 1,939,734 $ – $ – Operating costs and expenses (in thousands) $ 1,419,699 $ 1,275,350 $ 1,060,982 Operating income (loss) (in thousands) $ (1,411,211) $ 825,138 $ 829,462

N atural gas production (Bcf) 564.5 499.4 403.6 Oil production (MBbls) 83 97 171

Total production (Bcfe) 565.0 500.0 404.7

Average gas price per Mcf, including hedges $ 3.44 $ 4.19 $ 4.64 Average gas price per Mcf, excluding hedges $ 2.34 $ 3.56 $ 3.93 Average oil price per Bbl $ 101.54 $ 94.08 $ 76.84

Average unit costs per Mcfe:

Lease operating expenses $ 0.80 $ 0.84 $ 0.83 General & administrative expenses $ 0.26 $ 0.27 $ 0.30
Taxes, other than income taxes $ 0.10 $ 0.11 $ 0.11 Full cost pool amortization $ 1.31 $ 1.30 $ 1.34

Revenues

Revenues for our E&P segment were down $152.3 million, or 7%, in 2012 compared to 2011. Higher natural gas production volumes in 2012 increased revenues by $272.5 million while lower realized prices for our natural gas production decreased revenue by $423.8 million compared to 2011. E&P revenues were up $210.0 million, or 11%, in 2011 compared to 2010. Higher natural gas production volu mes in 2011 increased revenues by $445.0 million while lower realized prices for our natural gas production decreased reve nue by $227.9 million. We expect our natural gas production volumes to continue to increase due to our development of the Fayetteville Shale properties in Arkansas and our Marcellus Shale properties in Pennsylvania. Natural gas and oil prices ar e difficult to predict and subject to wide price fluctuations. As of February 15, 2013, we had hedged 185.6 Bcf of our remaining 2013 natural gas production and 54.8 Bcf of our 2014 natural gas production to help limit our exposure to price fluc tuations. For more information about our derivatives and risk management activities, we refer you to Note 5 to the consolidated financial statements included in this Form 10-K and to “Commodity Prices” below for additional information.

Production

In 2012, our natural gas and oil production increased 13% to 565.0 Bcfe, up from 500.0 Bcfe in 2011. The 65.0 Bcfe increase in our 2012 production resulted from a 48.7 Bcf increas e in net production from our Fayetteville Shale play, a 30.3 Bcf increase in net production from our Marcellus Shale properties and a 0.3 increase in net production in our New Ventures properties, which more than offset a combined 14.3 Bcfe decrease in net production from our East Texas and Arkoma Basin properties. Natural gas and oil production was up approximately 24% to 500.0 Bcfe in 2011, as compared to 2010, due to a 95.3 Bcf increase in net production from our Fayetteville Shale play and a 22.4 Bcf increase in net production from our Marcellus Shale properties, which more than offset a combined 13.7 Bcfe decrease in net production from our East Texas and Arkoma Basin properties. Our net production from the Fayetteville Shale play was 485.5 Bcf in 2012, up from 436.8 Bcf in 2011 and 350.2 Bcf in 2010.

We are targeting 2013 natural gas and oil production of 628 to 640 Bcfe, an increase of approximately 12% over our 2012 production, using midpoints. Approximately 475 to 480 Bcf of our 2013 targeted natural gas production is projected to come from our activities in the Fayetteville Shale play. Alth ough we expect production volumes in 2013 to increase, we51 cannot guarantee our success in discovering, developing an d producing reserves. Our ability to discover, develop and produce reserves is dependent upon a number of factors, many of which are beyond our control, including the availability of capital, the timing and extent of changes in natural ga s and oil prices and competition. There are also many risks inherent in the discovery, development and production of natural gas and oil. We refer you to “Risk Factors” in Item 1A of Part I of this Form 10-K for a discussion of these risks and the impact they could have on our financial condition and results of operations.

Commodity Prices

The average price realized for our natura l gas production, including the effects of hedges, decreased 18% to $3.44 per Mcf in 2012 and decreased 10% to $4.19 per Mcf in 2011. The d ecrease in the average price r ealized in 2012 compared to 2011 primarily reflects the decrease in average market prices, which was partially offset by the positive effect of our price hedging activities in 2012 (see additional discussion below). The decrease in the average price realized in 2011 compared to 2010 primarily reflects the decrease in average market prices and to a lesser exte nt the decreased effect of our natural gas price hedging activities, which had a greater positive imp act on our average realized natural gas price in 2010. We periodically enter into various hedging and other financial arra ngements with respect to a portion of our projected natural gas and oil production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differen tials. We refer you to Item 7A of this Form 10-K, Note 5 to the consolidated financial statements, and our hedge risk factor for additional discussion about our derivatives and risk management activities.

Our hedging activities increased the average natural gas sales pr ice we realized by $1.10 per Mcf in 2012, compared to an increase of $0.63 per Mcf in 2011 an d an increase of $0.71 per Mcf in 2010. Disregarding the impact of hedges, the average sales price we received for our natural gas production in 2012 was $1.22 per Mcf lower than 2011 and $0.45 lower than the average monthly NYMEX settlement price for 2012.

As of December 31, 2012, we had basi s hedges on approximately 232.7 Bcf of our 2013 expected natural gas production through financial hedging activities and physical sales arrangements at a basis differential to NYMEX natural gas prices of approximately $0.05 per Mcf.

In addition to the basis hedges discussed above, as of December 31, 2012, we had NYMEX fixed price hedges in place on notional volumes of 185.6 Bcf of our remaining 2013 natural gas production at an average price of $5.06 per MMBtu. As of December 31, 2012, we had NYMEX fixed price hedg es in place on notional volumes of 18.3 Bcf of our 2014 natural gas production.

Our E&P segment receives a sales price for our natural gas at a discount to average monthly NYMEX settlement prices due to locational basis differentials, while transporta tion charges and fuel charges al so reduce the price received. Assuming a NYMEX commodity price of $3.50 per Mcf for 2013, and disregarding the impact of hedges, we expect our total natural gas sales discount to NYMEX to be $0.50 to $0.55 per Mcf for 2013.

We realized an average sales price of $101.54 per barrel for our oil production for the year ended December 31, 2012, up approximately 8% from the prior year. The 2011 average realized price of $94.08 per barrel was up 22% from 2010. We did not hedge any of our 2012, 2011 or 2010 oil production.

Operating Income

Our E&P segment reported an operating loss of $1,411.2 million in 2012, down from operating income of $825.1 million in 2011. The operating loss in 2012 included a $1,939.7 million non-cash ceiling test impairment of our United States natural gas and oil properties. Excluding the $1,939.7 million non-cash ceiling test impairment, operating income in 2012 decreased $296.6 million over 2011 as the revenue impact of our 13% increase in production was more than offset by the 18% decline in our average realized natural gas prices and a $144.3 milli on increase in operating costs and expenses that resulted from our significant production growth. Opera ting income of $825.1 million in 2011 decreased $4.3 million over 2010 as the revenue impact of our 24% increase in productio n was more than offset by th e 10% decline in our average realized natural gas prices and a $214.4 million increase in operating costs that resulted from our significant production growth.52 Operating Costs and Expenses

Lease operating expenses per Mcfe for the E&P segment were $0.80 in 2012, compared to $0.84 in 2011 and $0.83 in 2010. Lease operating expenses per unit of production decreased in 2012 primarily due to lower compression and salt water disposal costs associated with our Fayetteville Shal e operations. Lease operating expenses per unit of production increased in 2011 compared to 2010 prim arily due to increased gathering, compre ssion and water disposal costs associated with our Fayetteville Shale operations. We expect our per un it operating cost for this segment to range between $0.84 and $0.89 per Mcfe in 2013.

General and administrative expenses for the E&P segment were $0.26 per Mcfe in 2012, down from $0.27 per Mcfe in 2011 and $0.30 per Mcfe in 2010. The decreases in general and administrative costs per Mcfe in 2012 and 2011 were due to decreased personnel costs per unit of production. In total, general and administrative expenses for the E&P segment were $145.1 million in 2012, $134.8 million in 2011 and $120.3 million in 2010. The increases in general and administrative expenses since 2011 was primarily a result of increased personnel and informa tion system costs associated with the expansion of our E&P operations . These increases accounted for $8.9 milli on, or 86%, of th e 2012 increase and $11.1 million, or 76%, of the 2011 increase. We added 131 new E&P employees during 2012 compared to 106 employees
added in 2011.

We expect our per unit cost for general and administrative expenses in 2013 to range between $0.26 and $0.30 per Mcfe. The expected increase in our per unit general and administrative costs in 2013 is due to general increases in personnel costs associated with ongoing development of our Fayetteville Shale and Marcellus Shale plays. Future changes in our general and administrative expenses for this segment are primarily dependent upon compensation and other personnel costs and level and intensity of our operating activities. For eligible employees, a portion of incentive compensation is based on the achievement of certain operating and performance results, including production, proved reserve additions, present value added for each dollar of cap ital invested, and lease operating expenses and general and administrative expenses per unit of production, while anot her portion is discretionary based upon an employee’s performance.

Taxes other than income taxes per Mcfe were $0.10 in 2012 and $0.11 in each of 2011 and 2010. In 2012, we incurred a new Pennsylvania well impact fee charged to all of our wells spud in the Marcellus Shale play. Taxes other than income taxes per Mcfe vary from period to period due to ch anges in severance and ad valorem taxes that result from the mix of our production volumes and fluctuations in commodity prices.

Our full cost pool amortization rate averaged $1.31 per Mcfe for 2012, $1.30 per Mcfe for 2011 and $1.34 per Mcfe

for 2010. The increase in the aver age amortization rate for 2012 compared to 2011 was primarily the result of a decrease in proved reserves associated with lower prices in 2012 and the sale of certain East Texas properties in 2012 and 2011. The decline in the average amortization rate for 2011 compared to 2010 was primarily the result of lower acquisition and development costs and sale of certain East Texas properties in 2011 and 2010. The amortization rate is impacted by the timing and amount of reserve additions and the costs associat ed with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from full cost ceiling tests, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variab ility of each of the factors discussed above, as well as other factors, including but not limited to the unc ertainty of the amount of future reserves attributed to our Fayetteville Shale and Marcellus Shale plays.

Unevaluated costs excluded from amortizat ion were $1,023.9 million at the end of 2012 compared to $942.9 million at the end of 2011 and $712.1 million at the end of 2010. Unevaluated costs excluded from amortization at the end of 2012 included $40.4 million related to our pr operties in Canada. The in crease in unevaluated cost s since December 31, 2011 primarily resulted from a $90.7 million increase in our drilling ac tivity in our wells in progress, offset slightly by a $5.3 million decrease in undeveloped leasehold acreage and seismic co sts. See Note 4 to the consol idated financial statements for additional information regarding our unevaluated costs excluded from amortization.

The timing and amount of production and reserve additions c ould have a material impact on our per unit costs; if production or reserves additions are lower than projected, our per unit costs could increase.53 Midstream Services

Year Ended December 31,

2012 2011 2010

($ in millions)

Revenues – marketing $ 1,889.5 $ 2,451.3 $ 2,137.8 Revenues – gathering $ 474.0 $ 408.2 $ 316.0 Gas purchases – marketing $ 1,858.8 $ 2,418.1 $ 2,110.4 Operating costs and expenses $ 210.4 $ 193.4 $ 151.8 Operating income $ 294.3 $ 248.0 $ 191.6 Gas volumes marketed (Bcf) 676.2 611.4 495.8 Gas volumes gathered (Bcf) 845.5 745.7 588.3

Revenues

Revenues from our marketing activities were down 23% to $1 ,889.5 million for 2012 compared to 2011. The decrease in marketing revenues resulted from a d ecrease in the prices received for volumes marketed, which was partially offset by
an increase in volumes marketed. Revenues from our mark eting activities were up 15% to $2,451.3 million for 2011 compared to 2010. The increa se in marketing revenues for 2011 resulted from increases in the volumes marketed which partially offset a decrease in the prices received for volumes marketed. The aver age price received for volumes marketed decreased 30% in 2012 compared to 2011, and decreased 7% in 2011 compared to 2010. Volumes marketed increased 11% in 2012 compared to 2011, and increased 23% in 2011 compared to 2010. Of the total volumes marketed, production from our E&P operated wells accounted for 95% in 2012, 94% in 2011 and 95% in 2010. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in natural gas purchase

expenses.

Revenues from our gathering activities were up 16% to $474.0 million for 2012 compared to 2011, and were up 29% to $408.2 million for 2011 compared to 2010. The increases in gathering revenues primarily resulted from a 13% increase in natural gas volumes gathered in 2012 compared to 2011 and a 27% increase in natural ga s volumes gathered in 2011 compared to 2010. The majority of the increases in gathering revenues for 2012 and 2011 resulted from increases in the volumes gathered from our operated production from the Fayetteville Shale play.

Operating Income

Operating income from our Midstream Serv ices segment increased 19 % to $294.3 million in 2012 and increased 29% to $248.0 million in 2011. The increases in operating income reflect the substantial increases in natural gas volumes gathered and marketed which resulted primarily from our incr eased E&P production volumes. The increase in operating income for 2012 compared to 2011 was due to an increase of $65.8 million in gathering revenues, which was partially offset by a decrease of $2.6 million in the margin generated from our natural gas marketing activities and a $17.0 million increase in operating costs and expenses, exclusive of purchased natural gas costs, associated with the increase in natural gas volumes gathered. The increase in oper ating income for 2011 compared to 2010 was due to a $92.2 million increase in gathering revenues and an increase of $5.8 million in the marg in generated from our natural gas marketing activities, which were partially offset by a $41.6 million increase in operating costs and expenses, exclusive of purchased natural gas costs

associated with the increase in natural gas volumes gathered.

The margin generated from natural gas marketing activities was $30.7 million for 2012, compared to $33.2 million for 2011 and $27.4 million for 2010. Margins are driven primarily by volumes of natural gas marketed and may fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities. The increases in margins generated are primarily the result of a 11 % increase in volumes market ed in 2012 and a 23% incr ease in volumes marketed in 2011, as compared to prior years, resulting from marke ting our increased E&P production volumes. We enter into hedging activities from time to time with respect to our natural gas marketing activities to provide margin protection. For more information about our derivatives and risk management activities, we refer you to “Quantitative and Qualitative
Disclosures about Market Risk” and Note 5 to the consolid ated financial statements for additional information.

Interest Expense

Interest expense, net of capitalization, was $35.7 millio n in 2012, an increase of $11.6 million compared to 2011, primarily due to our increased borrowing le vel, partially offset by an increase in capitalized interest. Interest capitalized increased to $62.1 million in 2012 from $45.7 million in 2011, primarily due to an increase in our unevaluated property54 balance during 2012.

Interest expense, net of capitalization, was $24.1 million in 2011, a decrease of $2.1 million compared to 2010, primarily due to a increase in capitalized interest. Interest cap italized increased to $45.7 million in 2011 from $32.9 million in 2010, primarily due to an increase in our weighted average interest rate and average borrowed balance under our credit facility during 2011, which had a weighted average interest ra te of 2.06% for 2011 and an increase in our unevaluated properties.

Income Taxes

Our effective tax rate was 38.5% in 2012 and 39.3% in 2011 and 2010. The effective tax rate is lower in 2012 primarily due to the $1,939.7 million non-cash impairment of our natural gas and oil properties and state income taxes. In general, differences between our effective tax rate and the st atutory tax rate of 35% primarily result from the effect of certain state income taxes and permanent items attributable to book-tax differences.

Stock-Based Compensation Expense

We recognized expense of $11.8 million and capitalized $10.5 million for stock-based compensation in 2012, compared to $10.6 million expensed and $8.5 million capitalized in 2011 and $9.8 million expensed and $6.8 million capitalized in 2009. We refer you to Note 1 to the consolidated financial statements for additional discussion of our equity based compensation plans.55 LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on internally generated funds, our re volving credit facility, sales of non-core assets and funds accessed through debt and equity markets as our primary sources of liquidity.

During 2013, assuming natural gas prices remain at current levels, we expect to draw on a portion of the funds available under our revolving credit facility to fund the por tion of our planned capital investments (discussed below under “Capital Investments”), that are expected to exceed the net cash generated by our opera tions. We refer you to Note 7 to the consolidated financial statements included in this Form 10-K and the section below under “Financing Requirements” for additional discussion of our revolving credit facility.

As of December 31, 2012, our capital structure consisted of 35% debt and 65% equity. We believe that our operating cash flow and available funds under our revolving credit fac ility will be adequate to meet our capital and operating requirements for 2013. The credit status of the financial in stitutions participating in our revolving credit facility could adversely impact our ability to borrow funds under the revolv ing credit facility. While we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet its obligation.

Net cash provided by operating activities decreased 5% to $1.7 billion in 2012, due to a decrease in net income adjusted for non-cash expenses which was partially offset by changes in working capital acco unts. Net cash provided by operating activities increased 6% to $1.7 billion in 2011 over 2010 due to an increase in net income adjusted for non-cash expenses which was partially offset by changes in working capital accounts. Fo r 2012, requirements for our capital investments were funded from our cash generated by operati ng activities, borrowings under ou r revolving credit facility, $1

billion issuance of senior notes and the proceeds from the sale of certain East Te xas oil and natural gas properties. Net cash from operating activities provided 78% of our cash requir ements for capital investments in 2012, 80% in 2011 and
79% in 2010.

Our cash flow from operating activities is highly dependent upon the market prices that we receive for our natural gas and oil production. Natural gas and oil prices are subject to wide fluctuations and are driven by market supply and demand factors which are impacted by the overa ll state of the economy. The sales price we receive for our production is also influenced by our commodity hedging activities, as more fully discussed in Note 5 to the consolidated financial statements included in this Form 10-K and Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.” Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to complete the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults
associated with our transactions. Howeve r, any future failures by one or more counterparties could negatively impact our cash flow from operating activities.

Additionally, our short-term cash flows are dependent on the timely collection of receivables from our customers and partners. We actively manage this risk through credit management activities and, through the date of this filing, have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers and partners could adversely impact our cash flows.

Due to the above factors, we are unabl e to forecast with certainty our future level of cash flow from operations. Accordingly, we will adjust our discretionary uses of cash dependent upon available cash flow.

Capital Investments

Our capital investments were $2.1 billion in 2012, down from $2.2 billion in 2011. Capital investments include a decrease of $36.9 million in 2012, an increase of $4.3 milli on in 2011 and an increase of $14.4 million in 2010 related to the change in accrued expenditures between years. Our E&P segm ent investments in 2012 were $1.9 billion, compared to $2.0 billion in 2011 and $1.8 billion in 2010.

2012 2011 2010

(in thousands) Exploration and production $ 1,860,681 $ 1,977,493 $ 1,775,518

Midstream services 164,978 160,776 271,316
Other 54,860 68,905 73,231 $ 2,080,519 $ 2,207,174 $ 2,120,06556 Our capital investments for 2013 are planned to be $2.0 billion, consisting of approximately $1.8 billion for E&P, $160 million for Midstream Services and $40 million for corpor ate and other purposes. Of the approximate $1.8 billion, we expect to allocate approximately $830 million to our Fayette ville Shale play. Our planned level of capital investments in 2013 is expected to allow us to continue our progress in the Fayetteville Shale and Marcellus Shale programs and explore and develop other existing natural gas and oil properties and generate new drilling prospects. As discussed above, our 2013 capital investment program is expected to be funded through cash flow from operations and borrowings under our revolving credit facility. The planned capital program for 2013 is flexible and can be modified. We will reevaluate our proposed investments as needed to take into account prevailing market conditions and, if natural gas prices change significantly in 2013, we could change our planned investments.

Financing Requirements

Our total debt outstanding was $1,669.5 million as of Decemb er 31, 2012, compared to $1 ,343.3 million at December 31, 2011.

In February 2011, we amended and rest ated our unsecured revolving credit f acility, increasing the borrowing capacity to $1.5 billion and extending the maturity date to February 2016. The amount available under the revolving credit facility may be increased to $2.0 billion at any time upon the our agreement with its existing or additional lenders. We had no borrowings under our revolving credit facility as of December 31, 2012 and had $671.5 million outstanding under our revolving credit facility at December 31, 2011.

The interest rate on our revolving credit facility is calcula ted based upon our public debt rating and is currently 200 basis points over LIBOR. At February 15, 2013, our publicly traded notes are rated BBB- by Standard and Poor’s and we have a Corporate Family Rating of Baa3 by Moody’s. Any downgrades in our public debt ratings could increase our cost of funds under our revolving credit facility.

Our revolving credit facility contains covenants which impos e certain restrictions on us. Under our revolving credit facility, we must keep our total debt at or below 60% of our total capital, and must maintain a ratio of EBITDA to interest expense of 3.5 or above. Our revolving credit facility’s fina ncial covenants with respect to capitalization percentages exclude the noncontrolling interest in equity, the effects of non-cash entries that result from any full cost ceiling impairments, hedging activities and our pension and other postr etirement liabilities. Therefore, under our revolving credit facility, our capital structure as of Decem ber 31, 2012 would have been 29% debt and 71% equity. We were in compliance
with all of the covenants of our revo lving credit facility as of December 31, 2012. Although we do not anticipate any violations of our financial covenants, our ability to comply with those covenants is de pendent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and oil. If we are unable to borrow under our revolving credit f acility, we would have to decrease our capital investment plans.

In March 2012, we issued $1 billion of 4.10% Senior Notes due 2022. A portion of the net proceeds of the offering were used to repay the amounts outstanding under our revolvi ng credit facility and the remaining proceeds were used for general corporate purposes.

As of December 31, 2012, our capital stru cture consisted of 35% debt and 65% eq uity compared to 25% debt and 75% equity at December 31, 2011. Our debt percentage of total capital as of December 31, 2012 increas ed in 2012, primarily due to a $1939.7 million non-cash ceiling test impairment of our United States natural gas and oil properties. Equity as of December 31, 2012 included an accumulated other comprehensiv e gain of $172.2 million related to our hedging activities and an accumulated other comprehensive loss for $22.3 million related to our pension and other postretirement liabilities. The amount recorded in equity for our hedging activities is base d on current market values for our hedges as of December 31, 2012 and does not necessarily reflect the value that we will receive or pay when the hedges are ultimately settled, nor does it take into account revenues to be received associated with the physical delivery of sales volumes hedged.

Our hedges allow us to ensure a certain level of cash flow to fund our operations. At February 15, 2013, we had NYMEX commodity price hedges in place on 185.6 Bcf, or approximately 29% of our targeted 2013 natural gas production and 54.8 Bcf of our expected 2014 natural gas production. The amount of long-term debt we incur will be dependent upon commodity prices and our capital investment plans.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arra ngements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2012, the Company’s material off- balance sheet arrangements and transactions include operating lease arrangements. There are no other transactions, arrangements or other relationships with unconsolidated57 entities or other persons that are reasonably likely to materially affect our liquidity or availability of or capital resources

. For more information regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent

Liabilities and Commitments” below.

Contractual Obligations and Cont ingent Liabilities and Commitments

We have various contractual obligations in the normal cour se of our operations and financing activities. Significant contractual obligations as of Decem ber 31, 2012, were as follows:

Contractual Obligations :

Payments Due by Period

Less than More than

Total 1 Year 1 to 3 Years 3 to 5 Years 5 Years

(in thousands)

Demand charges (1) $ 2,815,223 $ 252,439 $ 549,049 $ 604,035 $ 1,409,700

Debt 1,670,600 1,200 2,400 42,400 1,624,600
Interest on senior notes 663,260 91,072 181,886 181,543 208,759 Operating leases (2) 262,714 75,476 107,313 48,871 31,054 Operating agreements (3) 38,687 23,401 15,233 53 - Compression services (4) 70,724 30,508 27,915 12,301 - Purchase obligations 31,550 31,550 - - - Other obligations (5) 381,417 69,109 27,343 23,839 261,126 $ 5,934,175 $ 574,755 $ 911,139 $ 913,042 $ 3,535,239

(1) As of December 31, 2012, our Midstream Services segment had commitments for dema nd transportation charges on various pipeli nes, including approximately $1.0 billion related to the FEP pipeline and $0.6 billion related to the Boardwalk Pipeline.

(2) Operating leases include costs for compressors, aircraft, vehicles, office space and equipment under non-cancelable operati ng leases expiring through 2020. Additionally, this includes $38.8 million for leases of 14 drilling rigs and related e quipment through 2014 and $37.5 mil lion for pressure pumping equipment for its E&P operations through 2017.

(3) As of December 31, 2012, our E&P segment had commitments for approximately $213.9 million to companies for fracture stimula tion services,
which are cancellable under certain circumstances.

(4) As of December 31, 2012, our Midstream Services segment had commitments of approximately $67.6 million and our E&P segment had commitments of approximately $3.1 million for compression services associated primarily with our Fayetteville Shale play operat ions.

(5) In conjunction with our exploration program in New Brunswick , Canada, we provided promissory notes payable on demand to the Minister of Finance of the Province of New Brunswick with an aggregate prin cipal amount of CAD $44.5 million. See Note 8 to the consolidate d financial statements for additional information regard ing our commitments related to our explora tion program in Canada. Our other signifi cant contractual obligations include approximately $288.0 m illion for asset retirement obligations primar ily relating to oil and natural gas pro perties, approximately $13.8 million for funding of benef it plans, approximately $14.0 million for various information technology support and data sub scription agreements, approximately $6.8 million for insurance pr emium financing and approxi mately $2.1 million related to seismic services.

We refer you to Note 7 to the consolidated financial statements for a discussion of the terms of our debt.

Commitments and Contingent Liabilities

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. We currently expect to contribute approximately $13.5 million to our pension plans and $0.3 million to our postretirement benefit plan in 2013. For 2012, we contributed $11.1 million to our pension plans and contributed $0.1 million to our postretirement benefit plan. As of December 31, 2012 we recognized a liability of $3 3.5 million as a result of the underfunded status of our pension and other postretirement benefit plans compared to a liability of $20.5 million at December 31, 2011. For further information regarding our pension and other postretirement benefit plans, we refer you to Note 11 to the consolidated financial statements and “Critical Accounting Policies” below for additional information.58 Working Capital

We maintain access to funds that may be needed to meet capital requirements through our revolving credit facility described in “Financing Requirements” above. We had positive working capital of $41.1 million as of December 31, 2012 and positive working cap ital of $93.4 million at December 31, 2011. Curr ent assets decreased $16 9.4 million during 2012 primarily due to a $231.8 million decrease in our current hedging asset and $18.1 million decrease in inventory, which was partially offset by a $38.0 million increase in cash and cash equivalents. Current liabilities decreased $117.1 million primarily due to a $88.0 million decrease in our current defe rred income taxes related to our hedging activities and $77.4 million decrease in accounts payable, offset slightly by a $22.7 million increase in taxes payable.

Natural Gas in Underground Storage

We currently have one facility owned by our E&P segment th at contains natural gas in underground storage. Natural gas in storage that is expected to be cycled within the next 12 months is recorded in current assets. This current portion of natural gas in storage is classified as inventory and is carried at the lower of cost or market . As of December 31, 2012 and 2011, the current portion of natural gas in storage was $5.6 million and $7.8 million, respectively. The non-current portion of natural gas in storage is classified in property and equipm ent and carried at cost. The ca rrying value of the non-current natural gas is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be
recoverable.

The natural gas in inventory for the E&P segment is used primarily to supplement production in meeting the segment’s contractual commitments, especially during periods of colder weather. In determining the lower of cost or market for storage gas, we utilize the natural gas futures market in assessing the price we expect to be able to realize for our natural gas in inventory. A significant decline in the future market price of natural gas could require a write-down of our natural gas in underground storage carrying cost.

CRITICAL ACCOUNTING PO LICIES AND ESTIMATES

The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires mana gement to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses a nd related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are
believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation
of our consolidated financial statements.

Natural Gas and Oil Properties

We utilize the full cost method of accounting for costs rela ted to the exploration, de velopment and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such p ooled costs, net of applicable deferred taxes, to the aggregate of the present valu e of future net revenues attributable to pr oved natural gas and oil reserves discounted at 10% (standardized measure) plus the lower of cost or market value of unproved properties. An y costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future pe riods, even though higher natural gas and oil prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, in cluding the impact of deriva tives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.

Using the average quoted price from th e first day of each month from the prev ious 12 months for Henry Hub natural gas of $2.76 per MMBtu and $91.21 per barrel for West Texas Intermediate oil, adjusted for market differentials, our net

book value of its United States natura l gas and oil properties exceeded the ce iling amount and resulted in a ceiling test impairment as of December 31, 2012. Our net book value of its United States na tural gas and oil properties exceeded the ceiling by approximately $510.4 million (net of tax) as of Decem ber 31, 2012 and resulted in a non-cash ceiling test impairment. Cash flow hedges of natu ral gas production in place increased this ceiling amount by approximately $257.6 million as of December 31, 2012. Our net book value of its United States na tural gas and oil properties exceeded the ceiling by approximately $185.7 million (net of tax) at September 30, 2012 and resulted in a non-cash ceiling test impairment. Cash flow hedges of natu ral gas production in place increased the ceiling by $330.6 million at September 30,59 2012. In the second quarter of 2012, our net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $496.4 m illion (net of tax) at June 30, 2012 and re sulted in a non-cash ceiling test impairment. Cash flow hedges of natural gas producti on in place increased the ceiling by $354.8 million at June 30, 2012. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.

All of our costs directly associated with the acquisition and evaluation of pr operties in Canada as of December 31, 2012 were unproved and did not exceed the ceiling amount. If ou r exploration program in Canada is unsuccessful on all or a portion of these properties, a ceiling te st impairment may result in the future.

Natural gas and oil reserves cannot be measured exactly. Our estimate of natural gas and oil reserves requires extensive judgments of reservoir engineering data and projections of cost that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates u nder the supervision of our management. Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team to which the property is assigned. The reservoir engineering and financial data included in these estimates are reviewed by senior engineers who are not part of the asset management teams and our Manager – Capital Budgeting & Reserves, who was the technical person primarily responsible for the preparation of our reserv e estimates, and has over ten years of experience in petroleum engineering, including the estimation of oil and natural gas reserves. He reports to our Senior Vice President – Corporate Development, who has more than 31 years of experience in reservoir engineering, including the estimation of oil and natural gas reserves in multiple basins, both in the United States and internationally. On our behalf, the Senior Vice President – Corporate Development engages NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in
more detail below. The financial data included in the reserv e estimates are also separately reviewed by our accounting staff. Following these reviews and the au dit, the reserve estimates are submitted by our Senior Vice President – Corporate Development to our Chief Executive Officer for his review and approval prior to the presentation to our Board of Directors. NSAI reports the results of its reserve audit to the Board of Directors with whom final authority over the estimates of our proved reserves rests.

Proved developed reserves generally have a higher degree of accuracy in this estimation process, when compared to proved undeveloped and proved non-producing reserves, as produc tion history and pressure data over time is available for the majority of our proved developed pr operties. Proved developed reserves accounted for 80% of our total reserve base as of December 31, 2012. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature
of such reserve estimates. The uncerta inties inherent in the reserve estimate s are compounded by applying additional estimates of the rates and timing of production and the costs th at will be incurred in developing and producing the reserves. We cannot assure you that our internal c ontrols sufficiently address the numerous uncertainties and risks that are inherent in estimating quantities of natural gas and oil reserves and pr ojecting future rates of production and timing of development expenditures as many factors are beyond our control. We re fer you to “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A, “Risk Factors,” of Part I of this Form 10-K for a more detailed discussion of these uncertainties, risks and other factors.

In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently develop reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of major properties that account for approxi mately 93% of present worth of the company’s total proved reserves. NSAI’s audit process consists of sorting all fields by descending pres ent value order and selecting the fields from highest value to descending value until the selected fields account for more th an 80% of the present worth of our reserves. The properties in the bottom 20% of the total present worth are not reviewed in the audit. The fields included in approximately the top 93% present value as of December 31, 2012, accounted for approximately 95% of our total proved reserves and approximately 98% of our proved undeveloped reserves. In the conduct of its audit, NSAI did not independently verify the data we provided to them with respect to ownership interests, oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. NSAI has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data. On January 17, 2013, NSAI issued its audit opinion as to th e reasonableness of our reserve estimates for the year-ended December 31, 2012, stating that our estimated proved oil and natural gas reserv es are, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.60 A decline in natural gas and oil prices used to calculate the discounted future net revenues of our reserves affects both the present value of cash flows and the quantity of reserves repor ted. Our reserve base is nearly 100% natural gas, therefore changes in oil prices used do not have as significant an imp act as natural gas prices on cash flows and reported reserve quantities. Our standardized measure and reserve quantities as of December 31, 2012, were $2,050.7 million and 4,018.3 Bcfe, respectively. An assumed decrease of $1.00 per Mcf in th e average 2012 natural gas pri ce used to price our reserves would have resulted in an approximate $1,453.5 million declin e in our standardized measur e and an approximate decrease of 1,447 Bcfe of our reported reserves. The unit of producti on rate for amortization is adjusted quarterly based on changes in reserve estimates, capitalized cost s and future development costs.

Hedging

We use natural gas and oil swap agreements and options to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil. Our policies prohibit speculation with derivatives and limit agreements to counterparties with appropriate credit standings to minimize the risk of uncollectability. We actively monitor the credit status of our counterparties, performing both quantitative a nd qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults asso ciated with our transactions. From 2006 through 2008, we established a portfolio of hedges relating to approximately 60% to 80% of our annual production. In 2010, 2011, and 2012 we hedged 30%, 52% and 47% of our production. The primary market risks related to our derivative contracts are the volatility in market prices and basis differentials for natural gas and oil. However, the market price risk is generally offset by the gain or loss recognized upon the related natural gas or oil transaction that is hedged.

Our derivative instruments are recorded at fair value in our financial statements and generally qualify for hedge accounting. We have established the fair value of derivative instruments using data provid ed by our counterparties in conjunction with assumptions evaluated internally using estab lished index prices and other sources. These valuations are recognized as assets or liabilities in our balance sheet and, to the extent an open position is an effective cash flow hedge on equity production, the offset is recorded in other comprehensive income. Results of settled commodity hedging transactions are reflected in natural gas and oil sales. Any derivative not qualifying for hedge accounting treatment or any ineffective portion of a properl y designated hedge is recognized immediately in earnings. For the year ended December 31, 2012, we recorded an unrealized gain of $0.7 million related to basis differential swaps that did not qualify for hedge accounting in addition to a $1.7 million loss related to the change in call op tion positions and estimat ed ineffectiveness of our commodity cash flow hedges. Future market price volatility could create significant changes to the hedge positions
recorded in our financial statements. We refer you to “Quantitative and Qualitative Disclosures about Market Risk” in Item
7A of Part II of this Form 10-K for additional information regarding our hedging activities.

Pension and Other Postretirement Benefits

We record our prepaid or accrued benefit cost, as well as our periodic benefit cost, for our pension and other postretirement benefit plans using measurement assumptions that we consider reasonable at the time of calculation (see Note 11 to the consolidated financial statements for further discussion and disclosures regarding these benefit plans). Two of the assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be effectively settled, and the expected return on plan assets , which reflects the average rate of earnings expected on the funds invested. For the December 31, 2012 benefit obligation and the periodic benefit cost to be recorded in 2013, the discount rate assumed is 4.00%. For the 2013 periodic benefit cost, the expected return assumed is 7.50%. This compares to a discount rate of 5.00% and an expected return of 7.50% used in 2012.

Using the assumed rates discussed above, we recorded total benefit cost of $13.5 million in 2012 related to our pension and other postretirement benefit plans. Due to the significance of the discount rate and expected long-term rate of return, the following sensitivity analysis demonstrates the effect that a 50 basis point change in those assumptions would have had on our 2012 pension expense:

Increase (Decrease) of Annual Pension Expense

50 Basis Point

Increase 50 Basis Point

Decrease (in thousands) Discount rate $ (756) $ 829
Expected long-term rate of return $ (362) $ 362

As of December 31, 2012, we recognized a liability of $3 3.5 million, compared to $20.5 million at December 31,61 2011, related to our pension and other postretirement benefit plans. During 2012, we also made cash payments totaling $11.2 million to fund our pension and other postretirement benefit plans. In 2013, we expect to make cash payments totaling $13.8 million to fund our pension and other postretirement benefit plans and recognize pension expense of $12.8 million and a postretirement benefit expense of $2.9 million.

New Accounting Standards Implemented in this Report

In May 2011, the FASB issued guidance on fair value measurement and disclosure requirements outlined in Accounting Standards Update No. 2011-04, Fair Value Measurement (Topic 820) –Amendments to Achieve Common Fair
Value Measurement and Disclosure Re quirements in U.S. GAAP and IFRS (“Update 2011-04”). Update 2011-04 expands existing fair value disclosure requirements, particularly fo r Level 3 inputs, including: quantitative disclosure of the unobservable inputs and assumptions us ed in the measurement; description of the valuation processes in place and sensitivity of the fair value to changes in unobservable inpu ts and interrelationships between those inputs; the level of items (in the fair value hierarchy) that are not measured at fair value in the ba lance sheet but whose fair value must be disclosed; and the use of a nonfinancial asset if it differ s from the highest and best use assumed in the fair value measurement. The amendments in Update 2011-04 must be applied prospectively and are effective during interim and annual periods beginning after December 15, 2011. The implem entation of these changes did not have an impact on the Company’s consolidated results of operations, financial position or cash flows.

In July 2011, the FASB issued Accounting Standards Update No. 2011-05, Presentation of Comprehensive Income (“Update 2011-05”), which amends Topic 200, Comprehensive Income . Update 2011-05 eliminates the option to present components of other comprehensive income, or OCI, in the statement of changes in stockholders’ equity, and requires presentation of total comprehensive income and components of net income in a single statement of comprehensive income, or in two separate, consecutive statements. Update 2011-05 requires presentation of reclassification adjustments for items
transferred from OCI to net income on the face of the financ ial statements where the com ponents of net income and the components of OCI are presented. The amendments do not change current treatment of items in OCI, transfer of items from OCI, or reporting items in OCI net of the related tax im pact. Update 2011-05 is effectiv e for fiscal years and interim periods beginning after December 15, 2011. The Company early adopted all disclosure requirements of 2011-05 for the year-end December 31, 2011, except those items which were deferred by Accounting Standards Update No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comp rehensive Income in Accounting Standards Update No. 2011-

05. The implementation of these changes did not have an impact on the Company’s results of operations, financial position
or cash flows.

Accounting Standards Not Yet Implemented

In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“Update 2013-02”), which finalizes Proposed ASU No. 2012-240, and seeks to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. Update 2013-02 replaces the presentation requirements in ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income , and ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendmen ts to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 . Update 2013-02 requires an entity to report the effect of significan t reclassifications out of accumulated othe r comprehensive income on the respective line items in net income if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income. For public entities, Update 2013-02 is effective prospectively for reporting periods beginning after December 15, 2012, with early adoption permitted. The implementation of the disclosure requirement is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”), which finalizes Proposed ASU No. 2012-250 and clarifies the scope of transactions that are subject to disclosures concerning offse tting. Update 2013-01 addresses implementation issues regarding the scope of ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities , issued in December 2011. Update 2013-01 clar ifies that the scope of the disclosures under U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreem ents, and securities borrowing and securities lending transactions that are offs et either in accordance with FASB ASC Section 210-20-45, Balance Sheet—Offsetting—Other Presentation Matters , or FASB ASC Section 815-10-45, Derivatives and Hedging—Overall—
Other Presentation Matters , or are subject to a master netting arrangement or similar agreement. Update 2013-01 requires an entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to provide the required disclosures retrospectively for all comparative pe riods presented. The implementation of the disclosure62 requirement is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

See further discussion of our significant accounting policies in Note 1 to the consolidated financial statements.

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securitie s Act and Section 21E of the Exchange Act. 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 objectivesfor our future operations, are forward-looking statements. Although we believe the expectations expressed in such forwardlooking statements are based on reasonab le assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

Forward-looking statemen ts include the items identified in the preceding paragraph, in formation concerning possible or assumed future results of operations and other statements in this Form 10-K identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projectio n,” “goal,” “plan,” “forecast,” “target” or similar expressions.

You should not place undue reliance on forward-looking stat ements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our 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, ri sks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any fo rward-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);

 our ability to fund our planned capital investments;

 our ability to transport our production to the most favorable markets or at all;

 the timing and extent of our success in discovering, developing, producing and estimating reserves;

 the economic viability of, and our success in drilling, our large acreage position in the Fayetteville Shale play overall as well as relative to other productive shale natural gas plays;

 the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate an d over the counter derivatives;

 the costs and availability of oilfield personnel, servi ces and drilling supplies, raw materials, and equipment, including pressure pumping equipment and crews;

 our ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale play and Marcellus Shale play;

 our future property acquisition or divestiture activities;

 the impact of the adverse outcome of any material litigation against us;

 the effects of weather;

 increased competition and regulation;

 the financial impact of accounting regu lations and critical accounting policies;

 the comparative cost of alternative fuels;

 conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed;

 credit risk relating to the risk of loss as a resu lt of non-performance by our counterparties; and

 any other factors listed in the reports we have filed and may file with the Secu rities and Exchange Commission

SEC.63 We caution you that forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, third-party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks

, regulatory changes, the uncertainty inherent in estimating prov ed natural gas and oil reserves and in projecting future rates of production and timing of development expenditures and the other risks described in Item 1A of Part I of this Form 10-K.

Estimates of our proved natural gas and oil reserves and the estimated future net revenues from such reserves in this Form 10-K are based upon various assumptions, including assu mptions required by the SEC relating to natural gas and oil prices, drilling and operating expenses, capital investments, ta xes and availability of funds. The process of estimating natural gas and oil reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical , engineering and economic data for each reservoir. Therefore, those estimates are inherently imprecise.

Actual future production, natural gas and oil prices, reve nues, taxes, development costs, operating expenses and quantities of recoverable natural gas and oil reserves will most likely vary from those estimated. Such variances may be material. Any significant variance could mate rially affect the estimated quantities and present value of reserves set forth in this Form 10-K. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our
control.

As of December 31, 2012, approximately 20% of our estima ted proved reserves were proved undeveloped and 1% were proved developed non-producing. Proved undevelope d reserves and proved developed non-producing reserves, by their nature, are less certain than proved developed producing reserves. Estimates of reserves in the non-producing categories are nearly always base d on volumetric calculations rather than the performance data used to estimate producing reserves. Recovery of proved undevel oped reserves requires significant cap ital expenditures and successful drilling operations. Recovery of proved developed non-producing rese rves requires capital expenditures to recomplete into the zones behind pipe and is subject to the risk of a successful recompletion. Production revenues from proved undeveloped and proved developed non-producing reserves will not be realized, if at all, until sometime in the future.

The reserve data assumes that we will ma ke significant capital investments to develop our reserves. Although we have prepared estimates of our natural gas and oil reserves and the costs associated with thes e reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or
that the actual results will be as estimated.

You should not assume that the present va lue of future net cash flows referred to in this Form 10-K is the current fair value of our estimated natural gas and oil reserves. In accorda nce with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on average prices over the preceding twelve months and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the average prices and costs as of the date of the estimate. Any changes in consumption by natural gas purchasers or in governmental regulations or taxation could also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% di scount factor, which is required by the SEC to be used in calculating discounted future net cash flow s for reporting purposes, is not necessarily the most accurate discount factor for

our company.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributab le to us are expressly qualified in thei r entirety by this cautionary statement.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risks relating to our operations result primarily fro m the volatility in commodity prices, basis differentials and interest rates, as well as credit risk concentrations. We use natural gas and oil swap agreements and options and interest64 rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. Our Board of Directors has approved risk mana gement policies and procedures to utilize financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of interest rate risks i s subject to the approval of our Board of Directors. These policies prohibit specu lation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primar ily of trade receivables and
derivative contracts associated with comm odities trading. Concentratio ns of credit risk with re spect to receivables are limited due to the large number of our customers and thei r dispersion across geographic areas. No single customer accounted for greater than 10% of revenues as of December 31, 2012. See “Com modities Risk” belo w for discussion of credit risk associated with commodities trading.

Interest Rate Risk

The following table presents the principal cash payments for our debt obligations and related weighted-average interest rates by expected maturity dates as of December 31, 2012. As of December 31, 2012, we had $1,669.5 million of total debt with a weighted average interest rate of 5.45% and we had no borrowings under our revolving credit facility. Interest rate swaps may be used to adjust interest rate expos ures when deemed ap propriate. We do not have any interest rate swaps in effect currently.

Expected Maturity Date Fair Value

2013 2014 2015 2016 2017 Thereafter Total 12/31/12

($ in millions)

Fixed Rate $ 1.2 $ 1.2 $ 1.2 $ 1.2 $ 41.2 $ 1,623.5 $ 1,669.5 $ 1,917.0
Average Interest Rate 7.15% 7.15% 7. 15% 7.15% 7.21% 5.40% 5.45% –

Variable Rate – – – – – – – – Average Interest Rate – – – – – – – –

Commodities Risk

We use over-the-counter natural gas and oil swap agreemen ts and options to hedge sales of our production and to hedge activity in our Midstream Services segment against the inhe rent price risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or vari able price) for a notional quan tity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which partiesagree to pay a price based on two different indices (referred to as basis swaps) and (3) the purchase and sale of indexrelated puts and calls (collars) that provide a “floor” price, below which the counterparty pays funds equal to the amount by which the price of the commodity is below the contracted floor, and a “ceiling” price above which we pay to the counterparty the amount by which the price of the commodity is above the contracted ceiling.

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas and oil. However, the market price risk is of fset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged . Credit risk relates to the risk of loss as a result of nonperformance by our counterparties. The counterparties are primarily major commercial banks, investment banks, and integrated energy companies which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualita tive assessments of these counterparties based on their credit ratings and credit default swap rate s where applicable. We have not incurred any counterparty losses related to nonperformance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future.

Exploration and Production

The following table provides information about our financial instruments that are sensitive to changes in commodity prices and that are used to hedge prices for natural gas production. The table presents the notional amount in Bcf, the weighted average contract prices and the fa ir value by expected maturity dates. As of December 31, 2012, the fair value of our financial instruments related to natural gas production and gas-in-storage was a $287.8 million asset.65 Weighted Weighted Weighted Average Average Average Fair Value at
Price to be Call Basis December 31, Volume Swapped Fi xed Price Differential 2012
(Bcf) ($/MMBtu) ($/MMBtu) ($/MMBtu) ($ in millions)

Natural Gas:

Fixed Price Swaps:

2013 185.6 $ 5.06 $ – $ – $ 279.4
2014 18.3 $ 4.51 $ – $ – $ 8.5

Basis Swaps:

2013 30.1 $ – $ – $ 0.07 $ 3.1 2014 9.1 $ – $ – $ (0.03) $ 0.9

Fixed Price Call Options:

2015 18.3 $ – $ 5.50 $ – $ (4.1)

As of December 31, 2012, our basis swap s and call options did not qualify for hedge accounting treatment. Changes in
the fair value of derivatives that do not qualify as cash flow hedges are recorded in natural gas and oil sales. For the year ended December 31, 2012, we recorded an un realized gain of $0.7 million related to the basis swaps that did not qualify for hedge accounting treatment and an unrealized loss of $1.7 million related to the change in our call option positions and

estimated ineffectiveness of our cash flow hedges. Typically, our hedge ineffectiven ess results from changes at the end of a reporting period in the price differentials between the index price of the derivative contract , which is primarily a NYMEX price, and the index price for the point of sale for the cash flow that is being hedged.

Additionally, at December 31, 2011, we had outstanding fixed price basis differential swaps on 36.6 Bcf of 2012, 30.1 Bcf of 2013 and 9.1 Bcf of 2014 natural gas production that did not qualify for hedge treatment.66 ITEM 8. FINANCIA L STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Pa g e Management’s Report on Internal Control Over Financial Reporting 67

Report of Independent Registered Public Accounting Fir m 68

Consolidated Statements of Op erations for the years ended D ecember 31, 2012, 2011 and 2010 69

Consolidated Statements of Comprehensive In come (Loss) for the years ended December 31, 2012,
2011 and 2010 70

Consolidated Balance Sheets as of December 31, 2012 and 2011 71

Consolidated Statements of Ca sh Flows for the years ended D ecember 31, 2012, 2011 and 2010 72

Consolidated Statements of Equ ity for the fiscal years ended D ecember 31, 2012, 2011 and 2010 73

N otes to Consolidated Financial Statem ents, December 31, 20 12, 2011 and 2010 7467 Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regardi ng the reliability of financial reporting and the preparation of financial statements for external purpos es in accordance with generally accepted acc ounting principles (“GAAP”). Internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly re flect the transactions and dispositions of the assets of the Co mpany; (b) provide

reasonable assurance that trans actions are recorded as necessary to permit pr eparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Compan y are being made only in accord ance with authorizations of management and directors of the Company; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Comp any’s assets that could have a material effect on the

consolidated financial statements. Because of its inherent limitations, internal control ove r financial reporting may not prevent or detect misstatements. Also, projections of any eval uation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions , or that the degree of compliance with the policies and procedures may deteriorate.

We have performed an evaluation under the supervision and with the participation of our management, including our

Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal control over financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. Our management used the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) to perform its assessment. Based on the evaluation performed, we identified the material weakness described below in the Company’ s internal control over financial reporting (as defined in Rule 13a-15(f) under the Secur ities Exchange Act of 1934, as amended) as of December 31, 2012. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financ ial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

We did not maintain effective controls over the accuracy and valuation of the non-cash impairment of the natural gas and oil properties. Specifically, we did not design effective contro ls solely related to the review of the tax benefit associat ed with capitalized intangible drilling costs within the ceiling calculation of the full cost ceiling test. This control deficien cy resulted in a misstatement of the impairment of the natural gas and oil properties, depreciation, depletion and amortization,

and related balance sheet accounts and in the restatement of the Company’s Condensed Conso lidated Financial Statements in the Company’s Forms 10-Q for the quarters ended June 30, 2012 and September 30, 2012. This control deficiency could
result in further misstatement to the aforementioned account balances or disclosures that would result in material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, management has concluded that this control deficiency constitutes a material weakness.

Because of the above described material weakness in inte rnal control over financial reporting, our management, including our Chief Executive Officer and our Chief Financia l Officer, concluded, that as of December 31, 2012, our internal control over financial reporting was not effective based on those criteria.

The effectiveness of our internal cont rol over financial reporting as of D ecember 31, 2012 has been audited by PricewaterhouseCoopers LLP, an independent registered pub lic accounting firm, as stated in their report that follows.68 Report of Independent Regist ered Public Accounting Firm

To the Board of Directors and Stockholders of Southwestern Energy Company

In our opinion, the accompanying consolid ated financial statements listed in th e accompanying index present fairly, in all material respects, the financial position of Southwestern Energy Company and its subsid iaries at December 31, 2012 and 2011, and the results of their operations and their cas h flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the Unite d States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria estab lished in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) because a material weakness in internal control over financial reporting related to the review of the tax benefit associated with capitalized intangible drilling costs within the ceiling calculation of the full cost ceiling test as described in Management’s Report on Internal Control Over Financial Reporting existed as of that date. A material weakness is a de ficiency, or a combination of de ficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in the accompanying Management's Report on Intern al Control over Financial Repor ting. We considered this material weakness in determining the nature, timing, and exte nt of audit tests applied in our audit of the December 31, 2012 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. The Company's management is responsible for these financial statements, for maintaining ef fective internal control over financial reporting and for its

assessment of the effectiveness of internal control over financ ial reporting included in management's report referred to above. Our responsibility is to express opinions on these fina ncial statements and on the Company's internal control over financial reporting based on our integrated audits. We co nducted our audits in accordance w ith the standards of the Public Company Accounting Oversight Board (United States). Those st andards require that we plan and perform the audits to

obtain reasonable assurance about whether the financial statem ents are free of material misst atement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and sign ificant estimates made by management , and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk th at a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumst ances. We believe that our aud its provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the ma intenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance w ith authorizations of management and directors of the company; and (iii) prov ide reasonable assurance regarding preven tion or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over fi nancial reporting may not preven t or detect misstatements. Also, projections of any evaluation of effe ctiveness to future period s are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may

deteriorate.

/s/ PRICEWATERHOUSECOOPERS LLP

PricewaterhouseCoopers LLP
Houston, Texas February 20, 201369 SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the years ended December 31.

2012 2011 2010 (in thousands, except share/per share amounts)
Operating Revenues:

Gas sales $ 1,941,361 $ 2,079,725 $ 1,858,727
Gas marketing 591,528 714,123 615,913

Oil sales 8,427 9,085 13,111
Gas gathering 173,727 149,973 122,912
2,715,043 2,952,906 2,610,663
Operating Costs and Expenses:

Gas purchases – midstream services 592,466 709,091 611,161
Operating expenses 244,735 240,944 191,771
General and administrative expenses 175,147 158,041 145,563
Depreciation, depletion and amortization 810,953 704,511 590,332
Impairment of natural gas and oil properties 1,939,734

– – Taxes, other than income taxes 67,584 65,518 50,608

3,830,619 1,878,105 1,589,435
Operating Income (Loss) (1,115,576) 1,074,801 1,021,228
Interest Expense:

Interest on debt 93,296 65,421 57,144
Other interest charges 4,454 4,306 1,935
Interest capitalized (62,093) (45,652) (32,916)
35,657 24,075 26,163

Other Income (Loss), Net 1,030 264 427

Income (Loss) Before Income Taxes (1,150,203) 1,050,990 995,492
Provision (Benefit) for Income Taxes:

Current 18,689 4,198 11,939

Deferred (461,828) 409,023 379,720
(443,139) 413,221 391,659

N et Income (Loss) (707,064) 637,769 603,833
Less: Net Loss Attributable to Noncontrolling Interest

– – (285)
Net Income (Loss) Attributable to Southwestern Energy $ (707,064) $ 637,769 $ 604,118

Earnings (Loss) Per Share:

Basic $ (2.03) $ 1.84 $ 1.75

Diluted $ (2.03) $ 1.82 $ 1.73

Weighted Average Common Shares Outstanding:

Basic 348,610,503 347,205,316 345,581,568

Effect of:

Stock Options

– 2,475,053 3,512,241

Restricted Stock Awards

– 241,044 216,857

Diluted 348,610,503 349,921,413 349,310,666

The accompanying notes are an integral part of these consolidated financial statements.70 SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the years ended December 31,

2012 2011 2010

(in thousands)

N et income (loss) $ (707,064) $ 637,769 $ 603,833

Change in derivatives:

Reclassification to earnings (1) (382,156) (194,693) (182,619)

Ineffectiveness (2) (1,474) 2,518 4,145
Change in fair value of derivative instruments (3) 130,935 520,552 179,649

Total change in derivatives (252,695) 328,377 1,175

Change in value of pension and other postretirement liabilities:

Current period net loss (4) (7,466) (4,129) (2,148)
Current period prior service cost (5)

– – 16
Less: amortization of prio r service cost included in net periodic pension

cost (6) 1,008 766 674
Total change in value of pension and other postretirement liabilities (6,458) (3,363) (1,458)

Change in currency translation adjustment 529 (561) (18)

Comprehensive income (loss) (965,688) 962,222 603,532

Less: comprehensive loss attributab le to the noncontrolling interest

– – (285)
Comprehensive income (loss) attri butable to Southwestern Energy $ (965,688) $ 962,222 $ 603,817

(1) Net of ($249.4), ($126.6), a nd ($118.9) million in taxes for the years ende d December 31, 2012, 2011 and 2010, respectively

.

(2) Net of ($1.0), $1.6, and $2.6 million in taxes for the years ended D ecember 31, 2012, 2011 and 2010, respectively.

(3) Net of $85.1, $338.4, and $119.5 million in taxes for the years ended D ecember 31, 2012, 2011 and 2010, respectively.

(4) Net of ($4.9), ($2.7), and ($2.0) million in taxes for the years ended December 31, 2012, 2011 and 2010, respectively.

(5) Net of less than $0.1 million in taxes for the year ended December 31, 2010.

(6) Net of $0.7, $0.5, and $0.6 million in taxes for the years ended December 31, 2012, 2011, and 2010, respectively.

The accompanying notes are an integral part of these consolidated financial statements.71 SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, December 31,

2012 2011

ASSETS (in thousands)

Current assets:

Cash and cash equivalents $ 53,583 $ 15,627

Restricted cash 8,542

– Accounts receivable 377,638 341,915

Inventories 28,141 46,234
Hedging asset 282,693 514,465

Other 58,315 60,037

Total current assets 808,912 978,278

Property and Equipment:

Natural gas and oil p roperties, using the full cost method, including $1,023.9 million

in 2012 and $942.9 million in 2011 excluded from amortization 11,283,114 9,544,708
Gathering systems 1,148,261 980,647

Other 597,064 535,464
Less: Accumulated depreciation, depletion and amortization (7,191,463) (4,415,339)

Total property and equipment, net 5,836,976 6,645,480

Other assets 91,639 279,139 TOTAL ASSETS $ 6,737,527 $ 7,902,897

LIABILITIES AND EQUITY

Current Liabilities:

Accounts payable $ 459,569 $ 514,071
Taxes payable 62,980 40,691
Interest payable 34,431 20,565
Advances from partners 68,919 84,082

Current deferred income taxes 106,123 194,163

Other 35,749 31,341

Total current liabilities 767,771 884,913

Long-term debt 1,668,273 1,342,100

Other Liabilities:

Deferred income taxes 1,049,138 1,586,798
Pension and other postretirement liabilities 33,174 20,338
Other long-term liabilities 183,299 99,444

Total long-term liabilities 2,933,884 3,048,680

Commitments and contingencies

Equity:

Common stock, $0.01 par value; author ized 1,250,000,000 shares; issued

351,100,391 shares in 2012 and 349,058,501 in 2011 3,511 3,491
Additional paid-in capital 934,939 903,399
Retained earnings 1,949,150 2,656,214
Accumulated other comprehensive income 149,804 408,428
Common stock in treasury, 64,715 shares in 2012 and 98,889 in 2011 (1,532) (2,228)

Total equity 3,035,872 3,969,304

TOTAL LIABILITIES AND EQUITY $ 6,737,527 $ 7,902,897

The accompanying notes are an integral part of these consolidated financial statements.72 SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEM ENTS OF CASH FLOWS

For the twelve months ended

December 31,

2012 2011 2010 (In thousands)
Cash Flows From Operating Activities

Net income (loss) $ (707,064) $ 637,769 $ 603,833 Adjustments to reconcile net income to net cash provided by operating

activities:

Depreciation, depletion and amortization 814,710 707,966 591,943
Impairment of natural gas and oil properties 1,939,734

– – Deferred income taxes (461,828) 409,023 379,720
Unrealized gain on derivatives (272) (281) (4,289)
Stock-based compensation 11,795 10,550 9,820

Other 1,807 991 (1,348)
Change in assets and liabilities:

Accounts receivable (35,717) 9,659 (88,488)

Inventories 18,111 (12,975) 5,099
Accounts payable 41,275 11,490 65,782
Taxes payable 22,289 (9,360) 24,551
Interest payable 5,058 610 179
Advances from partners (15,163) 2,377 29,299
Tax benefit for stock-based compensation

– (14,626) –

Other assets and liabilities 19,207 (13,376) 26,484

Net cash provided by operating activities 1,653,942 1,739,817 1,642,585

Cash Flows From Investing Activities

Capital investments (2,107,755) (2,184,474) (2,073,174)
Proceeds from sale of property and equipment 201,101 154,526 350,227

Transfers to restricted cash (167,788) (85,055) (356,035)

Transfers from restricted cash 159,246 85,055 356,035

Other 8,519 5,158 (2,684)

Net cash used in i nvesting activities (1,906,677) (2,024,790) (1,725,631)

Cash Flows From Financing Activities

Payments on current por tion of long-term debt (1,200) (1,200) (1,200)
Payments on revolving long-term debt (2,263,900) (3,445,900) (2,958,100) Borrowings under revolving long-term debt 1,592,400 3,696,200 3,054,800
Change in bank drafts outstanding (35,608) 24,637 (11,545) Proceeds from issuance of long-term debt 998,780

– – Debt issuance costs (8,339)

– – Revolving credit facility costs

– (10,211) – Proceeds from exercise of common stock options 9,184 6,412 3,897
Tax benefit for stock-based compensation

– 14,626 –

Other (428) (261) (1,612)
Net cash provided by financing activities 290,889 284,303 86,240

Effect of exchange rate changes on cash (198) 242 (323)
Increase (decrease) in cash and cash equivalents 37,956 (428) 2,871
Cash and cash equivalents at beginning of year 15,627 16,055 13,184 Cash and cash equivalents at end of period $ 53,583 $ 15,627 $ 16,055

The accompanying notes are an integral part of these consolidated financial statements.73 SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

Southwestern Energy Stockholders

Accumulated

Common Stock Additional Other Common

Shares Paid-In Retained Comprehensive Stock in N oncontrolling

Issued Amount Capital Earnings Income (Loss) Treasury Interest Total

(in thousands)

Balance at December 31, 2009 346,081 $ 3,461 $ 833,494 $ 1,414,327 $ 84,276 $ (4,333) $ 9,756 $ 2,340,981

Comprehensive income (loss):

Net income (loss) – – – 604,118 – – (285) 603,833
Other comprehensive loss – – – – (301) – – (301)
Total comprehensive income (loss) (285) 603,532

Stock-based compensation – – 16,569 – – – – 16,569
Exercise of stock options 1,293 12 3,885 – – – – 3,897

Issuance of restricted stock 392 4 (4) – – – –

– Cancellation of restricted stock (30) – – – – – –

– Tax withholding – stock compensation (3) – (112) – – – – (112)

Issuance of stock awards 1 – 37 – – – – 37
Treasury stock – non-qualified plan – – 771 – – 889 – 1,660
Distributions to noncontrolling interest in partnership – – – – – – (188) (188)

Purchase of noncontrolling interest in partnership – – 7,783 – – – (9,283) (1,500)
Balance at December 31, 2010 347,734 $ 3,477 $ 862,423 $ 2,018,445 $ 83,975 $ (3,444) $ – $ 2,964,876

Comprehensive income:

Net income – – – 637,769 – – – 637,769
Other comprehensive income – – – – 324,453 – – 324,453
Total comprehensive income – – – – – – – 962,222

Tax benefit for stock-based compensation – – 14,626 – – – – 14,626
Stock-based compensation – – 19,036 – – – – 19,036
Exercise of stock options 851 9 6,403 – – – – 6,412

Issuance of restricted stock 532 5 (5) – – – –

– Cancellation of restricted stock (52) – 1 – – – – 1
Tax withholding – stock compensation (7) – (262) – – – – (262)

Issuance of stock awards 1 – 42 – – – – 42
Treasury stock – non-qualified plan – – 1,135 – – 1,216 – 2,351
Balance at December 31, 2011 349,059 $ 3,491 $ 903,399 $ 2,656,214 $ 408,428 $ (2,228) $ – $ 3,969,304

Comprehensive loss:

Net loss – – – (707,064) – – – (707,064)
Other comprehensive loss – – – – (258,624) – – (258,624)
Total comprehensive loss – – – – – – – (965,688)

Stock-based compensation – – 22,212 – – – – 22,212
Exercise of stock options 1,607 16 9,168 – – – – 9,184

Issuance of restricted stock 539 5 (5) – – – –

– Cancellation of restricted stock (95) (1) 1 – – – –

– Tax withholding – stock compensation (11) – (393) – – – – (393)

Issuance of stock awards 1 – 44 – – – – 44
Treasury stock – non-qualified plan – – 513 – – 696 – 1,209
Balance at December 31, 2012 351,100 $ 3,511 $ 934,939 $ 1,949,150 $ 149,804 $ (1,532) $ – $ 3,035,872

The accompanying notes are an integral part of these consolidated financial statements.74 SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Southwestern Energy Company (including its subsidiaries, collectively, “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and o il exploration, development and production. The Company engages in natural gas and oil explora tion and production, natural gas gathering and natural gas marketing through its subsidiaries. Southwestern’s exploration, development and pr oduction (“E&P”) activities are principally focused within the United States on development of an unconventional natural ga s reservoir located on the Arkansas side of the Arkoma Basin, which the Company refers to as the Fayetteville Shale play. The Company is also actively engaged in exploration and production activities in Pennsylvania, where we are targeting the unconventional natural gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin. The Company has recently commenced exploration operations in southern Arkansas and northern Louisiana testing a new unconventional horizontal oil play targeting the Lower Smackover Brown Dense formation, as well as in Colorado, Montana and Canada. Southwestern’s natural gas gathering and marketing (Midstr eam Services) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania and Texas.

Basis of Presentation

The consolidated financial statements included in this Annual Report on Form 10-K present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of fi nancial statements in confor mity with GAAP requires management to make estimates and assumptions that affect th e reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of th e financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued.

Certain reclassifications have been made to the prior years financial statements to conform to the 2012 presentation.
The effects of the reclassifications we re not material to the Company’s co nsolidated financial statements.

Principles of Consolidation

The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries. Allsignificant intercompany accounts and transactions have been eliminated. In 2010, the Company purchased the noncontrolling interest in Overton Partners, L.P.

Revenue Recognition

Natural gas and oil sales. Natural gas sales and oil sales are recognized wh en the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, natural gas sales and oil sales are not recognized for deliveries in exces s of the Company’s net revenue interest, while natural gas sales and oil sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estima ted sales prices of the anticipated future settlements of the imbalances. As of December 31, 2012, the Company ha d overproduction of 8.4 Bcf valued at $28.4 million and underproduction of 9.4 Bcf valued at $29.9 million. At December 31, 2011, the Company had overproduction of 6.1 Bcf valued at $22.5 million and underproduction of 6.4 Bcf valued at $22.9 million.

Gas marketing. The Company generally markets its natural gas, as well as some gas produced by third parties, to brokers, local distribution companies and end-users, pursuan t to a variety of contracts. Gas marketing revenues are recognized when delivery of natural gas has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured.

Gas gathering. The Company gathers its natural gas, as well as some natural gas produced by third parties, pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.75 Other. The Company maintains an underground gas storage fac ility and generally sells natural gas from its storage facility during the winter gas withdrawal season. Revenue is r ecognized on natural gas storage sales when the natural gas is sold to a purchaser at a fixed or determinable price, deliv ery has occurred, title has transferred and collectability of the revenue is reasonably assured. Other revenues, a component of gas sales, include gains of $0.9 million, $0.9 million and $2.5 million in 2012, 2011 and 2010, respectively, primarily rela ted to the sale of natural gas in underground storage.

Cash and Cash Equivalents

Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money mark et mutual funds that are read ily convertible into cash. Management considers cash and cash equivalents to have minimal credit and market risk.

Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the acco mpanying consolidated ba lance sheets. Outstanding checks included as a component of accounts payable totaled $12.1 million and $47.7 million as of December 31, 2012 and 2011, respectively.

Restricted Cash

Restricted cash represents proceeds deposited by the Comp any with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.

Inventory

Inventory recorded in current assets includes $5.6 million as of December 31 , 2012 and $7.8 million at December 31, 2011, for natural gas in underground storage owned by the Company’s E&P segment, and $22.5 million as of December 31, 2012 and $38.4 million at December 31, 2011 for tubulars and other e quipment used in the E&P segment.

The Company has one natural gas storage facility. The current portion of the natural gas is classified in inventory and
carried at the lower of cost or market. The non-current portion of the natural gas is classified in property and equipment and carried at cost. The carrying value of the non-current natu ral gas is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Withdrawals of current natural gas in underground storage are accounted for by a weighted average cost method whereby natural gas withdrawn from storage is relieved at the weighted average cost of current natural gas remaining in the facility.

Other assets include $13.8 million as of December 31, 20 12 and $19.5 million at December 31, 2011 for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems.

Tubulars and other equipment are carried at the lower of co st or market and are accounted for by a moving weighted average cost method that is applied with in specific classes of inventory items. Purchases of inventory are recorded at cost and inventory is relieved at the weighted average co st of items remaining within a specified class.

Property, Depreciation, Depletion and Amortization

Natural Gas and Oil Properties. The Company utilizes the full cost method of accoun ting for costs related to the exploration, development and acquisition of natural gas and o il properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other inte rnal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-ofproduction method. These capitalized cost s, less accumulated amortization and relate d deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10% (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in exces s of the ceiling are written off as a non- cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedg es, to calculate the ceiling value of their reserves.

Using the average quoted price from th e first day of each month from the prev ious 12 months for Henry Hub natural gas of $2.76 per MMBtu and $91.21 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil proper ties exceeded the ceiling amount and resulted in a76 ceiling test impairment as of December 31, 2012. The Compan y’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $510.4 milli on (net of tax) as of December 31, 2012 and resulted in a non-cash ceiling test impairment in addition to other ceiling test impairments in 2012 (see below). Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $257 .6 million as of December 31, 2012. At December 31, 2011, the ceiling value of the Company’s reserv es was calculated based upon average quoted price from the first day of each month from the previous 12 months fo r Henry Hub natural gas of $4.12 per MMBtu for Henry Hub natural gas and $92.71 per barrel for We st Texas Intermediate oil, and at D ecember 31, 2010, the ceiling value of the Company’s reserves was calculated based upon average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.38 per MMBtu for Henry Hub natural gas and $75.96 per barrel for West Texas Intermediate oil. Using the first-day-of-the-month prices of natural gas for the first two months of 2013 and NYMEX strip prices for the remainder of 2013, as applicable, the prices required to be used to determine the ceiling limit could result in a ceiling test write-down in 2013. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.

At September 30, 2012, the net capita lized costs of our natural gas and oil properties exceeded the ceiling by approximately $185.7 million (net of tax) and resulted in a non-cash ceiling test impairment in the third quarter of 2012. At June 30, 2012, the net capitalized costs of our natural gas and oil properties exceeded the ceiling by approximately $496.4 million (net of tax) and resulted in a non-cash ce iling test impairment in the second quarter of 2012.

All of our costs directly associated with the acquisitio n and evaluation of properties in Canada relating to our exploration program as of December 31, 2012 were unproved and did not exceed the ceiling amount. If our exploration program in Canada is unsuccessful on all or a portion of these properties, or if further extensions are not granted, if requested, a ceiling test impairment may result in the future.

Gathering Systems. The Company’s investment in gathering systems is primarily related to its Fayetteville Shale play in Arkansas and Marcellus Shale play in Pennsylvania. These assets are being depreciated on a straight-line basis over 25

years.

Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and actively being evaluated.

Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or wh en it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the a sset. The asset retirement obligation is re corded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company owns natural gas and oil properties which require expenditures to plug and abandon the wells when reserves in the wells are depleted.

Income Taxes

The Company follows the asset and liability method of accoun ting for income taxes. Under this method, deferred tax

assets and liabilities are recorded for the estimated future ta x consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabiliti es are measured using the tax rate in effect for the year in wh ich those temporary differences are expected to reverse. The effect of a change in tax rates on deferre d tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation al lowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The ta x benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benef it that has a greater than 50% likelihood of being realized upon ultimate settlement. The eff ective tax rate and the tax basi s of assets and liabilities refle ct management’s estimates of the ultimate outcome of various tax uncertainties.77 Derivative Financial Instruments

The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity swaps and options contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in other comprehensive income (loss) to the extent that they are effective in offsetting th e changes in the cash flows of the hedged item. In contrast, gains and losses from the ineffective por tion of swaps and option contacts as well as basis swap and call option contracts that do not qualify for he dge accounting treatment are recognized curre ntly in gas sales in the consolidated statements of operations. Changes in the fair value of derivative instruments designated as fair value hedges as well as the offsetting gain or loss on the hedged item are recognized in ea rnings immediately. See Note 5 for a discussion of the Company’s hedging activities.

Earnings Per Share

Basic earnings per common share attributable to Southwestern stockholders is computed by dividing net income (loss) attributable to Southwestern by the weighted average number of common shares outstanding during each year. The diluted earnings per share attributable to Southwestern stockholders calculation adds to the weighted average number of common shares outstanding the incremental shares that would have been outstanding assuming the exercise of dilutive stock options and the vesting of unvested restri cted shares of common stock.

As we recognized a net loss for the year ended December 31, 2012, the unvested stock optio ns were not recognized in diluted earnings per share (“Diluted EPS” ) calculations as they would be antidilutiv e. Options for 1,716,109 shares were
excluded from the calculation of diluted shares because they would have had an antidilutive effect. For the year ended December 31, 2011, outstanding options for 3, 577,104 shares with an average exercise price of $11.78 were included in the calculation of diluted shares. Options for 881,254 shares were excluded from the calcula tion because they would have
had an antidilutive effect . For the year ended December 31 , 2010, outstanding options for 4,753,530 shares with an average exercise price of $9.42 were in cluded in the calculation of diluted shar es. Options for 548,160 shares were

excluded from the calculation because they would have had an antidilutive effect.

As we recognized a net loss for the year ended Decembe r 31, 2012, the unvested share-based payments were not recognized in diluted earnings per shar e (“Diluted EPS”) calculations as they would be antidilutive. The calculation of
diluted shares exclud ed 602,429 shares of restricted b ecause they would have had an antid ilutive effect. For the year ended December 31, 2011, 241, 044 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 135,352 shares of restricted stock because they would have had an antidilutive effect. For the year ended December 31, 2010, 700, 512 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 39,600 shares of restricted stock becau se they would have had an antidilutive effect.



### Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information (in thousands):

For the years ended December 31,

2012 2011 2010

(in thousands)

Cash paid during the year for interest, net of amounts capitalized $ 17,311 $ 19,159 $ 24,049

Cash paid during the year for income taxes 818 4,198 14,368 Increase (decrease) in noncash property additions $ (26,240) $ 30,389 $ 46,588

Stock-Based Compensation

The Company accounts for stock-based co mpensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly rela ted to the acquisition, exploration and development activities of the Company’s natural gas and oil propertie s or directly related to the constructio n of the Company’s gathering systems.78 Treasury Stock

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liability of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and ar e presented as treasury stock and carried at cost. As of December 31, 2012, 64,7 15 shares were accounted for as treasury stock, compared to 98,889 shar es at December 31, 2011.

Foreign Currency Translation

We have designated the Canadian dollar as the functional currency for our operations in Canada. The cumulative translation effects of translating the accounts from the functiona l currency into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.

New Accounting Standards Implemented in this Report

In May 2011, the FASB issued guidance on fair value measurement and disclosure requirements outlined in Accounting Standards Update No. 2011-04, Fair Value Measurement (Topic 820) –Amendments to Achieve Common Fair
Value Measurement and Disclosure Re quirements in U.S. GAAP and IFRS (“Update 2011-04”). Update 2011-04 expands existing fair value disclosure requirements, particularly fo r Level 3 inputs, including: quantitative disclosure of the unobservable inputs and assumptions us ed in the measurement; description of the valuation processes in place and sensitivity of the fair value to changes in unobservable inpu ts and interrelationships between those inputs; the level of items (in the fair value hierarchy) that are not measured at fair value in the ba lance sheet but whose fair value must be disclosed; and the use of a nonfinancial asset if it differ s from the highest and best use assumed in the fair value measurement. The amendments in Update 2011-04 must be applied prospectively and are effective during interim and annual periods beginning after December 15, 2011. The implem entation of these changes did not have an impact on the Company’s consolidated results of operations, financial position or cash flows.

In July 2011, the FASB issued Accounting Standards Update No. 2011-05, Presentation of Comprehensive Income (“Update 2011-05”), which amends Topic 200, Comprehensive Income . Update 2011-05 eliminates the option to present components of other comprehensive income (“OCI”) in the statement of changes in stockholders’ equity, and requires presentation of total comprehensive income and components of net income in a single statement of comprehensive income, or in two separate, consecutive statements. Update 2011-05 requires presentation of reclassification adjustments for items
transferred from OCI to net income on the face of the financ ial statements where the com ponents of net income and the components of OCI are presented. The amendments do not change current treatment of items in OCI, transfer of items from OCI, or reporting items in OCI net of the related tax im pact. Update 2011-05 is effectiv e for fiscal years and interim periods beginning after December 15, 2011. The Company early adopted all disclosure requirements of 2011-05 for the year-end December 31, 2011, except those items which were deferred by Accounting Standards Update No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comp rehensive Income in Accounting Standards Update No. 2011-

05. The implementation of these changes did not have an impact on the Company’s results of operations, financial position
or cash flows.

Accounting Standards Not Yet Implemented

In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“Update 2013-02”), which finalizes Proposed ASU No. 2012-240, and seeks to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. Update 2013-02 replaces the presentation requirements in ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income , and ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendmen ts to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 . Update 2013-02 requires an entity to report the effect of significan t reclassifications out of accumulated othe r comprehensive income on the respective line items in net income if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income. For public entities, Update 2013-02 is effective prospectively for reporting periods beginning after December 15, 2012, with early adoption permitted. The implementation of the disclosure requirement is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.79 In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”), which finalizes Proposed ASU No. 2012-250 and clarifies the scope of transactions that are subject to disclosures concerning offse tting. Update 2013-01 addresses implementation issues regarding the scope of ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities , issued in December 2011. Update 2013-01 clar ifies that the scope of the disclosures under U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreem ents, and securities borrowing and securities lending transactions that are offs et either in accordance with FASB ASC Section 210-20-45, Balance Sheet—Offsetting—Other Presentation Matters , or FASB ASC Section 815-10-45, Derivatives and Hedging—Overall—
Other Presentation Matters , or are subject to a master netting arrangement or similar agreement. Update 2013-01 requires an entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to provide the required disclosures retrospectively for all comparative pe riods presented. The implementation of the disclosure requirement is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

(2) DIVESTITURES

In May 2012, we sold certain oil and natural gas leas es, wells and gathering equipment in East Texas for approximately $166.0 million. The assets included in the sale represented all of the Company’s interests and related assets in the Overton Field in Smith County. The net production from the sold assets was approximately 24.0 MMcfe per day as of the closing date and our net proved reserves were approximately 143.0 Bcfe at December 31, 2011.

In May 2011, we sold certain oil and natural gas leas es, wells and gathering equipment in East Texas for approximately $118.1 million. The sale included only the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 9,717 net acres. The net production from the Haynesville and Middle Bossier Shale intervals in this acreage was approximately 7.0 MMcf per day and proved net reserves were approximately 37.1 Bcf when the sale was closed in May 2011.

(3) PREPAID EXPENSES

The components of prepaid expenses incl uded in other current assets as of December 31, 2012 and 2011 consisted of the following:

2012 2011
(in thousands)

Prepaid drilling costs $ 30,101 $ 42,775 Prepaid insurance 9,507 7,275

Total $ 39,608 $ 50,050

(4) NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

The Company’s natural gas and oil properties are located in the United States and Canada.

Net Capitalized Costs

The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortizati on as of December 31, 2012 and 2011:

2012 2011 (in thousands)

Proved properties $ 10,259,226 $ 8,601,818 Unproved properties 1,023,888 (1) 942,890 (1)

Total capitalized costs 11,283,114 9,544,708 Less: Accumulated depreciation, depletion and amortization 6,774,174 4,092,410

N et capitalized costs $ 4,508,940 $ 5,452,298

(1) Includes $40.4 and $27.9 million related to our exploration program in Canada as of December 31, 2012 and 2011, respectivel y.80 The table below sets forth the compos ition of net unevaluated costs excluded from amortization as of December 31,

2012.

2012 2011 2010 Prior Total
(in thousands)

Property acquisition costs $ 193,258 $ 232,615 $ 123,736 $ 45,081 $ 594,690 (1)

Exploration and development costs 233,888 65,479 15,357 36,958 351,682 (1)

Capitalized interest 11,578 25,163 18,989 21,786 77,516 (1)

$ 438,724 $ 323,257 $ 158,082 $ 103,825 $ 1,023,888

(1) Property acquisition costs include $14. 8 million, exploration costs include $22.5 million and capitalized interest includes $3.1 million related to our exploration program in Canada.

Of the total net unevaluated costs excluded from amortization as of December 31, 2012, approximately $25.9 million is related to unevaluated seismic costs in the Fayetteville Sh ale play, approximatel y $44.0 million is related to acquisition of undeveloped properties in the Company’s Fayetteville Shale play, approximately $145.6 million is related to acquisition of undeveloped properties in the Company’s Marcellus Shale play and approximately $387.1 million is related to acquisition of undeveloped properties in the Company’s New Ve ntures, excluding our exploration program in Canada. The Company has $40.4 million of unevaluated costs related to its exploration program in Canada. Additionally, the Company has approximately $270.8 million of unevaluated costs related to costs of wells in progress. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drillin g wells, results of drilling, and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.

Costs Incurred in Natural Gas an d Oil Exploratio n and Development

The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities:

2012 2011 2010

(in thousands, except per Mcfe amounts)

Proved property acquisition costs $ – $ 17 $ –

Unproved property acquisition costs 220,822 (1) 262,886 (1) 229,909 (1)

Exploration costs 197,280 (2) 63,419 (2) 27,062 (2)

Development costs 1,492,841 1,633,784 1,524,453

Capitalized costs incurred 1,910,943 1,960,106 1,781,424

Full cost pool amor tization per Mcfe $ 1.31 $ 1.30 $ 1.34

(1) Includes $3.6 million, $0.2 million and $2.5 million, in 2012, 201 1 and 2010, respectively, relate d to our exploration program in Canada. (2) Includes $2.5 million, $18.4 milli on and $8.2 million in 2012, 2011 and 2010, respec tively, related to our exploration program in Canada.

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $62.1 million, $43.4 million and $32.9 million during 2012, 2011 and 2010, respectively, based on the Company’s weighted average cost of borrowings used to finance the expenditures.

In addition to capitalized interest, the Company also capitalized internal costs of $159.7 million, $147.7 million and $139.2 million during 2012, 2011 and 2010, respectively. Th ese internal costs were directly related to acquisition, exploration and development activities and are included as pa rt of the cost of natural gas and oil properties.81 Results of Operations from Natural Gas and Oil Producing Activities

The table below sets forth the results of operations from natural gas and oil producing activities:

2012 2011 2010
(in thousands)

Sales $ 1,948,222 $ 2,100,488 $ 1,890,444 Production (lifting) costs (505,271) (469,153) (376,939) Depreciation, depletion and amortization (765,192) (666,107) (561,003) Impairment of natural gas and oil properties (1,939,734)

– – (1,261,975) 965,228 952,502
Provision (benefit) for income taxes (502,690) 376,049 371,281

Results of operations $ (759,285) $ 589,179 $ 581,221

The results of operations shown above exclude general and administrative expenses, and interest expense and are not necessarily indicative of the contribution made by our natu ral gas and oil operations to the Company’s consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.

Natural Gas and Oil Reserve Quantities

Company engaged the services of Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties and accounted for approximately 93%, 90% and 85% of the present worth of the Company’s total proved reserves as of December 31, 2012, 2011 an d 2010, respectively. A reserve audit is not the same as a financial audit and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. Reserve estimates ar e inherently imprecise and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, the Co mpany’s estimates are expected to change, an d such changes could be material and occur
in the near term as future information becomes available.

The following table summarizes the changes in the Company’s proved natural gas and oil reserves for 2012, 2011 and
2010 all of which were located in the United States:

2012 2011 2010

Natural Natural Natural

Gas Oil Gas Oil Gas Oil (MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)

Proved reserves, beginning of year 5,887,207 996 4,929,980 1,219 3,650,303 1,059 Revisions of prev ious estimates (2,087,985) (44) 34,505 (125) 309,292 50
Extensions, discoveries and other additions 918,594 154 1,459,428 2 1,429,439 281

Production (564,484) (83) (499,433) (97) (403,636) (171) Acquisition of reserves in place

– – 13 – – – Disposition of reserves in place (136,534) (779) (37,286) (3) (55,418) – Proved reserves, end of year 4,016,798 244 5,887,207 996 4,929,980 1,219

Proved developed reserves: Beginning of year 3,254,018 983 2,687,238 1,173 1,972,767 1,028 End of year 3,195,662 243 3,254,018 983 2,687,238 1,173

Proved undeveloped reserves: Beginning of year 2,633,189 13 2,242,742 46 1,677,536 31 End of year 821,136 1 2,633,189 13 2,242,742 46

The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil.82 Standardized Measure of Discounted Future Net Cash Flows

The following standardized measures of discounted future net cash flows relating to proved natural gas and oil reserves as of December 31, 2012, 2011 and 2010 are calculated after income ta xes and discounted using a 10% annual discount rate and do not purport to present the fair market value the Company’s proved gas and oil reserves:

2012 2011 2010
(in thousands)

Future cash inflows $ 9,570,652 $ 22,012,205 $ 19,620,254 Future production costs (4,737,297) (8,080,207) (6,826,915) Future development costs (711,050) (3,425,185) (3,025,433)

Future income tax expense (745,251) (3,366,175) (3,143,571)

Future net cash flows 3,377,054 7,140,638 6,624,335

10% annual discount for estimat ed timing of cash flows (1,326,389) (3,689,838) (3,610,585)

Standardized measure of disc ounted future net cash flows $ 2,050,665 $ 3,450,800 $ 3,013,750

Under the standardized measure, future cash inflows were es timated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardi zed measure above were $2.76 per MMBtu for natural gas and $91.21 per barrel for oil in 2012, $4.12 per MMBtu for natural gas and $92.71 per barrel for oil in 2011, and $4.38 per MMBtu for natural gas and $75.96 per barrel for oil in 2010. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.

Following is an analysis of changes in the standardized measure during 2012, 2011 and 2010:

2012 2011 2010

(in thousands) Standardized measure, beginning of year $ 3,450,800 $ 3,013,750 $ 1,801,818 Sales and transfers of natural gas and oil produced, net of production costs (1,443,606) (1,632,156) (1,516,571)

N et changes in prices and production costs (2,604,591) (381,131) 706,062

Extensions, discoveries, and other a dditions, net of future production and

development costs 549,601 1,163,992 1,205,464 Acquisition of reserves in place

– 30 – Sales of reserves in place (157,108) (11,761) (6,269) Revisions of previous quantity estimates (1,109,409) 34,221 324,284

Accretion of discount 480,315 426,245 230,355

N et change in income taxes 1,079,158 (103,643) (746,971) Changes in estimated future development costs 2,475,470 70,492 (10,558) Previously estimated development costs incurred during the year 61,949 564,894 353,560 Changes in production rates (timing) and other (731,914) 305,867 672,576

Standardized measure, end of year $ 2,050,665 $ 3,450,800 $ 3,013,75083 (5) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to volatility in market prices and ba sis differentials for natural gas and oil which impacts the predictability of its cash flows related to the sale of natural gas and oil. These risks are managed by the Company’s use of
certain derivative financial instruments. As of Decem ber 31, 2012 and 2011, the Company’s derivative financial instruments consisted of price swaps, costless-collars, call options and basis swaps. A description of the Company’s derivative financial instruments is provided below:

Fixed price swaps The Company receives a fixed price for the c ontract and pays a floating market price to the
counterparty.

Floating price swaps The Company receives a floating market price fr om the counterparty and pays a fixed price.

Costless-collars Arrangements that contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, th e Company receives the fixed price and pays the market price. If the ma rket price is between the call and the put strike price, no payments are du e from either party.

Basis swaps Arrangements that guarantee a price differential for natural ga s from a specified delivery point. The Company receives a payment fro m the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the
stated terms of the contract.

Fixed price call options The Company sells call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty such excess on sold call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

GAAP requires that all derivatives be recognized in the bala nce sheet as either an asset or liability and be measured at fair value. Under GAAP, certain criteria must be satisfied in order for derivative financial instruments to be classified and accounted for as either a cash flow or a fair value hedge. Accounting for qualifying hedges requires a derivative’s gains and losses to be recorded either in earnings or as a component of other comprehensive income. Gains and losses on
derivatives that are not elected for he dge accounting treatment or that do not meet hedge accounting requirements are recorded in earnings.

The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy at the time the transactions are entered into and the Comp any closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financ ial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.84 The balance sheet classification of th e derivative financial instruments are summarized below as of December 31,
2012 and 2011:

Derivative Assets

December 31, 2012 December 31, 2011

Balance Sheet
Classification Fair Value Balance Sheet
Classification Fair Value
(in thousands)
Derivatives designated as hedging instruments:
Fixed and floating price swaps Hedging asset $ 279,443 Hedging asset $ 333,479

Costless-collars Hedging asset

– Hedging asset 179,080
Fixed and floating price swaps Other assets 8,550 Other assets 201,081 Total derivatives designated as hedging

instruments $ 287,993 $ 713,640

Derivatives not de signated as hedging
instruments:
Basis swaps Hedging asset $ 3,250 Hedging asset $ 1,906
Basis swaps Other assets 901 Other assets 1,797
Total derivatives not designated as hedging

instruments $ 4,151 $ 3,703

Total derivative assets $ 292,144 $ 717,343

Derivative Liabilities
December 31, 2012 December 31, 2011

Balance Sheet
Classification Fair Value Balance Sheet
Classification Fair Value
(in thousands)
Derivatives designated as hedging instruments: Fixed and floating price swaps
Other current liabilities $

– Other current liabilities $ 11,849

Costless-collars Other current liabilities

– Other current liabilities 209 Total derivatives designated as hedging

instruments $

– $ 12,058

Derivatives not de signated as hedging

instruments:

Basis swaps Other current liabilities $ 138 Other current liabilities $ 400 Basis swaps Other long-term liabilities

– Other long-term liabilities 55 Fixed price call options Other long-term liabilities 4,128 Other long-term liabilities –
Total derivatives not designated as hedging

instruments $ 4,266 $ 455

Total derivative liabilities $ 4,266 $ 12,513

Cash Flow Hedges

The reporting of gains and losses on cash flow derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gains and losses on the derivative hedging instruments are recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gain s and losses from the derivative hedging instrument recognized in earnings immediately.85 As of December 31, 2012, the Company had cash flow hedge s on the following volumes of natural gas production and gas-in-underground storage (in Bcf):

Year Fixed price swaps

2013 185.6

2014 18.3

As of December 31, 2012, the Company recorded a gain in accumulated other comprehensive income related to its hedging activities of $172.2 mi llion net of a deferred income tax liability of $112.9 million. The amount recorded in accumulated other comprehensive income will be relieved over tim e and recognized in the stat ement of operations as the physical transactions being he dged occur. Assuming the market prices of natural gas futures as of December 31, 2012 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of approximately $167.2 million from accumulated other comprehensive income to earnings du ring the next 12 months. Ga ins or losses from derivative instruments designated as cash flow hedges are reflected as ad justments to natural gas sales in the consolidated statements of operations. Natural gas sales included a realized gain fr om settled contracts of $631.5 million for the year ended December 31, 2012 compared to a realized gain of $320.1 million for the year ended December 31, 2011. Volatility in net income, comprehensive income and accumulated other comprehens ive income may occur in the future as a result of the Company’s derivative activities.

The following tables summ arize the before tax effect of all cash flow he dges on the consolidated financial statements for the years ended December 31, 2012 and 2011.

Gain Recognized in Other Comprehensive Income (Effective Portion) For the years ended December 31,

Derivative Instrument 2012 2011 (in thousands) Fixed price swaps $ 178,660 $ 714,740

Costless-collars $ 39,247 $ 144,126

Classification of Gain Gain Reclassified from Accumulated Other Comprehensive Income into Earnings

Reclassified from Accumu lated (Effective Portion)

Other Comprehensive Income For the years ended

into Earnings December 31, Derivative Instrument (Effective Portion) 2012 2011 (in thousands) Fixed price swaps Gas Sales $ 413,410 $ 256,229

Costless-collars Gas Sales $ 218,119 $ 65,047

Gain (Loss) Recognized in Earnings

(Ineffective Portion)

Classification of Gain (Loss) For the years ended

Recognized in Earnings December 31,

Derivative Instrument (Ineffective Portion) 2012 2011 (in thousands) Fixed price swaps Gas Sales $ 2,450 $ (4,018)

Costless-collars Gas Sales $ (24) $ (137)

Fair Value Hedges

For fair value hedges, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item are recognized in ear nings immediately. As of December 31, 2012, the Company had no fair value hedges, and no86 material fair value hedg es at December 31, 2011.

Other Derivative Contracts

Although the Company’s basis swaps meet the objective of managing comm odity price exposure, these trades are typically not entered into concurrent with the Company’s de rivative instruments that qualify as cash flow hedges and therefore do not generally qu alify for hedge accounting. Selling call options allows the Company to obtain above-market swaps on a portion of the Company’s projected natural gas production, these trades do not qualify for hedge accounting. Basis swap and call option derivative instruments that do not qu alify as cash flow hedges are r ecorded on the balance sheet at their fair values under hedging assets, other assets, othe r current liabilities, and other long-term liabilities, as applica ble and all realized and unrealized gains and losses related to th ese contracts are recognized imme diately in the consolidated statements of operations as a component of natural gas sales.

As of December 31, 2012, the Company had basis swaps on natural gas production that did not qualify for hedge accounting treatment of 30.1 Bcf for 2013 and 9.1 Bcf for 2014. As of December 31, 2012, the Compan y had call options on natural gas production that did not qualify for hedge accountin g treatment of 18.3 Bcf for 2015.

The following tables summarizes the before tax effect of basis swaps that di d not qualify for hedge accounting on the uncondensed consolidated statements of operations for the years ended December 31, 2012 and 2011.

Unrealized Gain (Loss)
Recognized in Earnings
Income Statement For the years ended

Classification December 31,

Derivative Instrument of Unrealized Loss 2012 2011
(in thousands)
Basis swaps Gas Sales $ 766 $ 5,222
Fixed price call op tions Gas Sales (4,128)

–

Realized Gain (Loss)
Recognized in Earnings
Income Statement For the years ended

Classification December 31,

Derivative Instrument of Realized Gain (Loss) 2012 2011
(in thousands)
Basis swaps Gas Sales $ 2,125 $ (2,135)87 (6) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Comp any’s financial instruments as of December 31, 2012 and
2011 were as follows:

The carrying values of cash and cash equivalents, accounts receivable, accounts payable, other current assets and
current liabilities on the condensed consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

Debt: The fair values of the Company’s senior notes were based on the market for the Company’s publicly-traded debt as determined based on yield of the Company’s 7.5% Senior Notes due 2018, which was 2.6% as of December 31, 2012 and 4.6% at December 31, 2011, and its 4.10% Senior Notes due 2022, which was 3.1% as of December 31, 2012. The carrying values of the borrowings under the Company’s unsecured revolving credit facility at December 31, 2011 approximate fair value because the interest rate is variable and reflective of market rates. The Company considers the fair
value of its debt to be a Level 2 meas urement on the fair value hierarchy.

Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.

December 31, 2012 December 31, 2011
Carrying Fair Carrying Fair

Amount Value Amount Value (in thousands)

Cash and cash equivalents $ 53,583 $ 53,583 $ 15,627 $ 15,627

Restricted cash $ 8,542 $ 8,542 $ – $ – Unsecured revolving credit facility $ – $ – $ 671,500 $ 671,500

Senior notes $ 1,669,473 $ 1,917,005 $ 671,800 $ 773,578

Derivative inst ruments, net $ 287,878 $ 287,878 $ 704,830 $ 704,830

GAAP establishes a fair value hierarchy th at prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hi erarchy consists of three broad levels:

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

Level 3 valuations - Consist of internal estimates and have the lowest priority.

Pursuant to GAAP, the Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s Level 2 fair valu e measurements include fixed- price and floating-price swaps and are estimated using internal discoun ted cash flow calculations using the NY MEX futures index. The Company’s Level 3 fair value measurements include costless-collars, basis sw aps and call options. The Compan y’s costless-collars and call options are valued using the Black-Scholes model, an industry standard option valuation model, and takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness. The Co mpany’s basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves.

The accounting group, reporting to the Vice President and Controller, is responsible for determining the Company’s Level 3 fair value measurements. Inputs to the Black-Scholes model, including th e volatility input, which is the significant unobservable input for Level 3 fair valu e measurements, are obtained from a third-party pricing source, with independent verification of most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively.88 Assets and liabilities measured at fair value on a recurring basis are summarized below (in thousands):

December 31, 2012

Fair Value Measurements Using: Quoted Prices Significant in Active Other Significant Markets Observable Inputs Unobs ervable Inputs Assets (Liabilities) (Level 1) (Level 2) (Level 3) at Fair Value
Derivative assets $ – $ 287,993 $ 4,151 $ 292,144
Derivative liabilities – – (4,266) (4,266)

Total $ – $ 287,993 $ (115) $ 287,878

December 31, 2011

Fair Value Measurements Using: Quoted Prices Significant in Active Other Significant Markets Observable Inputs Unobs ervable Inputs Assets (Liabilities) (Level 1) (Level 2) (Level 3) at Fair Value
Derivative assets $ – $ 534,560 $ 182,783 $ 717,343
Derivative liabilities – (11,849) (664) (12,513)

Total $ – $ 522,711 $ 182,119 $ 704,830

The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2012 and
2011. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market, observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, refl ect reasonable assumptions a marketplace participant would have used as of December 31, 2012 and at December 31, 2011.

Total net gains and losses for Level 3 derivatives for th e years ended December 31, 20 12 and 2011 are provided
below:

For the years ended
December 31,

2012 2011
(in thousands)

Balance at beginning of period $ 182,119 $ 97,677

Total gains or losses (realized/unrealized):

Included in earnings 216,857 67,998 Included in other comprehensive income (178,847) 79,215
Purchases, issuances, and settlements:

Purchases

– – Issuances

– – Settlements (220,244) (62,913)

Transfers into/out of Level 3

– 142 Balance at end of period $ (115) $ 182,119
Change in unrealized gains included in earnings relating to derivatives still held as of

December 31 $ (3,362) $ 5,08589 (7) DEBT

The components of debt as of December 31, 2012 and 2011 consisted of the following:

2012 2011
(in thousands)

Short-term debt:

7.15% Senior Notes due 2018 $ 1,200 $ 1,200

Total short-term debt 1,200 1,200

Long-term debt:

Variable rate (2.200% and 2.276% as of December 31, 2012 and December 31, 2011,

respectively) unsecured revolving cred it facility, expires February 2016

– 671,500

7.5% Senior Notes due 2018 600,000 600,000

7.35% Senior Notes due 2017 15,000 15,000

7.125% Senior Notes due 2017 25,000 25,000

7.15% Senior Notes due 2018 29,400 30,600

4.10% Senior Notes due 2022 1,000,000

– Unamortized discount (1,127)

–

Total long-term debt 1,668,273 1,342,100

Total debt $ 1,669,473 $ 1,343,300

The following is a summary of scheduled long-term debt maturities by year as of December 31, 2012 (in thousands):

2014 $ 1,200
2015 1,200
2016 1,200
2017 41,200
Thereafter 1,624,600 $ 1,669,400

Issuance of Senior Notes and Subsidiary Guarantees

In January 2008, the Company completed an offering of $600 million Senior Notes with a coupon rate of 7.5% (“7.5% Senior Notes”), a maturity in February 2018 and semi-annual interest payments. Upon a “change of control,” as defined in the indenture, holders have the option to require the Company to purchase all or any portion of the notes at a purchase price equal to 101% of the principal amount plus accrued and unpaid interest before the change of control date.

In March 2012, the Company i ssued $1.0 billion of 4.10% Se nior Notes due 2022 in a private placement. The 4.10% Senior Notes are redeemable at the Compa ny’s election, in whole or in part, at an y time prior to December 15, 2021, at a redemption price equal to the greater of: (1) 100% of the principal amount of the notes to be redeemed then outstanding; and (2) the sum of the present values of the remaining schedu led payments of principal and interest on the notes to be redeemed (not including any po rtion of such payments of in terest accrued to the date of redemption) discounted to the redemption date on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) as determined in accordance with the Indenture, plus 35 basis points, plus, in eith er of such cases, accrued and unpa id interest to the date of redemption on the notes to be redeemed. In addition, if the Company undergoes a “change of control,” as defined in the indenture, holders of the 4.10% Senior Notes will have the optio n to require the Company to purchase all or any portion of the notes at a purchase price equal to 101% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the change of control date. Payment obligations with respect to the 4.10% Senior Notes are currently guaranteed by the Company’s subsidiaries, SEECO, SEPCO and SES, which guarantees may be unconditionally released in certain circumstances. The inde ntures governing the 4.10% Senior Notes and the Company’s other senior notes contain covenants that, among other things, re strict the ability of the Company and/or its subsidiaries to incur liens, to engage in sale and leaseback transactions and to merge, consolidate or sell a ssets. In December 2012, the Company completed its offer to exchange up to $1.0 billion aggregate principa l amount of its 4.10% Senior Notes due 2022 (the “Exchange Notes”, wh ich were registered under the Securities Act of 1933, as amended (the “Act”), for any and all of its outstanding 4.10% Senior Notes due 2022, which were issued in a private placement in March 2012 (the “Private Notes”). The Exchange Notes have substantially identical terms to the Private Notes, except that the offering of the Exchange Notes was registered under the Act, and the Exchange Notes are not subj ect to any transfer restrictions. The90 Company exchanged $999,500,000 of Private Notes for Exchange Notes, and has no further obligations under the related registration rights agreement.

The indentures governing the Company’s senior notes contain cove nants that, among other thin gs, restrict the ability of the Company and/or its subsidiaries’ ability to incur liens, to engage in certain sale and leaseback transactions and to merge, consolidate, or sell certain assets. All of the Compan y’s senior notes are currently guaranteed by its subsidiaries, SEECO, Inc. (“SEECO”), Southwestern Energy Production Company (“SEPCO”) and Southwestern Energy Services Company (“SES”). If no default or event of default has occu rred and is continuing, these guarantees will be released (i) automatically upon an y sale, exchange, or transfer of all of the Company’s equity interests in the guarantor; (ii) automatically upon the liquidation and dissolution of a guaranto r; (iii) following delivery of notice to the trustee of the release of the guarantor of its obligations under the Company’ s revolving credit facility; and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the notes.

Please refer to Note 15, “Condensed Consolidating Financial Information” in this Form 10-K for additional
information

Credit Facility

In February 2011, the Company amended and restated its unsecured revolving credit fac ility, increasing the borrowing capacity to $1.5 billion and extending the maturity date to February 2016 (“Credit Facility”). The amount available under the Credit Facility may be increased to $2.0 billion at an y time upon the Company’s agreement with its existing or additional lenders. The interest rate on the Credit Facility is calculated based upon our debt rating and is currently 200 basis points over the current London Interbank Offered Rate (LIBOR) and was 200 basis points over LIBOR as of December 31, 2012. The Credit Facility is guaranteed by the Company’s subsidiary, SEECO and requires additional subsidiary guarantors if certain guaranty coverage levels ar e not satisfied. The facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 60% of its total adjusted capital and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. The terms of the Credit Facility also include covenants that restrict the ability of the Company and its material subsidiaries to merge, consolidate or sell all or substantially all of their assets, restrict the ability of the Company and its subsidiaries to incur liens and restrict the ability of the Company’s subsidiaries to incur indebtedness. As of December 31, 2012, the Co mpany was in compliance with the covenants of its debt agreements. While the Company believes all of the lenders under the Credit Facility have the ability to provide funds, it cannot predict whether each will be able to meet its obligation under the facility.

(8) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

The Company has commitments to third parties for demand tr ansportation charges. As of December 31, 2012, future payments under non-cancelable demand charges are approximately $252.4 million in 2013, $264.3 million in 2014, $284.7 million in 2015, $300.1 million in 2016, $303.9 million in 2017 and $1,409.7 million thereafter.

The Company leases 14 drilling rigs and equipment for its E& P operations under leases that expire on January 1, 2015. The Company’s current ag gregate annual payment under the leases is approximately $19.4 million. The lease payments for the drilling rigs and equipment, as well as ot her operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to third-party working interest owners f or their share of rig day-rate charges.

The Company has 11 leases for pressure pumping equipment for its E&P operations under leases that expire between December 1, 2017 and January 1, 20 18. The Company’s curr ent aggregate annual payment under the leases is approximately $7.5 million. The lease payments for the pressure pumping equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings t o third-party working interest owners for their share of fracture stage charges.

The Company leases compressors, aircraft, vehicles, o ffice space and equipment unde r non-cancelable operating leases expiring through 2020. As of December 31, 2012, fu ture minimum payments under these non-cancelable leases accounted for as operating leases are appr oximately $75.5 million in 2013, $66.0 million in 2014, $41.4 mi llion in 2015, $32.1 million in 2016, $16.8 million in 2017 and $31.1 million thereafter. The Company also has commitments for compression services related to its Midstream Services an d E&P segments. As of December 31, 2012, future minimum payments under these non-cancelable agreements are approximately $30.5 million in 2013, $17.4 million in 2014, $10.591 million in 2015, $8.9 million in 2016, $3.4 million in 2017 and no agreements thereafter.

During 2011 and 2012, SES entered into a number of short- and long-term firm transportation service and gathering agreements in support of our growing Ma rcellus Shale operations in Pennsylvania. In March 2011, SES entered into a precedent agreement with Millennium Pipeline Company, L.L.C. pursuant to which it will enter into short- and long-term firm natural gas transportation services on Millennium’s existin g system and expansions of the system are expected to be in-service by the second quarter of 2013 and late 2013. In Ju ne 2011, SES entered into separa te 15 year agreements with each of Bluestone Pipeline Company of Pennsylvania, LLC (“Bluestone Gath ering”), and Susquehanna Gathering Company I, LLC, both wholly owned subsidiaries of DTE Pi peline Company, an affiliate of DTE Energy Company. Bluestone Gathering would build and operate a natural gas gathering system in Susquehanna County, Pennsylvania and Broome County, New York, and provide gathering services to SES in support of a portion of our future Marcellus Shale natural gas production. This gathering system was initially placed into service in November 2012 and is expected to be fully completed during the first quarter of 2013. Susquehanna Gathering Company I, LLC. would build and operate gathering infrastructure from well pad recei pt locations for deliveries into the Blue stone Gathering system as well as other potential field delivery points. This system was first placed into service November 2012 and will be constructed as necessary to support the company’s activities primarily in Su squehanna County. SES also executed firm transportation agreements with Tennessee Gas Pipeline Company (“TGP”) that increase our ability to move our Marcellus Shale natural gas production in the short term to market as well as a pre cedent agreement for an expansio n project with a projected inservice date of November 2013 pursuant to which SES has subscribed for 100,000 Dekatherm/day of capacity. TGP’s expansion project will expand its 300 Line in Pennsylvania to provide natural gas transportation from the Marcellus Shale supply area to existing delivery points on the TGP system. TGP filed a certificate appli cation for the project and the Federal Energy Regulatory Commission issued a certificate on August 9, 2012. Construction would begin in second quarter 2013, with a projected November 1, 2013 in-service date. In March 2012, SES entered into a firm transportation agreement with TGP to utilize existing tran sportation capacity to various delivery poin ts on TGP’s system. SES has agreed to enter a ten year firm transportation agreement with a to tal capacity of 130 MMcf per day. The capacity went into service in November 2012. In March 2012, SES entered into a precedent agreement with Constitution Pipeline Co. LLC for a proposed 121-mile pipeline conn ecting to the Iroquois Gas Transmissi on and Tennessee Gas Pipeline systems in Schoharie County, New York. Subject to the receipt of regulatory approvals and satisfaction of other conditions, SES has agreed to enter a fifteen year firm transportation agreement with a total capacity of 150 MMcf per day. The project is expected to be in service by the sec ond quarter of 2015. We have provided certain guarantees of a portion of SES’s obligations under these agreements.

As of December 31, 2012, SES’s and SEPCO’s obligatio ns for demand and similar charges under the firm transportation agreements and gatherin g agreements totaled approximately $2.8 billion and the Company has guarantee obligations of up to $100.0 million of that amount.

In the first quarter of 2010, the Company was awarded exclusive licenses by the Province of New Brunswick in Canada to conduct an exploration program covering approximately 2.5 million acres in the province. The licenses require the Company to make certain capital investments in New Brun swick of approximately $47 million in the aggregate over a three year period. In order to obtain the licenses, the Company provided promissory notes payable on demand to the
Minister of Finance of the Province of New Brunswick with an aggregate pr incipal amount of $44.5 million Canadian dollars. The promissory notes secure the Company's capital expe nditure obligations under the licenses and are returnable to the Company to the extent the Company performs such obligations. If the Company fails to fully perform, the Minister of Finance may retain a portion of the applicable promissory notes in an amount equal to any deficiency. The Company commenced its Canada exploration progra m in 2010 and, as of December 31, 20 12 had invested $25.8 million in New Brunswick towards the Compan y’s commitment. In Decembe r 2012, we received two one- year extensions to our exploration license agreements which expi re on March 16, 2014 and March 16, 2015, respectively. No liability has been recognized in connection with the promissory notes due to the Company’s i nvestments in New Brunswick as of December 31, 2012 and its future investment plans.

Environmental Risk

The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital na ture are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial pos ition or reported results of operations of the Company.92 Litigation

Tovah Energy

In February 2009, SEPCO was added as a defendant in a Third Amended Petition in the matter of Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al. In the Sixth Amended Petition, filed in July 2010, in the 273rd District Court in Shelby County, Texas (collectively, the “S ixth Petition”), plaintiff alleged that, in 2005, they provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom. Among other things, the plainti ff’s allegations in the Sixth Petition included various statutory and common law claims, including, but not limited to claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduci ary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 15, 2005 and February 15, 2006. In the Sixth Petition, plaintiff sought actual damages of over $55.0 million as well as other remedies, including special damages and punitive damages of four times the amount of actual damages established at trial.

Immediately before the commencement of the trial in November 2010, plaintiff was permitted, over SEPCO’s objections, to file a Seventh Amended Petition claiming actual damages of $46.0 million and also seeking the equitable remedy of disgorgement of all profits fo r the misappropriation of trade secrets a nd the breach of fiduciary duty claims. In December 2010, the jury found in favor of the plaintiff with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages. The jury did not, however, award the plaintiff any special, punitive or other damages. In addition, the jury separately determined that SEPCO’s profits for purpose s of disgorgement were $381.5 million. This profit determination does not constitute a judgment or an award. The plaintiff’ s entitlement to disgorgement of profits as an equitable remedy will be determined by th e judge and it is within the judge’s discretion to award none, some or all the amount of prof it to the plaintiff. On Decem ber 31, 2010, the plaintiff file d a motion to enter the judgment based on the jury’s verdict. On February 11, 2011, SEPCO filed a motion for a judgment notwithstanding the verdict and a motion to disregard certain findings. On March 11, 2011, the plaintiff filed an amended motion for judgment and intervenor filed its motion for judgment seeking not only the monetary damages and the profits determined by the jury but also seeking, as a new remedy, a constructive trust for prof its from 143 wells as well as future drilling and sales of properties in the prospect areas. A hear ing on the post-verdict motions was held on March 14, 2011. At the suggestion of the judge, all parties voluntarily agreed to participate in non-binding mediation efforts. The mediation occurred on April 6, 2011 and was unsuccessful. On June 6, 2 011, SEPCO received by mail a letter date d June 2, 2011 from the judge, in which he made certain rulings with respect to the post-verdict motions and responses filed by the parties. In his rulings, the judge denied SEPCO’s motion for judgment, judgment notwithstanding th e verdict and to disregard certain findings. Plaintiff’s
and intervenor’s claim for a constructive trust was denied but the judge ruled that plaintiff and intervenor shall recover from SEPCO $11.4 million and a reasonable attorney’s fee of 40% of the total damages awarded and are entitled to recover on their claim for disgor gement. The judge instructed that SEPCO calcu late the profit on the designated wells for each respective period. SEPCO performed the calculation and provided it to the judge in June 2011. On July 5, 2011, plaintiff and intervenor filed a letter with the court raising objections to the accounting provided by SEPCO, to which SEPCO filed a response on July 11, 2011. On July 12, 2011, the judge sent a letter to the parties in which he ruled that after reviewing the parties’ respective position letters, he was awarding $23.9 million in disgorgement damages in favor of the plaintiff and intervenor. In the July 12, 2011 letter, the judge instructed the plaintiff and intervenor to prepare a judgment for his approval prior to July 21, 2011 consistent with his findings in his June 2, 2011 letter and the disgorgement award. On August 24, 2011, a judgment was entered pursuant to which plaintiff and intervenor are entitled to recover approximately $11.4 million in actual damages and approximately $23.9 milli on in disgorgement as well as prejudgment interest and attorneys' fees which currently are estimated to be up to $8.9 million and all costs of court of the plaintiff and intervenor. On September 23, 2011, SEPCO filed a motion for a new trial and on November 18, 2011 filed a notice of appeal. On November 30, 2011, the court approved SEPCO’s supersedeas bo nd in the amount of $14.1 mi llion, which stays executionon the judgment pending appeal. The bond covers the $11.4 million judgment for actual damages, plus $1.3 million in prejudgment interest, $1.3 million in post-judgment interest (estimating two years for the duration of appeal), and court costs.

On June 22, 2012, SEPCO filed its appellate brief and, on June 25, 2012, plaintiff and intervenor filed a crossappellate brief seeking limited remand to reassess the disgorgement determination. The parties filed their responses to the appellate and cross-appellate briefs on or about November 7, 2012. Both sides filed replies to the opposing party’s responses in January 2013. Oral argument s are expected to o ccur in spring 2013. Based on the Company's understanding and judgment of the facts and merits of this case, including appellate defenses, and after considering the advice of counsel, the Company has determined that, although reasonably possible after exhaustion of all appeals, an adverse final outcome to this lawsuit is not probable. As such, the Company has not accrued any amounts with respect to this lawsuit. If the plaintiff and intervenor were to ultimately prevail in the ap pellate process, the Company currently estimates, based on the93 judgments to date, that SEPCO’s potential liability would be up to $44.2 million, including interest and attorney’s fees. The Company’s assessment may change in the future due to occurrence of certain even ts, such as denied appeals, and such re-assessment could lead to the determination that the potential liability is probable and could be material to the Company's results of operations, financial position or cash flows.

Muncey

On February 20, 2012, the Company b ecame aware that SEPCO was named as a defendant in the matter of Gery Muncey v. Southwestern Energy Production Company, et al filed in the District Court of San Augustine County in Texas on January 31, 2012. The plaintiff in this case is also the intervenor in the Tovah Energy matter described above and alleged various claims including fraud, misappropriation and breach of fiduciary duty that are purportedly independent of the claims alleged in the Tovah Energy matter but arise from the substantially same circumstances involved in the Tovah Energy matter. SEPCO’s motion for summary judgment was granted on July 9, 2012. On August 22, 2012, the court signed a final take-nothing judgment in SEPCO’s favor. The de adlines for filing appeals have expired, so this matter has
been resolved in SEPCO’s favor.

Bureau of Land Management

In March 2010, the Company’s subsidiary, SEECO, was serv ed with a subpoena from a federal grand jury in Little Rock, Arkansas. Based on the documents requested under the subpoena and subsequent discussions described below, the Company believes the grand jury is investigating matters in volving approximately 27 horizontal wells operated by SEECO in Arkansas, including whether appropriate leases or permits were obtained therefor and whether royalties and other production attributable to federal lands have been proper ly accounted for and paid. The Company believes it has fully complied with all requests related to the federal subpoena an d delivered its affidavit to that effect. The Company and representatives of the Bureau of Land Management and the U.S. Attorney have had discussions since the production of the documents pursuant to the subpoena. In January 2011, the Company voluntarily produced additional materials informally requested by the government arising from these discussions. Although, to the Company’s knowledge, no proceeding in this matter has been initiated against SEECO, the Company cannot predict whether or when one might be initiated. The Company intends to fully comply with any further requests a nd to cooperate with any relate d investigation. No assurance
can be made as to the time or resources that will need to be de voted to this inquiry or the impact of the final outcome of the discussions or any related proceeding.

Other

We are subject to various litigation, claims and proceedings that have arisen in the ordinary course of business. Management believes, individually or in aggregate, such litigation, claims and pro ceedings will not have a material adverse impact on our financial position, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future. If an un favorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such ite ms when a liability is both probable and the amount can be reasonably estimated.

Indemnifications

The Company provides certain indemnifications in relation to dispositions of assets. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. No liability has been recognized in connecti on with these indemnifications.94 (9) INCOME TAXES

The provision (benefit) for income taxes included the following components:

2012 2011 2010
(in thousands)

Current:

Federal $ 15,500 $ 3,378 $ 10,421

State 3,189 820 1,518
18,689 4,198 11,939

Deferred:

Federal (388,209) 345,922 319,279

State (71,582) 60,941 59,982 Foreign (2,037) 2,160 459

(461,828) 409,023 379,720
Provision (benefit) for income taxes $ (443,139) $ 413,221 $ 391,659

The provision for income taxes was an effective rate of 38.5% in 2012, 39.3% in 2011 and 2010, respectively. The following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the stat utory federal tax rate to pre-tax financial income:

2012 2011 2010
(in thousands)

Expected provision (benefit) at federal statutory rate $ (402,571) $ 367,854 $ 348,632 Increase (decrease) resulting from:
State income taxes, net of federal income tax effect (44,454) 40,145 39,975

N ondeductible expenses 2,100 1,244 660

Other 1,786 3,978 2,392

Provision (benefit) for income taxes $ (443,139) $ 413,221 $ 391,659

The components of the Company’s net deferred tax liability as of December 31, 2012 and 2011 were as follows:

2012 2011
(in thousands)

Deferred tax liabilities:

Differences between book a nd tax basis of property $ 1,441,149 $ 1,916,619 Cash flow hedges 112,625 276,063

Other 4,460 15,755
1,558,234 2,208,437

Deferred tax assets:

Accrued compensation 16,387 30,316 Alternative minimum tax credit carryforward 89,016 73,516 Stored natural gas 7,812 9,053 Accrued pension costs 7,686 3,982 Asset retirement obligations 39,249 13,188 Net operating loss carryforward 217,276 287,830

Differences between book and tax basis of property - state 16,872

– Other 12,354 9,591
406,652 427,476

N et deferred tax liability $ 1,151,582 $ 1,780,961

The net deferred tax liability as of December 31, 2012 was comprised of net long-term deferred income tax liabilities of $1,045.5 million in addition to a net current deferred inco me tax liability of $106.1 million. The net deferred tax liabilit y95 at December 31, 2011 was comprised of ne t long-term deferred income tax liabilities of $1,586.8 million , in addition to a net current deferred income tax liability of $194.2 million. In 2012, the Company paid $0.8 million in state income taxes and did not pay any alternative minimum taxes. In 2011, the Company paid $0.8 million in state income taxes and paid $3.4 million in alternative minimum taxes. The Company’ s operating loss carryforward as of December 31, 2012 was $701.4 million and has expiration dates of 2027 through 2032. The Company also had an alternative minimum tax credit carryforward of $89.0 million and a st atutory depletion carryforward of $13. 6 million as of December 31, 2012.

Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises in 2012. Some exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the grant (“windfalls”). Although these additional tax benefits or “windfalls” are re flected in net operating loss carryforwards, pursuant to GAAP, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable. Accordingly, since the tax benefit does not reduce our current taxes payable in 2012 due to net operating loss carryforwards, these “windfall” tax benef its are not reflected in our net operating losses in deferred ta x assets for 2012. Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2012 were $128.3 million.

As of December 31, 2012, the Company ha s no unrecognized tax benefits. The income tax years 2010 to 2012 remain open to examination by the major taxing jurisdictions to which the Company is subject.

The Company has an income tax net operat ing loss carryforward related to its Ca nadian operations of $15.9 million, and has expiration dates of 2030 through 2032. The Company assesses the available positive and negative evidence to estimate if sufficient future taxable income will be generated to utili ze the existing deferred tax asset associated with the Canadian net operating loss. Based on this assessm ent, the Company did not record a valuat ion allowance as of December 31, 2012. The Company recorded a valuation allowance of $2.0 million in 2011, to reflect that it is more likely than not that the deferred tax asset will not be recognized. The amount of the defe rred tax asset considered rea lizable could be adjusted if

estimates of future taxable income durin g the carryforward period are increased.

(10) ASSET RETIREMENT OBLIGATIONS

The following table summariz es the Company’s 2012 and 2011 activity related to asset retirement obligations:

2012 2011
(in thousands)

Asset Retirement obligation at January 1 $ 37,693 $ 27,786

Accretion of discount 2,394 1,361 Obligations incurred 23,327 4,304 Obligations settled/removed (8,804) (883)

Revisions of estimates 46,027 5,125 Asset retirement obligation at December 31 $ 100,637 $ 37,693

Current liability 4,091 1,539 Long-term liability 96,546 36,154 Asset retirement obligation at December 31 $ 100,637 $ 37,693

In 2012, the Company recorded a correction to increase th e asset retirement obligation by approximately $39 million.

Because the amounts involved were not mate rial to the Company’s financial statemen ts in any individual prior period and the cumulative amount is not material to the current period financial statements, the Company recorded the cumulative effect of correcting this error in 2012. The Company’s asset retirement obligation balance is impacted by the Company’s credit adjusted risk free rate. The comb ination of declining treasury rates and the Company’s upgrade by Moody’s to Baa3 in February 2012, are contributing factors to the increased asset retir ement obligation balance.

(11) RETIREMENT AND EMPLOYEE BENEFIT PLANS

401(k) Defined Contribution Plan

The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $2.2 million, $1.9 million and $0.9 million of contribution expense in 2012, 2011 and 2010, respectively. Additionally, the Company capitalized $2.8 million, $3.8 million and $4.2 million of contributions in 2012, 2011 and 2010, respectively, directly related to the acquisition, exploration and developm ent activities of the Company’s natural gas and oil properties96 or directly related to the construction of the Company’s gathering systems.

Defined Benefit Pension and Other Postretirement Plans

Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of se rvice. Effective January 1, 1998, th e Company amended its pension plan to become a “cash balance” plan on a pros pective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.

The postretirement benefit plan provides contributory h ealth care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.

Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. The Company accounts for its defined benefit pension and othe r postretirement plans by recogn izing the funded status of each defined pension benefit plan and other postretirement be nefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conver sely, if a plan is underfund ed, the Company recognizes a liability.

The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets, and

funded status as of D ecember 31, 2012 and 2011:

Other Postretirement

Pension Benefits Benefits

2012 2011 2012 2011
(in thousands)

Change in benefit obligations:

Benefit obligation at January 1 $ 81,738 $ 67,933 $ 6,793 $ 4,955

Service cost 10,942 9,323 1,832 1,354

Interest cost 4,050 3,671 398 252 Participant contributions

– – 21 19

Actuarial loss 14,981 6,967 2,525 302 Benefits paid (6,951) (6,156) (105) (89)

Plan amendments 672

– – – Settlements

– – – – Benefit obligation at December 31 $ 105,432 $ 81,738 $ 11,464 $ 6,793

Other Postretirement

Pension Benefits Benefits

2012 2011 2012 2011 (in thousands)

Change in plan assets:

Fair value of plan assets at January 1 $ 68,023 $ 56,949 $ – $

– Actual return/(loss) on plan assets 11,191 4,717

– – Employer contributions 11,084 12,513 84 70 Participant contributions

– – 21 19 Benefits paid (6,951) (6,156) (105) (89)

Settlements

– – – – Fair value of plan assets at December 31 $ 83,347 $ 68,023 $ – $

– Funded status of plans at December 31 $ (22,085) $ (13,715) $ (11,464) $ (6,793)

The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded status for each period as presented above.

The change in accumulated other comprehe nsive income related to the pension pl ans was a loss of $8 .4 million ($5.097 million after tax) for the year ended December 31, 2012 and a loss of $5.4 million ($3.3 million after tax) for the year ended December 31, 2011. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a loss of $2.4 million ($1.4 million after tax) for the year ended December 31, 2012 and was a loss of $0.2 million ($0.1 m illion after tax) for the year ended December 31, 2011. Included in accumulated other comprehensive income as of December 31, 2012 and 20 11 was a $36.9 million loss ($22.3 million net of tax) and a $26.2 million loss ($15.9 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans.

The amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2013 are $0.1 million for prior service costs and $1.7 million net loss.

The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2012 and 2011 are as follows:

2012 2011
(in thousands)

Projected benefit obligation $ 105,432 $ 81,738 Accumulated benefit obligation $ 100,379 $ 77,317 Fair value of plan assets $ 83,347 $ 68,023

Pension and other postretirement benefit costs include the following components for 2012, 2011 and 2010:

Other Postretirement

Pension Benefits Benefits

2012 2011 2010 2012 2011 2010
(in thousands)

Service cost $ 10,942 $ 9,323 $ 7,096 $ 1,832 $ 1,354 $ 1,089

Interest cost 4,050 3,671 3,249 398 252 195 Expected return on plan assets (5,426) (4,398) (3,503)

– – – Amortization of transition

obligation

– – – 64 64 65 Amortization of prior service cost 286 344 346 14 14 14

Amortization of net loss 1,220 856 806 93 11 21 Net periodic benefit cost 11,072 9,796 7,994 2,401 1,695 1,384

Settlements and curtailments

– – 223

– – – Total benefit cost $ 11,072 $ 9,796 $ 8,217 $ 2,401 $ 1,695 $ 1,384

Amounts recognized in other comprehensive income for the year ended December 31, 2012 were as follows:

Pension

Benefits Other
Postretirement

Benefits
(in thousands)

N et actuarial loss arising during the yea r $ (9,215) $ (2,525) Amortization of transition obligation – 64 Amortization of prior service cost 287 14
Amortization of net loss 1,219 93
Plan amendments (672) –
Tax effect 3,343 934 $ (5,038) $ (1,420)98 The weighted average assumptions used in the measurement of the Company’s be nefit obligations as of December 31,
2012 and 2011 are as follows:

Pension Benefits Other Postretirement

Benefits

2012 2011 2012 2011

Discount rate 4.00 % 5.00 % 4.00 % 5.00 %

Rate of compensation increase 4.50 % 4.50 % n/a n/a

The weighted average assumptions used in the measurement of the Company’s net periodic benefit cost for 2012, 2011
and 2010 are as follows:

Pension Benefits Other Postretirement

Benefits

2012 2011 2010 2012 2011 2010

Discount rate 5.00 % 5.50 % 5.75 % 5.00 % 5.50 % 5.75 %

Expected return on plan assets 7.50 % 7.50 % 7.50 % n/a n/a n/a

Rate of compensation increase 4.50 % 4.50 % 4.50 % n/a n/a n/a

The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee Retirement Income Security Act and with a prudent level of diversification.

For measurement purposes, the following trend rates were assumed for 2012 and 2011:

2012 2011

Health care cost trend assumed for next year 8 % 9 %

Rate to which the cost trend is assumed to decline 5 % 5 %

Year that the rate reaches the ultimate trend rate 2031 2031

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:

1%

Increase 1%

Decrease (in thousands)

Effect on the total service an d interest cost components $ 340 $ (281) Effect on postretirement benefit obligations $ 1,639 $ (1,360)

Pension Payments and Asset Management

In 2012, the Company contributed $11.1 million to its pe nsion plans and $0.1 million to its other postretirement benefit plan. The Company expects to contribute $13.5 million to its pension plans and $0.3 million to its other postretirement benefit plan in 2013. No plan assets are expected to be returned to the Company during the next twelve
months.99 The following benefit payments, which reflect expected futu re service, as appropriate, are expected to be paid:

Pension Benefits Other

Postretirment

Benefits (in thousands)

2013 $ 4,599 $ 314
2014 $ 6,599 $ 418
2015 $ 6,573 $ 559
2016 $ 8,297 $ 748 2017 $ 9,155 $ 855 Years 2018-2022 $ 58,870 $ 6,681

The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth of plan assets and to ensure adequate liquidity exists for the near-term benefit payment of obligations to participants, retirees and beneficiarie s. The Retirement Committee of the Comp any’s Board of Directors (“Retirement Committee”) administers the Co mpany’s pension plan assets. The Retiremen t Committee believes long-term investment performance is a function of asset-class mix and restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets, international equity markets or investment grade fixed income assets.

The table below presents the allocations targeted by th e Retirement Committee and the actual weighted-average asset allocation of the Company’s pension plan as of December 31 , 2012, by asset category. The asset allocation targets are subject to change and the Retirement Committee allows for its actual allocations to deviate from target as a result of current and anticipated market conditions. Plan assets are periodically balanced wh enever the allocation to any asset class falls outside of the specified range.

Pension Plan Asset

Allocations Asset category: Target Actual

Equity securities:

U.S. large cap growth equity 6 % 6 % U.S. large cap value equity 6 % 6 % U.S. large cap core equity 15 % 14 % U.S. small cap equity 3 % 3 % Non-U.S. equity 25 % 26 % Emerging markets equity 5 % 5 % Fixed income and cash and cash equivalents 40 % 40 %

Total 100 % 100 %

Utilizing GAAP’s fair value hier archy, the Company’s fair value measurement of pension plan assets as of December 31, 2012 are as follows:

Asset category: Total Quoted Prices in
Active Markets for

Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant
Unobservable Inputs (Level 3)
(in thousands) Equity securities:

U.S. large cap growth equity (1) $ 4,588 $ 4,588 $ – $ – U.S. large cap value equity (2) 5,257 5,257 – – U.S. large cap core equity (3) 11,564 – 11,564 – U.S. small cap equity (4) 2,792 2,792 – – Non-U.S. equity (5) 21,891 21,891 – – Emerging markets equity (6) 4,454 – 4,454 –

Fixed income (7) 31,021 – 31,021 – Cash and cash equivalents 1,780 1,780 – – Total $ 83,347 $ 36,308 $ 47,039 $ –100 (1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciati on growth opportunities. (2) Mutual fund that seeks to invest in a diversified portfolio of stocks th at will increase in value over the long-term as wel l as provide current income. (3) An institutional fund that seek s to replicate the performance of the S&P 500 Index before fees. (4) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations. (5) Mutual funds that invest primarily in equity securities of companies domiciled out side of the United States, primarily in d eveloped markets. (6) An institutional fund that invests prim arily in the equity secur ities of companies domiciled in emerging markets. (7) An institutional fund that seeks to rep licate the performance of the Barclays Ca pital Long-Term Corpor ate Bond Index before fees through a sampling

process.

Utilizing GAAP’s fair value hierarch y, the Company’s fair value measurement of pension plan assets at December 31, 2011 are as follows:

Asset category: Total Quoted Prices in
Active Markets for

Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant
Unobservable Inputs (Level 3) (in thousands) Equity securities:

U.S. large cap growth equity (1) $ 3,792 $ 3,792 $ – $ – U.S. large cap value equity (2) 3,689 3,689 – – U.S. large cap core equity (3) 10,849 – 10,849 – U.S. small cap equity (4) 2,201 2,201 – – Non-U.S. equity (5) 16,719 16,719 – – Emerging markets equity (6) 3,377 – 3,377 –

Fixed income (7) 25,192 – 25,192 – Cash and cash equivalents 2,204 2,204 – – Total $ 68,023 $ 28,605 $ 39,418 $ –

(1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciati on growth opportunities. (2) Mutual fund that seeks to invest in a diversified portfolio of stocks th at will increase in value over the long-term as wel l as provide current income. (3) An institutional fund that seek s to replicate the performance of the S&P 500 Index before fees. (4) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations. (5) Mutual funds that invest primarily in equity securities of companies domiciled out side of the United States, primarily in d eveloped markets. (6) An institutional fund that invests prim arily in the equity secur ities of companies domiciled in emerging markets. (7) An institutional fund that seeks to rep licate the performance of the Barclays Ca pital Long-Term Corpor ate Bond Index before fees through a sampling

process.

The Company’s pension plan assets that are classified as Level 1 are due to the pension plan’s investments comprising either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fair valu e measurement as Level 1. The Company’s Level 2 pension plan assets represent investments in institu tional funds. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Le vel 2 securities are based upon the net asset values provided by the investment managers. No concentration of risk arising within or across categories of plan assets exists due to any significant investments in a single entity, industry, country or investment fund.

(12) STOCK-BASE D COMPENSATION

The Southwestern Energy Company 2004 Stock Incentive Plan (2004 Plan) was adopted in February 2004 and approved by stockholders in May 2004. The 2004 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subs idiaries. The 2004 Plan repl aced the Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan) and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (2002 Plan) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The awards under the prior plans have been adjusted for stock splits as permitted under such plans.

The 2004 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units to employees, officers and directors that in the aggregate do not exceed 16,80 0,000 shares. The types of incentives that may be awarded are comp rehensive and are intended to enable the Company’ s board of directors to structure the most appropriate in centives and to address changes in income tax laws which may be enacted over the term of
the 2004 Plan.

As initially adopted, the 2000 Plan provided for the grant of options, stock appreciation rights, shares of phantom stock, and shares of restricted stock to employees, officers and di rectors that in the aggreg ate did not exceed 1,250,000 shares of common stock. As initially adopt ed, the 2002 Plan provided for grants of optio ns, stock appreciation rights,101 shares of phantom stock and shares of re stricted stock that in the aggregate did not exceed 300,000 sh ares to employees who are not officers or directors of the Company under provisio ns of Section 16 of the Securities Exchange Act of 1934, as
amended.

The Company may utilize treasury shares, if available, or authorized but unissued shares when a stock option is
exercised or when restri cted stock is granted.

The Company measures the cost of employee services receiv ed in exchange for an award of equity instruments based on the grant date fair value of the award. All options are issued at fair market valu e at the date of grant and expire seven years from the date of grant for awards under the 2004 Plan and ten years from the date of grant for awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three years from the grant date. The Company issues shares of restricted stoc k to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards gran ted to participants who have reached re tirement age or will reach retirement age during the vesting period. Re stricted stock and stock optio ns granted to participants on or after December 8, 2005 immediately vest upon death, disability or retiremen t (subject to a minimum of five years of service).

Stock Options

The Company recorded the following co mpensation costs related to stock optio ns for the years ended December 31, 2012, 2011 and 2010:

2012 2011 2010

(in thousands)

Stock-based compensation cost related to stock options – general and administrative expense $ 5,427 $ 4,959 $ 4,706 Stock-based compensation cost related to stock options – capitalized $ 4,468 $ 3,365 $ 2,679

The Company also recorded a deferred tax benefit of $2.2 million related to stock options in 2012, compared to deferred tax benefits of $1.7 million in 2011 and $1.7 million in 2010. A total of $20.4 million of unrecognized compensation cost related to the Company’s unvested stock option and restricted stock grants. This cost is expected to be recognized over a weighted-average period of 2.9 years.

The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on exercise of stock options, post vesting forfeitures and other factors to estimate the expected term of th e stock-based payments granted. The risk free interest rate is based on the U.S. Treasury yield curv e in effect at the time of grant.

Assumptions 2012 2011 2010

Risk-free interest rate 0.6% 0.9% 2.0%

Expected dividend yield –

– – Expected volatility 58.2% 58.1% 60.1%

Expected term 5 years 5 years 5 years102 The following tables summarize stock option activity for the years 2012, 2011 and 2010 and provide information for options outstanding at Decem ber 31 of such years:

2012 2011 2010
Weighted Weighted Weighted
Average Average Average

Number Exercise Number Exercise Number Exercise

of Shares Price of Shares Price of Shares Price

Options outstanding at January 1 4,741,732 $ 21.24 4,769,122 $ 16.13 5,649,233 $ 11.59

Granted 613,120 34.34 853,478 36.64 446,895 37.05

Exercised (1,607,784) 5.71 (850,659) 7.54 (1,293,046) 3.01
Forfeited or expired (97,548) 37.76 (30,209) 35.46 (33,960) 35.26

Options outstanding at December 31 3,649,520 $ 29.84 4,741,732 $ 21.24 4,769,122 $ 16.13

Options Outstanding Options Exercisable
Weighted Weighted
Average Average
Options Weighted Remaining Aggregat e Options Weighted Remaining Aggregate
Outstanding at Average Contractual Intrinsic Exercisable at Average Contractual Intrinsic
Range of December 31, Exercise Life Value December 31, Exercise Life Value
Exercise Prices 2012 Price (Years) (thousands) 2012 Price (Years) (thousands)

$1.43 - $3.10 465,772 $ 2.64 0.9 465,772 $ 2.64 0.9
$16.75 - $29.69 553,756 24.32 1.7 541,606 24.24 1.6
$30.23 - $35.91 1,175,749 33.04 5.2 505,485 31.30 3.1
$36.22 - $39.68 1,062,788 36.77 5.5 493,943 36.75 5.3
$40.15 - $51.47 391,455 41.60 4.0 365,732 41.49 3.9

3,649,520 $ 29.84 4.1 $ 20,521 2,372,538 $ 26.77 2.9 $ 20,437

The weighted-average grant-date fair value of options granted during the years 2012, 2011 and 2010 was $16.91, $18.17 and $19.40, respectively. The total intrinsic value of options exercised during 2012, 2011 and 2010 was $44.1 million, $27.0 million and $41.4 million, respectively.

Restricted Stock

The Company recorded the fo llowing compensation costs related to rest ricted stock grants for the years ended December 31, 2012, 2011 and 2010:

2012 2011 2010

(in thousands)

Stock-based compensation cost relate d to restricted stock grants – general and administrative expens e $ 6,368 $ 5,591 $ 5,114

Stock-based compensation cost relate d to restricted stock grants – capitalized $ 5,994 $ 5,162 $ 4,107

The Company also recorded a deferred tax liability of $1.4 million related to restricted stock for the year ended December 31, 2012, compared to deferr ed tax liabilities of $2.1 million for 2011 and $1.4 million for 2010. As of December 31, 2012, there was $32.0 milli on of total unrecognized compensation co st related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of 3.2 years.103 The following table summarizes the restricted stock activity for the years 2012, 2011 and 2010 and provides

information for restricted stock outstanding at Decem ber 31 of such years:

2012 2011 2010

Weighted Weighted Weighted

Average Average Average

Number Grant Date Number Grant Date Number Grant Date

of Shares Fair Value of Shares Fair Value of Shares Fair Value

Unvested shares at January 1 1,019,737 $ 36.71 834,058 $ 36.24 794,529 $ 33.70

Granted 537,244 34.39 532,754 36.41 390,415 36.46

Vested (344,164) 36.50 (294,358) 34.90 (319,894) 30.45

Forfeited (95,302) 36.97 (52,717) 36.45 (30,992) 33.54

Unvested shares at December 31 1,117,515 $ 35.64 1,019,737 $ 36.71 834,058 $ 36.24

The fair values of the grants were $18.5 million for 2012, $19.4 million for 2011 and $14.2 million for 2010. The total fair value of shares vested were $12.6 million for 2012, $10.9 million for 2011 and $9.7 million for 2010.

(13) SEGMENT INFORMATION

The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and oil. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas volumes and through gathering fees asso ciated with the transportation of natural gas to market.

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs and expenses. Income before income taxes, for the purpose of reco nciling the operating income amount shown be low to consolidated income before income taxes, is the sum of operating income, interest expe nse and other income (loss), net. The “Other” column includes items not related to the Company’s reportable segm ents including real esta te and corporate items.

Exploration

an d Midstrea m Production Services Other Total (in thousands)

2012 Revenues from external customers $ 1,949,674 $ 765,255 $ 114 $ 2,715,043 Intersegment revenues (1,452) 1,598,225 2,751 1,599,524 Operating income (loss) (1) (1,411,211) 294,302 1,333 (1,115,576) Other income (loss), net (1,156) 132 2,054 1,030 Depreciation, depletion and amortization expense 765,368 44,395 1,190 810,953 Impairment of natural gas and oil properties 1,939,734 – – 1,939,734 Interest expense (2) 20,315 14,341 1,001 35,657 Provision (benefit) for income taxes (2) (548,556) 104,522 895 (443,139)

Assets 5,193,733 (3) 1,273,228 270,566 6,737,527 Capital investments (4) 1,860,681 164,978 54,860 2,080,519

2011 Revenues from external customers $ 2, 088,763 $ 864,096 $ 47 $ 2,952,906 Intersegment revenues 11,725 1,995,423 3,221 2,010,369 Operating income 825,138 247,952 1,711 1,074,801 Other income (loss), net 328 (91) 27 264 Depreciation, depletion and amor tization expense 666,125 37,261 1,125 704,511 Interest expense (2) 9,026 15,049 – 24,075

Provision for income taxes (2) 322,714 90,221 286 413,221
Assets 6,547,117 (3) 1,119,861 235,919 7,902,897104 Capital investments (4) 1,977,493 160,776 68,905 2,207,174

2010 Revenues from external customers $ 1, 871,835 $ 738,828 $ – $ 2,610,663 Intersegment revenues 18,609 1,715,012 984 1,734,605 Operating income 829,462 191,566 200 1,021,228
Other income, net 235 179 13 427 Depreciation, depletion and am ortization expense 561,018 28,765 549 590,332 Interest expense (2) 7,888 18,275 – 26,163

Provision for income taxes (2) 323,748 67,834 77 391,659
Assets 4,849,478 (3) 1,016,563 151,422 6,017,463 Capital investments (4) 1,775,518 271,316 73,231 2,120,065

(1) The operating loss for the E&P segment for the twelve months ended December 31, 2012 includes a $1, 939.7 million non-cash c eiling test impairment of our natural gas and oil properties.

(2) Interest income, interest expense and the provision (benefit) for income taxes by segment ar e an allocation of corporate a mounts as cash equivalents, debt and income tax expense allocated as they are incurred at the corporate level.

(3) Includes capital investments for office, technology, drilling rigs and other ancillary equipment not directly related to na tural gas and oil property acquisition, exploration and development activities.

(4) Capital investments include a decrease of $36.9 million for 201 2, an increase of $4.3 million for 2011 and an increase of $ 14.4 million for 2010 related to the change in accrue d expenditures between years.

Included in intersegment revenues of the Midstream Services segment are $1.3 billion, $1.7 billion and $1.5 billion for 2012, 2011 and 2010, respectively, for marketing of the Co mpany’s E&P sales. Corporate assets include cash and cash equivalents, restricted cash, furniture and fixtures, prepaid debt and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocat ed to the segments. For 2012 and 2011, capital investments within the E&P segment include $11.6 million and $18.7 mil lion, respectively, related to the Company’s activities in Canada. As of December 31, 2012, E&P assets include $44.4 million and at D ecember 31, 2011, asse ts include $28.4 million related to the Company’s activities in Canada.105 (14) QUARTERLY RESULTS (UNAUDITED)

The following is a summary of the quarterly results of operations for the years ended December 31, 2012 and 2011:

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (in thousands, except per share amounts)

2012

Operating revenues $ 656,469 $ 599,728 $ 685,848 $ 772,998
Operating income (loss) 185,960 (652,394) (71,838) (577,304)

N et income (loss) 107,704 (405,132) (54,053) (355,583) Earnings (loss) per share - Basic 0.31 (1.16) (0.16) (1.02)
Earnin g s ( loss ) p er share - Dilute d 0.31 ( 1.16 ) ( 0.16 ) ( 1.02 )

2011

Operating revenues $ 676,335 $ 765,166 $ 767,255 $ 744,150
Operating income 232,651 282,542 295,718 263,890

N et income 136,609 167,454 175,173 158,533 Earnings per share - Basic 0.39 0.48 0.50 0.47 Earnings per share - Diluted 0.39 0.48 0.50 0.45

(15) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Company is providing condensed consolidating financial information for SEECO, SEPCO and SES, its subsidiaries that are currently guarantors of the Company’s registered public debt, and for its other subsidiaries that are not guarantors of such debt. These wholly owned subsidiary guar antors have jointly and severally, fully and unconditionally guaranteed the Company’s 7.35% Senior Notes, 7.125% Senior Notes and 4.10% Senior Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future su bordinated debt of the subsidiary guarantor s; (iii) are effectively subordinated to any future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subord inated to all debt and other obligations of the subsidiaries of the guarantors. In the case of each series of notes, if no default or event of default has o ccurred and is continuing, these guarantees will be released (i) automatically upon any sale, exchange or transfer of all of the Company’s equity interests in the guarantor; (ii) automatically upon the liquidation and dissolution of a guaranto r; (iii) following delivery of notice to the trustee of the release of the guarantor of its obligations under the Company’ s revolving credit facility; and (iv) upon legal or covenant defeasance or other satisfaction of the obligations under the notes.

The Company has not presented separate financial and narrative information for each of the subsidiary guarantors
because it believes that such financial and narrative informa tion would not provide any add itional information that would be material in evaluating the sufficiency of the guarantees . The following condensed consolidating financial information summarizes the results of operations, financial position and cash flows for the Company’s guarantor and non-guarantor
subsidiaries.106 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

Parent Guarantors NonGuarantors Eliminations Consolidated

(in thousands)
Year ended December 31, 2012: Operating revenues $ – $ 2,541,684 $ 476,997 $ (303,638) $ 2,715,043
Operating costs and expenses:

Gas purchases – 593,091 – (625) 592,466
Operating expenses – 423,147 121,953 (300,365) 244,735
General and administrative expenses – 151,488 26,307 (2,648) 175,147
Depreciation, depletion and am ortization – 765,623 45,330 – 810,953
Impairment of natural gas and oil properties – 1,939,734 – – 1,939,734

Taxes, other than income taxes – 56,262 11,321 1 67,584

Total operating costs and expenses – 3,929,345 204,911 (303,637) 3,830,619
Operating income (loss) – (1,387,661) 272,086 (1) (1,115,576)
Other income (loss), net – (1,143) 2,173 – 1,030
Equity in earnings of subsidiaries (707,064) – – 707,064 –
Interest expense – 22,312 13,345 – 35,657
Income (loss) before income taxes (707,064) (1,411,116) 260,914 707,063 (1,150,203)
Provision (benefit) for income taxes – (538,357) 95,218 – (443,139)

N et income (loss) (707,064) (872,759) 165,696 707,063 (707,064) Comprehensive income (loss) $ (965,688) $ (1,125,454) $ 166,225 $ 959,229 $ (965,688)

Year ended December 31, 2011: Operating revenues $ – $ 2,803,385 $ 411,998 $ (262,477) $ 2,952,906
Operating costs and expenses:

Gas purchases – 710,487 – (1,396) 709,091
Operating expenses – 380,154 118,713 (257,923) 240,944
General and administrative expenses – 141,499 19,700 (3,158) 158,041
Depreciation, depletion and amortization – 665,615 38,896 – 704,511

Taxes, other than income taxes – 53,950 11,568 – 65,518

Total operating costs and expenses – 1,951,705 188,877 (262,477) 1,878,105
Operating income (loss) – 851,680 223,121 – 1,074,801
Other income (loss), net – 306 (42) – 264
Equity in earnings of subsidiaries 637,769 – – (637,769) –
Interest expense – 11,277 12,798 – 24,075
Income (loss) before income taxes 637,769 840,709 210,281 (637,769) 1,050,990

Provision for income taxes – 332,795 80,426 – 413,221

N et income (loss) 637,769 507,914 129,855 (637,769) 637,769 Comprehensive income (loss) $ 962,222 $ 836,291 $ 129,294 $ (965,585) $ 962,222107 Year ended December 31, 2010: Operating revenues $ – $ 2,488,105 $ 318,232 $ (195,674) $ 2,610,663
Operating costs and expenses:

Gas purchases – 612,745 – (1,584) 611,161
Operating expenses – 293,713 91,164 (193,106) 191,771
General and administrative expenses – 127,022 19,525 (984) 145,563
Depreciation, depletion and amortization – 559,845 30,487 – 590,332

Taxes, other than income taxes – 44,200 6,408 – 50,608

Total operating costs and expenses – 1,637,525 147,584 (195,674) 1,589,435
Operating income – 850,580 170,648 – 1,021,228

Other income, net – 242 185 – 427
Equity in earnings of subsidiaries 604,118 – – (604,118) –
Interest expense – 10,777 15,386 – 26,163
Income (loss) before income taxes 604,118 840,045 155,447 (604,118) 995,492

Provision for income taxes – 330,879 60,780 – 391,659

N et income (loss) 604,118 509,166 94,667 (604,118) 603,833
Less: Net loss attributable to noncontrolling

interest – (285) – – (285)

N et income (loss) attributable to

Southwestern Energy 604,118 509,451 94,667 (604,118) 604,118 Comprehensive income (loss) $ 603,817 $ 510,626 $ 94,649 $ (605,275) $ 603,817108 CONDENSED CONSOLIDATING BALANCE SHEETS

Parent Guarantors NonGuarantors Eliminations Consolidated

(in thousands) December 31, 2012:

ASSETS

Cash and cash equivalents $ 47,491 $ 5,988 $ 104 $
– $ 53,583

Restricted cash 8,542

– – – 8,542

Accounts receivable 2,677 353,607 21,354

– 377,638

Inventories 2 26,975 1,164

– 28,141

Other current assets 7,461 321,396 12,151

– 341,008

Total current assets 66,173 707,966 34,773

– 808,912

Intercompany receivables 2,259,713 42 27,077 (2,286,832)

–

Property and equipment 220,837 11,491,222 1,316,380

– 13,028,439

Less: Accumulated deprec iation, depletion and

amortization (82,178) (6,923,106) (186,179)

– (7,191,463)
138,659 4,568,116 1,130,201

– 5,836,976

Investments in subsidia ries (equity method) 2,309,947

– – (2,309,947)

–

Other assets 35,136 42,247 14,256

– 91,639

Total assets $ 4,809,628 $ 5,318,371 $ 1,206,307 $ (4,596,779) $ 6,737,527

LIABILITIES AND EQUITY

Accounts payable $ 140,367 $ 375,604 $ 41,009 $
– $ 556,980

Other current liabilities 3,758 205,623 1,410

– 210,791

Total current liabilities 144,125 581,227 42,419

– 767,771

Intercompany payables

– 2,108,360 178,472 (2,286,832)

–

Long-term debt 1,668,273

– – – 1,668,273

Deferred income taxes (116,207) 820,279 345,066

– 1,049,138

Other liabilities 77,565 124,505 14,403

– 216,473

Total liabilities 1,773,756 3,634,371 580,360 (2,286,832) 3,701,655

Commitments and contingencies Total equity 3,035,872 1,684,000 625,947 (2,309,947) 3,035,872

Total liabilities and equity $ 4,809,628 $ 5,318,371 $ 1,206,307 $ (4,596,779) $ 6,737,527109 CONDENSED CONSOLIDATING BALANCE SHEETS

Parent Guarantors NonGuarantors Eliminations Consolidated

(in thousands)
December 31, 2011:

ASSETS

Cash and cash equivalents $ 14,711 $ – $ 916 $ – $ 15,627

Accounts receivable 2,914 309,038 29,963 – 341,915
Inventories – 45,260 974 – 46,234
Other current assets 6,087 563,635 4,780 – 574,502

Total current assets 23,712 917,933 36,633 – 978,278

Intercompany receivables 2,053, 132 53 23,517 (2,076,702) –

Property and equipment 180,300 9, 731,944 1,148,575 – 11,060,819
Less: Accumulated deprec iation, depletion and

amortization (57,254) (4,220,205) (137,880) – (4,415,339)
123,046 5,511,739 1,010,695 – 6,645,480

Investments in subsidiaries (equity method) 3,256,195 – – (3,256,195) –

Other assets 28,641 227,152 23,346 – 279,139

Total assets $ 5,484,726 $ 6,656,877 $ 1,094,191 $ (5,332,897) $ 7,902,897

LIABILITIES AND EQUITY

Accounts payable $ 205,341 $ 332,710 $ 37,276 $ – $ 575,327

Other current liabilities 5,912 301,170 2,504 – 309,586

Total current liabilities 211,253 633,880 39,780 – 884,913

Intercompany payables – 1,628,750 447,952 (2,076,702) –

Long-term debt 1,342,100 – – – 1,342,100
Deferred income taxes (97,045) 1,442,576 241,267 – 1,586,798
Other liabilities 59,114 54,826 5,842 – 119,782

Total liabilities 1,515,422 3,760 ,032 734,841 (2,076,702) 3,933,593

Commitments and conti ngencies Total equity 3,969,304 2,896, 845 359,350 (3,256,195) 3,969,304

Total liabilities and equity $ 5,484,726 $ 6,656,877 $ 1,094,191 $ (5,332,897) $ 7,902,897110 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

Parent Guarantors Non-Guarantors Eliminations Consolidated

(in thousands)

Year ended December 31, 2012:

N et cash provided by (used in) operating activities $ (39,934) $ 1,278,673 $ 415,203 $ – $ 1,653,942 Investing activities: Capital investments (36,918) (1,868,487) (202,350) – (2,107,755) Proceeds from sale of prop erty and equipment 26,006 169, 149 5,946 – 201,101 Transfers to restricted cash (167,788) – – – (167,788)
Transfers from restricted cash 159,245 1 – – 159,246 Other (696) (35,792) 45,007 – 8,519

N et cash used in investing activities (20,151) (1,735,129) (151,397) – (1,906,677) Financing activities: Intercompany activities (198,023) 462,443 (264,420) – – Payments on current portion of long-term debt (1,200) – – – (1,200) Payments on revolving long-term debt (2,263,900) – – – (2,263,900) Borrowing under revolving long-term debt 1,592,400 – – – 1,592,400

Proceeds from issuance of long-term debt 998,780 – – – 998,780 Other (35,192) 1 – – (35,191)

N et cash provided by (used in) financing activities 92,865 462,444 (264,420) – 290,889 Effect of exchange rate changes on cash – – (198) – (198) Increase (decrease) in cash and cash equivalents 32,780 5,988 (812) – 37,956 Cash and cash equivalents at beginning of year 14,711 – 916 – 15,627 Cash and cash equivalents at end of year $ 47,491 $ 5,988 $ 104 $ – $ 53,583

Year ended December 31, 2011:

N et cash provided by operating activities $ 14,688 $ 1,482,853 $ 242,276 $ – $ 1,739,817 Investing activities: Capital investments (66,647) (1,916,246) (201,581) – (2,184,474) Proceeds from sale of proper ty and equipment – 154,261 265 – 154,526 Transfers to restricted cash (85,055) – – – (85,055)
Transfers from restricted cash 85,055 – – – 85,055 Other 16,263 (43,961) 32,856 – 5,158

N et cash used in investing activities (50,384) (1,805,946) (168,460) – (2,024,790) Financing activities: Intercompany activities (242,277) 315,462 (73,185) – – Payments on current portion of long-term debt (1,200) – – – (1,200) Payments on revolving long-term debt (3,445,900) – – – (3,445,900) Borrowings under revolving long-term debt 3,696,200 – – – 3,696,200
Other 35,203 – – – 35,203

N et cash provided by financing activities 42,026 315,462 (73,185) – 284,303 Effect of exchange rate changes on cash – – 242 – 242 Increase (decrease) in cash and cash equivalents 6,330 (7,631) 873 – (428) Cash and cash equivalents at beginning of year 8,381 7,631 43 – 16,055 Cash and cash equivalents at end of period $ 14,711 $ – $ 916 $ – $ 15,627

Year ended December 31, 2010:

N et cash provided by operating activities $ 25,865 $ 1,368,248 $ 248,472 $ – $ 1,642,585 Investing activities: Capital investments (46,062) (1,718,847) (308,265) – (2,073,174) Proceeds from sale of property and equipment – 348,274 1,953 – 350,227 Transfers to restricted cash (356,035) – – – (356,035)
Transfers from restricted cash 356,035 – – – 356,035 Other 11,864 (22,719) 8,171 – (2,684)

N et cash used in investing activities (34,198) (1,393,292) (298,141) – (1,725,631) Financing activities: Intercompany activities (76,904) 26,899 50,005 – – Payments on current portion of long-term debt (1,200) – – – (1,200) Payments on revolving long-term debt (2,958,100) – – – (2,958,100) Borrowings under revolving long-term debt 3,054,800 – – – 3,054,800
Other (9,260) – – – (9,260)

N et cash provided by financing activities 9,336 26,899 50,005 – 86,240 Effect of exchange rate changes on cash – – (323) – (323) Increase in cash and cash equivalents 1,003 1,855 13 – 2,871 Cash and cash equivalents at beginning of year 7,378 5,776 30 – 13,184 Cash and cash equivalents at end of period $ 8,381 $ 7,631 $ 43 $ – $ 16,055111 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our

Chief Executive Officer and Chief Financia l Officer, of the effectiveness of our di sclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, (the Exchange Act) as of December 31, 2012. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate informati on to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reas onable assurance with respect to financial statement preparation and presentation.

Based on the ineffectiveness of the design of controls solely related to the review of the tax benefit associated with capitalized intangible drilling costs within the ceiling calculation of the full cost ceiling test, resulting in an overstateme nt of our full cost ceiling test impairment of natural gas and o il properties, our Chief Executiv e Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were not effective as of Dece mber 31, 2012 because of the material weakness in internal control over financial reporting described in Management’s Report on Internal Control over Financial Reporting.

Plan of Remediation of Material Weakness

Management has taken steps to remediate the material weakness, including enhanced analytical analysis and improved cross-functional management review of the non-cash ceiling test calculation through which management identified the errors. Management believes the additional control procedur es, as implemented and when validated, will fully remediate

this material weakness.

Changes in Internal Control Over Financial Reporting

We have begun the implementation of the remedial measures described above. As a result, these changes in our internal control over financial reporting during the three months ended December 31, 2012 have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting is included on page 67 of this Form 10-K.

PricewaterhouseCoopers LLP’s report on Southwestern Energy’s internal control over financial reporting is included in its Report of Independent Registered Public Accounting Firm on page 68 of this Form 10-K.

ITEM 9B. OTHER INFORMATION

On February 19, 2013, the Board of Directors of the Company approved the amendment of Section 3.1(c) of the Company’s Amended and Restated Bylaws (t he “Bylaws”) to reduce the number of ye ars of service necessary for a retired director to be appointed to the position of director emeritus without a unanimous vote of the Board of Directors of the Company from 20 years to 10 years. The Bylaws as amended and restated (the “A mended and Restated Bylaws”) are filed as Exhibit 3.2 to this Annual Report on Form 10-K and incorporated herein by reference. The foregoing description of the Amended and Restated Bylaws does not purport to be complete and is qualified in its entirety by reference to the Amended and Restated Bylaws.112 PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Name Officer Position Age Years Served
as Officer

Steven L. Mueller President and Chief Executive
Officer 59 4

William J. Way Executive Vice President & Chief Operating Officer 53 1

Mark K. Boling President - V+ Development Solutions, General Counsel & Secretary 55 11

R. Craig Owen Senior Vice President and Chief

Financial Officer 43 4

Jeffrey B. Sherrick Senior Vice President – Corporate Development 58 4

Mr. Mueller was appointed Chief Executive Officer in May 2009 and was subsequently elected to the Board of Directors in July 2009. Mr. Mueller joined us as President a nd Chief Operating Officer in June 2008. He joined us from CDX Gas, LLC, where he was employed as Executive Vice President from September 2007 to May 2008. In December 2008, CDX Gas, LLC voluntarily filed for bankruptcy. In 2009, CDX emerged from bankruptcy and resumed operations as Vitruvian Exploration LLC. From 2001 until 2007, Mr. Mu eller served first as the Seni or Vice President and General Manager Onshore and later as the Exec utive Vice President and Chief Operatin g Officer of The Houston Exploration Company. A graduate of the Colorado School of Mines, Mr. Mueller has over 30 years of experience in the oil and natural gas industry and has served in multiple operational and mana gerial roles at Tenneco Oil Company, Fina Oil Company, American Exploration Company, Belco Oil & Gas Company a nd The Houston Exploration Company. Mr. Mueller is the president of Southwestern Energy’s subsidiaries, Sout hwestern Field Services, LLC, DeSoto Sand, LLC, SWN International, LLC, Southwestern NGV Services, LLC and A.W. Realty Company. Mr. Mueller is also a director of Southwestern Energy’s subsidiaries, SW N Resources Canada, Inc., Certified Title Company and A.W. Realty Company.

Mr. Way joined the Company in 2011 as Executive Vice President and Chief Operating Officer of Southwestern Energy. He is also Executive Vice Pr esident of Southwestern Energy’s subsid iaries, Southwestern Energy Production Company, SEECO, Inc., DeSoto Drilling, Inc., Southwestern Field Services, LLC, DeSoto Sand, LLC, SWN International, LLC, Southwestern NGV Services, LLC and A. W. Realty Company. Mr. Way is also a director of Southwestern Energy’s subsidiaries, SEECO, Inc., Southwestern Energy Production Company, DeSoto Drilling, Inc., Southwestern Midstream Services Company and Southwestern Ener gy Services Company. Prior to join ing the Company, he was Senior Vice President, Americas of BG Group plc with responsibility fo r E&P, Midstream and LNG operations in the United States, Trinidad and Tobago, Chile, Bolivia, Canada and Argentina. He is a graduate of Texas A&M University with a degree in Industrial Engineering and has an MBA from The Massachusetts Institute of Technology.

Mr. Boling was appointed to his present position in December 2012. He joined us as Senior Vice President, General Counsel and Secretary in January 2002. He is also the secretary of all of Southweste rn Energy’s subsidiaries and a director of Southwestern Energy’s subsidiaries , SEECO, Inc., Southwestern Energy Pr oduction Company, DeSoto Drilling Inc., Southwestern Midstream Services Compa ny, Southwestern Energy Services Comp any, A.W. Realty Company, Certified Title Company and SWN Resources Canada, Inc. Prior to jo ining the company, Mr. Boling had a private law practice in Houston specializing in the natural gas and oil industry from 1993 to 2002. Previously, Mr. Boling was a partner with Fulbright and Jaworski L.L.P. where he was employed from 1982 to 1993.

Mr. Owen was appointed to his present position in October 2 012. He joined the Company as Controller in July 2008 and was promoted to Senior Vice President in May 2012. Immediately prior to joining the Company, he was Controller, Operations Accounting of Anadarko Petroleum Corporation, where he had held various managerial positions since 2001.113 Prior to Anadarko Petroleum, Mr. Owen was a business assurance manager at Pr icewaterhouseCoopers LLP in Houston, Texas, serving clients in the energy, insurance, banking and investment industries, and held various financial reporting roles with ARCO Pipe Line Company and Hilcorp Ener gy Company. Mr. Owen hold s a bachelor of business administration degree in accounting from Texas A&M University and is a Certified Public Accountant.

Mr. Sherrick joined the Company on October 15, 2008 as Senior Vice President, U.S. Exploitation of Southwestern Energy’s subsidiaries, SEECO, Inc. and Southwestern Energy Production Company. From 2005 to 2007, Mr. Sherrick
served as the Senior Vice Pres ident, Corporate Development of The Houston Exploration Company. In 2004, he served as the Senior Vice President, Production and Nonregulated Services of El Paso Production Company. From 1999 through 2002, he served as the Chairman, CEO and President of Enron Global Exploration and Production Inc., and prior to that he served in multiple operational and managerial roles at Enron Oil & Gas Company, an d Tenneco Oil Company. Mr. Sherrick is a graduate of Marietta College with a Bachelor of Science degree in Petroleum Engineering.

All executive officers are elected at the Annual Meeting of the Board of Directors for one-year terms or until their successors are duly elected. There are no arrangements between any officer and any other person pursuant to which he was selected as an officer. There is no family relationship betw een any of our executive officer s or between any of them and
our directors.

The definitive Proxy Statement to holders of our common st ock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Stockholders to be held on or about May 21, 2013 (“2011 Proxy Statement”), is hereby incorporated by reference for the purpose of providing information about our directors, and for discussion of our audit committee and our audit committee financial expert. We refer you to the sections “Proposal No. 1: Election of Directors” and “Share Ownership of Management, Directors and Nominees” in the 2013 Proxy Statement for information concerning our directors. We refer you to the section “Corporate Governance – Committees of the Board of Directors” in the 2013 Proxy Statement for discussion of our audit committee and our audit committee financial expert. Information concerning our executive officers is presented in Part I of this Form 10-K. We refer you to the section “Section 16(a) Beneficial Ownership Reporting Complia nce” in the 2013 Proxy Stat ement for information relating to compliance with Section 16(a) of the Exchange Act.

Southwestern Energy has adopted a code of ethics that applies to our Chief Ex ecutive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on our website at www.swn.com , and is available free of charge in print to any stockholder who requests it. Requests for copies should be addressed to the Secretary at 2350 N. Sam Houston Parkway East, Suite 125, Houston TX, 77032.

ITEM 11. EXECUTIVE COMPENSATION

The 2013 Proxy Statement is hereby incorporated by reference for the purpose of providing information about executive compensatio n, compensation committee interlocks and insider participation as well as the Compensation Committee Report. We refer you to the sections “Compensation Discussion & Analysis,” “Executive Compensation,” “Outside Director Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the 2013 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The 2013 Proxy Statement is hereby incorporated by reference for the purpose of providing information about securities authorized for issuance under our equity compensation plans and security ownership of certain beneficial owners and our management. For information about our equity compensation plans, refer to “Equity Compensation Plans” in our 2013 Proxy Statement. Refer to the sections “Security Ownership of Certain Beneficial Owners” and “Share Ownership of Management, Directors and Nominees” in our 2013 Proxy Statement for information about security ownership of certain beneficial owners and our management and directors.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE

The 2013 Proxy Statement is hereby inco rporated by reference for the purpose of providing information about certain relationships, related transactions and board independence. Refer to the sections “Transactions with Related Persons,” “Share Ownership of Management, Directors and Nomin ees,” and “Compensation Discussion and Analysis” for information about transactions with our executive officers, directors or management and to “Corporate Governance – Director Independence” and “ – Committees of the Board of Directors” for info rmation about director independence.114 ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The 2013 Proxy Statement is hereby incorporated by reference for the purpose of providing information about fees paid to the principal accountant and the audit committee’s pr e-approval policies and procedures. We refer you to the section “Relationship with Independent Registered Public Accounting Firm” in the 2013 Proxy Statement and to Exhibit A thereto for information concerning fees paid to our principa l accountant and the audit comm ittee’s pre-approval policies and procedures and other required information.

PART IV

ITEM 15. EXHIBITS, FINA NCIAL STATEMENT SCHEDULES

(a) (1) The consolidated financial statements of Southwestern Energy and its subsidiaries and the report of independent registered public accounting firm are in cluded in Item 8 of this Form 10-K.

(2) The consolidated financial statement schedules have been omitted because they are not required under the related instructions, or are not applicable.

(3) The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this

Form 10-K.115 SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused the report to be signed on its behalf by the undersigned, thereunto duly authorized.

SOUTHWESTERN ENERGY COMPANY

Dated: February 20, 2013 BY:/s/ R. CRAIG OWEN R. Craig Owen

Senior Vice President

and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 20, 2013.

/s/ HAROLD M. KORELL Director, Chairman of the Boar d
Harold M. Korell

/s/ STEVEN L. MUELLER Director, President and Chief Executive Office r Steven L. Muelle r

/s/ R. CRAIG OWEN Senior Vice President and Chief Financial Office r R. Craig Owen

/s/ JOSH C. ANDERS Vice President, Controller and Chief Accountin g Office r Josh C. Anders

/s/ LEWIS E. EPLEY, JR Directo r Lewis E. Epley, J r

/s/ JOHN D. GASS Directo r John D. Gass

/s/ ROBERT L. HOWARD Directo r Robert L. Howar d

/s/ CATHERINE A. KEHR Directo r Catherine A. Kehr

/s/ GREG D. KERLEY Directo r Greg D. Kerley

/s/ VELLO A. KUUSKRAA Directo r Vello A. Kuuskraa

/s/ KENNETH R. MOURTON Directo r Kenneth R. Mourton

/s/ ELLIOTT PEW Directo r Elliott Pew

/s/ CHARLES E. SCHARLAU Directo r Charles E. Scharlau

/s/ ALAN H. STEVENS Directo r Alan H. Stevens116 EXHIBIT INDEX

Exhibit Number Descri p tion 3.1 Amended and Restated Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010)

3.2* Amended and Restated Bylaws of Southwestern Energy Company, as amended on February 19, 2013.

4.1 Form of Com m on Stock Certificate. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)

4.2 Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock, dated April 9, 2009. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 9, 2009)

4.3 Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First National Bank of Chicago, as trustee. (Incorporated by reference to Exhibit 4 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (File No. 33- 63895) filed on November 17, 1995)

4.4 First Supplemental Indenture between Southwestern Energy Company and J.P. Morgan
Trust Com p any, N.A. (as successor to the First National Bank of Chicago) dated June 30, 2006. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)

4.5 Second Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N. A., as trustee (as succes sor to J.P. Morgan Trust Company, N.A.), dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)

4.6 Indenture dated June 1, 1998 by and among NOARK Pipeline Finance, L.L.C. and The Bank of New York. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)

4.7 First Supplemental Indenture dated May 2, 2006 by and among Southwestern Energy Company, NOARK Pipeline Finance, L.L.C., and UMB Bank, N.A., as trustee (as successor to the Bank of New York). (Incorpo rated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)

4.8 Second Supplemental Indenture between Southwestern Energy Company and UMB Bank, N.A., as trustee, dated June 30, 2006. (Incorporated b y reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)

4.9 Third Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and UMB Bank, N.A., as trustee, dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)

4.10 Guaranty dated June 1, 1998 by Southwestern Energy Company in favor of The Bank of
N ew York, as trustee, under the Indenture dated as of June 1, 1998 between NOARK Pipeline Finance L.L.C. and such trustee. (Incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2005)

4.11 Indenture dated January 16, 2008 among Southwestern Energy Company, the Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 16, 2008)

4.12 Indenture b y and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N .A., as trustee, dated as of March 5, 2012. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012)117 4.13 Policy on Confidential Voting of Southwestern Energy Company. (Incorporated by reference to the Appendix of the Registrant ’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2006 Annual Meeting of Stockholders)
4.14 Third Amended and Restated Credit Agreement dated February 14, 2011 among Southwestern Energy Compan y, JPMorgan Chase Bank, NA , Bank of America, N.A., Wells Fargo N.A., The Royal Bank of Scotland PLC, Citigroup, N.A. and the other lenders named therein, JPMorgan Chas e Bank, NA, as administrative agent. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed February 18, 2011)

10.1 Form of Second Amended and Restated Indemnity Agreement between Southwestern Energy Company and each Executive Officer and Director of the Registrant. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)

10.2 Form of Executive Severance Agreem ent between Southweste rn Energy Company and
each of the Executive Officers of Southwestern Energy Company, effective February 17, 1999. (Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)

10.3 Form of Amendment to Executive Seve rance Agreement between Southwestern Energy Company and each of the Execu tive Officers of Southwestern Energy Company prior to 2011. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)

10.4 Form of Executive Severance Agreem ent between Southweste rn Energy Company and
Executive Officers Post 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No.1-08426) for the year ended December 31, 2012) 10.5 Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.2(b) to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)

10.6 Amendment to Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Annual Report on Form 10- K (Commission File No. 1-08246) for the year ended December 31, 2008)

10.7 Second Amendment to Southwestern Energy Company Incentive Compensation Plan (Incorporated by reference to Exhibit 10.6 to the Registrant’s Annual Report on Form 10- K (Commission File No. 1-08246) for the year ended December 31, 2009)

10.8 Southwestern Energy Company Supplement al Retirement Plan as amended. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)

10.9 Southwestern Energy Co mpany Non-Qualified Retirement Pl an as amended. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)

10.10 Amendment One to the Southwestern Energy Company Non-Qualified Retirement Plan (Incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10- K (Commission File No. 1-08246) for the year ended December 31, 2009)

10.11 Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2000 Annual Meeting of Stockholders)

10.12 Southwestern Energy Company 2002 Em ployee Stock Incentive Plan, effective October 23, 2002. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)

10.13 Southwestern Energy Company 2002 Pe rformance Unit Plan, as amended, effective December 8, 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2012)118 10.14 Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)

10.15 Form of Incentive Stock Option Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)

10.16 Form of Non-Qualified Stock Option Agreement for non-employee directors for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)

10.17 Form of Incentive Stock Option for awards granted on or after December 8, 2005. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)

10.18 Form of Restricted Stock Agreement for awards granted on or after December 8, 2005. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)

10.19 Form of Non-Qualified Stock Option Agre ement for awards granted on or after December 8, 2005 and through December 8, 2011 (Incorporated by refere nce to Exhibit 10.4 to the Registrant’s Current Report on Fo rm 8-K filed on December 13, 2005)

10.20 Form of Non-Qualified Stock Option Agre ement for awards granted on or after December 8, 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08426) for the year ended December 31, 2012) 10.21 Master Lease Agreement by and betwee n Southwestern Energy Company and SunTrust Leasing Corporation dated December 29, 2006 . (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2006)

10.22 Guaranty by and between Southwestern Energy Company and Texas Gas Transmission, LLC, dated as of October 27, 2008. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2008)

10.23 Guaranty by and between Southweste rn Energy Company and Fayetteville Express Pipeline, LLC dated September 30, 2008 (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)

10.24 Retirement Letter Agreement dated February 24, 2012 between Southwestern Energy Company and Gene A. Hammons. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed February 27, 2012)

10.25 Retirement Agreement dated August 11, 2009 between Southwestern Energy Company and Harold M. Korell. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 14, 2009)

21.1* List of Subsidiaries.

23.1* Consent of PricewaterhouseCoopers LLP.

23.2* Consent of Netherland, Sewell & Associates, Inc.

31.1* Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2* Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32* Certification of CEO and CFO furnished pu rsuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

95.1* Mine Safety Disclosure.

99.1* Reserve Audit Report of Netherland, Sewell & Associates, Inc., dated January 17, 2013.

101.INS* Interactive Data File Instance Documen t119 101.SCH* Interactive Data File Schema Documen t

101.CAL* Interactive Data File Calculation Linkbase Documen t

101.LAB* Interactive Data File Label Linkbase Documen t

101.PRE* Interactive Data File Presentation Linkbase Documen t

101.DEF* Interactive Data File Definition Linkbase Document

____________ *Filed herewith