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 number, 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. Yes  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 Securities 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 subject 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 Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such 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 not

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  Non-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 York Stock Exchange –

Composite Transactions closing price on June 29, 2012 of $31.93. For purposes of this calculation, the registrant has assumed that 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 held 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, Related 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 Forward-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, Executive 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 116

 
2 

This Annual Report on Form 10-K includes certain statements that may be deemed to be “forward-looking” within the 

meaning of Section 27A of the Securities Act of 1933, or the Securities Act, and Section 21E 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 Operations — 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 forward-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 reasonably practicable after they are 

filed with the Securities and Exchange Commission, 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 website, and are available in print free of charge 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 additional 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, which we refer to as the Fayetteville 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 Marcellus 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 products and services through DeSoto Sand, L.L.C. and SWN Well 

Services, L.L.C., both of which are wholly-owned subsidiaries 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 primarily support our E&P operations and 

generate revenue from fees associated with gathering of natural gas. Our natural gas marketing subsidiary, Southwestern 

Energy Services Company, or SES, captures downstream opportunities which arise through the marketing and 

transportation of the natural gas produced 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 present value added for each dollar to be invested, which we refer to as Present Value 

Index, 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 Fayetteville Shale and the Marcellus Shale Plays. Our primary focus is to 

maximize the value of our significant acreage position in the Fayetteville Shale play, which has provided significant 
4 

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 approximately 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 176,298 net acres in the Marcellus Shale and believe our 

production and reserves from this play will 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 3,819,128 net undeveloped acres in connection with our New Ventures 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 interest. 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 of drilling 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 approximately $1,038 million in the 1,852 mile gas gathering system built for 

our Fayetteville Shale play, which was gathering approximately 2.3 Bcf per day at year-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 returns 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 borrowings under our $1.5 billion unsecured revolving credit 

facility. The planned capital program for 2013 is flexible and 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 our 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 formations 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 segment 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% decline 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 2011 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 expenses. 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 total 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 barrel 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 natural 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-tax 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 value of future income taxes on the estimated cash flows. Our 

year-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 from company to company, the after-tax PV-10 is dependent on the unique tax situation of each 

individual company. We understand that securities analysts use pre-tax PV-10 as one measure of the value of a company’s 

current proved reserves and to compare relative values among peer companies without 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 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, and to 

“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 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 sales accounted for nearly 100% of total operating 

revenues for this segment in 2012, 2011 and 2010. 
6 

The following table provides an overall and categorical summary of our oil and natural gas reserves, as of fiscal yearend 2012 based on average fiscal year prices, and our well count, 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

Net 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 gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic 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 evaluation, including analysis of petrophysical 

parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir 

parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including 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 exclude $15 million related to our 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, 2012. 

(4) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next 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. 

(5) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next 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 acreage and leases are not extended, leasehold expiring over the next 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 Fayetteville 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, leasehold expiring over the next three years will be 1,200 net acres in 2013, 670 net acres in 2014 and 17,788 net acres in 2015. 

(8) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next 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, Canada, 2,518,518 net acres will expire in March 2015. We have applied for an additional 1-year option to 

extend our exploration license agreements and, if granted by the Province of New Brusnwick, this would extend our exploration license agreements 

until March 2016. With regard to our acreage in the LSBD play, assuming successful wells are not drilled and leases are not extended, 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 securities analysts to 

compare relative values among peer companies without regard to income taxes. The reconciling difference in pre-tax PV-10 and the after-tax PV-10, 

or standardized measure, is the discounted value of future income taxes on the estimated cash flows from our proved oil and natural gas reserves. 

(10) Based upon pre-tax PV-10 of proved 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 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 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 after 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 undeveloped 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 reserves 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 require 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 cash 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 Condition 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 new 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 limitations as to the usefulness of this measure as it does not reflect the type of 

reserves or the cost of adding the reserves or indicate the potential value of the reserve additions. 

In 2012, we replaced our production volumes with 919.5 Bcfe of proved reserve 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 were 
8 

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 production 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 upward 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 average 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 production 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 reserve additions, 698.0 Bcfe were 

proved developed and 733.2 Bcfe were proved undeveloped. The upward reserve revisions during 2010 were primarily due 

to 266.7 Bcf in upward revisions related to the improved performance of wells in our Fayetteville Shale play and positive 

reserve revisions of 78.4 Bcfe due to a comparative increase in the 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 replacement ratio, including revisions, was 

141%. Our reserve replacement ratio for 2012, excluding the effect of reserve revisions, was 163%, compared 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 additions have been generated from our drilling program in the 

Fayetteville Shale play. Over the past several years, the Marcellus 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 “Our drilling plans for the Fayetteville Shale play and Marcellus 

Shale play are subject to change” and “Our 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 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 depth 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 conventional 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 acreage 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 of 
9 

this Form 10-K. Excluding our acreage in the traditional Fairway, our acreage position was obtained at an average cost of 

approximately $313 per acre and has an average royalty interest of 15%. In 2013, we expect to earn 13 sections or 

approximately 5,700 net acres, representing 3% of our drilling program. As of December 31, 2012, excluding our acreage 

in the traditional Fairway and our federal acreage, the undeveloped 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 are necessary to hold our acreage, 

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 since its commencement in 2004, 3,034 of 

which were operated by us and 552 of which were outside-operated 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, including 2,783 horizontal wells. Of the 2,783 horizontal 

wells, 2,765 wells were fracture stimulated using either slickwater or crosslinked gel stimulation treatments, or a 

combination thereof. 

Over the past several years, we have seen continual improvement in our drilling practices in the Fayetteville Shale 

play. Our operated horizontal 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-entry to re-entry during 2011. In 2010, our average completed 

operated well cost was $2.8 million per well with an average horizontal lateral length of 4,528 feet and average time to drill 

to total depth of 10.9 days from re-entry to re-entry. The operated wells we placed on production during 2012 averaged 

initial production rates of 3,629 Mcf per day, compared to average initial production rates of 3,330 Mcf per day in 2011 

and 3,364 Mcf per day in 2010. The increase 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 the field with the highest-return wells. As a result, our average 

initial production rates on a per well basis were significantly higher, particularly during the last half of 2012. The decrease 

in initial production rates in 2011 was primarily due to increased well density and locational differences in the mix of 

wells. During 2012, we placed 60 operated wells on production with initial production rates 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 the 

3,508 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 Bcf 

from 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, which 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 our 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 have 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 program with respect to our Fayetteville Shale play is flexible 

and will be impacted by a number of factors, including the results 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 commodity 
10 

price environment. As we continue to gather data about the 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 drilling 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 approximately 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 average 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 Shale 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 million per well, average horizontal lateral 

length of 4,223 feet and an average of 14 fracture stimulation stages in 2011. In 2010, our 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 properties, $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 year-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 net 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 approximately $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 “Midstream Services — Gas Marketing” for a discussion of our 

gathering and transportation arrangements for the Marcellus Shale production and to the risk factor “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 

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 significant 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 determine the most effective and economic fracture 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 change” 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. Production 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 production 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 approximately 9,717 net acres for approximately $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 our 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 213 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 approximately $15 million in our Ark-La-Tex 

division. 

New Ventures

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.” We have been focusing on both oil and natural gas unconventional plays, 

and the technological methods best suited to developing these 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 States. 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 from the Department of Natural 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 under our licenses, we are required to make investments of 

approximately $47 million USD in the province by March 31, 2013. 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 geochemistry 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, obtained at an average cost of $419 per acre. Our leases 

currently have approximately an 81% average net revenue interest and an average primary lease term of approximately 

four years, which may be extended for approximately four additional 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 several 

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 Pennsylvanian 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 projects is subject to drilling and completion technique risks and 
12 

enhanced recovery methods. Our drilling results may not meet our expectations for reserves or production and the value of 

our undeveloped New Venture acreage could decline,” and “Our 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 approximately 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 leases, 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 Arkoma 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 acquisition of properties, $10 million for seismic expenditures and $254 million in 

capitalized interest and other expenses. Additionally, we invested 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 acquisition 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 Shale play and Marcellus Shale play will be the primary focus of 

our capital investments, with planned investments of approximately $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 capitalized interest and expenses as well as equipment, facilities 

and technology-related expenditures. We refer you to “Management’s Discussion and Analysis of Financial Condition and 

Results of Operations — Liquidity and Capital Resources — Capital 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 production from our Marcellus Shale play, and a 0.3 Bcfe increase in 
13 

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 640 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 hedges 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 Risks,” for further information regarding our hedge position as of December 31, 

2012. 

Including the effect of hedges, we realized an average wellhead price 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 price received for our natural gas production, excluding the 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 sales price for our natural gas production $0.50 to $0.55 per Mcf 

below the NYMEX Henry Hub average settlement price, excluding 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 customers or any priority allocations or price limitations imposed 

by federal or state regulatory agencies, or any other factors 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 purchase natural gas at market to fulfill our obligations. 

Customers. Our customers include major energy companies, utilities 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 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 business. 
14 

Competition

All phases of the oil and natural gas industry are highly competitive. 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 producers and operators. Many of these competitors have 

financial and other resources that substantially 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 interstate pipeline transportation 

in Arkansas has increased our access to markets for our natural gas production, these markets are also served by a number 

of other suppliers. Consequently, we will encounter competition that may affect both the price we receive and contract 

terms we must offer. Outside Arkansas, we are less established 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 preferential 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 means 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 development of our recently announced 

unconventional horizontal oil play targeting the LSBD formation in Arkansas and Louisiana and potentially other New 

Venture areas. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture 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 hydraulic 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 recently 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 treatment 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 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 fracturing 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. 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 available 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 disposal 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 prohibit 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 currently 

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 curtailment 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 expected 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 and cash flows. We refer you to the 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 marketing of natural gas. Our gathering 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 2011 operating income and EBITDA were primarily due to increased gathering revenues and 

margins, partially offset by increased operating 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. 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) attributable to Southwestern Energy. 

Gas Gathering

We engage in gas gathering activities through our gathering 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 million related to these activities and had gathering revenues of 
16 

$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 lines 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 Gathering 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 throughout the Marcellus Shale play area. During 2012, Angelina 

Gathering gathered approximately 64.7 Bcf of natural gas volumes 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 Gathering 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 aggregate approximately 28,195 horsepower had also been 

installed at 3 central point gathering facilities in Pennsylvania. 

Gas Marketing

Our gas marketing subsidiary, SES, allows us to capture downstream opportunities related to marketing and 

transportation of natural gas. SES purchases natural gas and sells it to end-users, manages basis risk and marketing 

portfolio and acquires transportation rights on third-party pipelines. 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 serving 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 Fayetteville 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 was 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 “Centerpoint East.” The Fayetteville and Greenville Laterals and the 

Fayetteville Express Pipeline allow us to transport 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 Marcellus 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 entered into separate 15 year agreements 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 receipt locations for deliveries into the Bluestone 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 Susquehanna 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 precedent agreement for an expansion 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 application 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 systems 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 agreement 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 agreements. 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 obligations for demand and similar charges under the firm 

transportation agreements and gathering 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 are used for transportation from producers to end-users. Other 

factors affecting competition are the cost and availability of alternative 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 the 

marketing 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, specific 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 period. Our gathering system in Arkansas constitutes a “major 

non-interstate pipeline” under Order No. 720. In October 2011, 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 require 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 estate 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 commercial 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 Health 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 229.106) 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 measure commonly used in our industry. EBITDA should not be 

considered in isolation or as a substitute for net income (loss) attributable to Southwestern Energy, net cash provided by 

operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles 

in the United States, or GAAP, or as a measure of our profitability 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 Southwestern 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 

Net income (loss) attributable to Southwestern 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

Net 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 

Net income attributable to Southwestern Energy $ 493,726 $ 142,591 $ 1,452 $ 637,769

Depreciation, depletion and amortization 666,125 37,261 1,125 704,511

Net 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 

Net income attributable to Southwestern Energy $ 498,346 $ 105,636 $ 136 $ 604,118

Depreciation, depletion and amortization 561,018 28,765 549 590,332

Net 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 subject to numerous federal, state and local 
19 

laws and regulations including the Comprehensive Environmental Response, Compensation and Liability Act, or the 

CERCLA, the Clean Water Act, the Clean Air Act and similar state 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 casing wells, the surface use and restoration 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 relief. 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 affect 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 requirements 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 prevention 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 located. 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 negligence or willful misconduct or resulted from 

violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully 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 preparation of oil spill response plans and proof of financial 

responsibility to cover environmental cleanup and restoration costs 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 the 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 hazardous 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 substances that have been released into the environment and for 

damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for 

personal injury and property damage allegedly caused by the hazardous substances released into the environment. 

The Resource Conservation and Recovery Act, as amended, or the RCRA, generally does not regulate wastes 

generated by the exploration and production of natural gas and oil. The RCRA specifically excludes from the definition of 

hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or 

production of oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to 

time that would reclassify certain natural gas and oil exploration and production 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 impact 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 certain geological and geophysical activities that are not subject 

to extensive environmental regulation. Once we begin exploration 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 gas 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 been 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 or 
20 

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 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 oil and other hazardous substances. Many state discharge 

regulations and the Federal National Pollutant Discharge Elimination 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 experience 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 production 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 hydraulic fracturing practices at 

the federal, state and local levels of government although hydraulic fracturing is typically regulated by state oil and natural

gas commissions. 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 to the EPA’s efforts, 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 fracturing 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 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 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 were 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 pressure base of the state or area where the reserves exist and 

at 60 degrees Fahrenheit. 

“Acquisition of properties” Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease 

bonuses and options to purchase or lease properties, the portion 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 drive 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 produce 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 definition in Item 1207(d) of Regulation S-K, a link for which is 

available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used 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. Determined 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 reserves 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 other costs of development activities, are costs incurred to: 

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of 

determining specific development drilling sites, clearing ground, 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 stratigraphic 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 production 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 SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml. 

“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 SEC’s definition in Rule 4-10(a) (9) of Regulation S-X, a link 

for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml. 

“Downspacing” The process of drilling additional wells within a defined 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 Southwestern 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 operation. 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/divisions/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 information, 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/divisions/corpfin/ecfrlinks.shtml. 

“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 stratigraphic 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 reservoirs all grouped on or related to the same individual 

geological structural feature and/or stratigraphic condition. There 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 are 

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 localized 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 working interest. The number of gross wells is the total 

number of wells in which the registrant owns a working interest. 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 fractional working interests owned in gross wells or acres expressed 

as whole numbers and fractions of whole numbers. For additional information, see the SEC's definition in Item 1208(c)(2) 

of Regulation S-K, a link for which is available at the SEC'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 production cycle following the identification by geologists and 

geophysicists of areas with potential 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 resources 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, see 
24 

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. 

“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. 

“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 specially 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 reasonable certainty to be economically producible—from a given 

date forward, from known reservoirs, and under existing 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 deterministic 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 additional 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 reserves, PV-10 means the estimated future gross revenue to be 

generated from the production of proved reserves, net of estimated 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 revisions 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/divisions/corpfin/ecfrlinks.shtml. 

“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 and 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 regardless 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 “undeveloped 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, “well 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 should 

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, decreasing funds available for capital investments 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, could be severely limited or 

unavailable.

Consequently, our revenues and profitability would suffer. 

Lower natural gas and oil prices and/or increased development costs may cause 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 natural gas and oil properties. Under the full cost accounting rules 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 country-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 quarter, including the impact of derivatives qualifying as cash flow hedges, utilizing the 

average price in the 12-month period prior to the end of each fiscal quarter. The average price for this period is defined as 

the unweighted arithmetic average of the first-day-of-the-month price for each month within 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 costs, transportation costs or basis differentials increase, a 

write-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 the 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, with no borrowings under our revolving 

credit facility. At February 15, 2013, we had long-term indebtedness of $1,709.6 million, including borrowings of $40.2 

million under our revolving credit facility. We currently expect to utilize the borrowing availability under our revolving 
27 

credit facility in order to fund a portion of our capital investments 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 “financing 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 planning for, or reacting to, changes in our business and the industry in which we 

operate; and 

 detracting from our ability to successfully withstand a downturn in our 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 sufficient 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 our planned capital investments, which could adversely affect our growth. 

We have experienced and expect to continue to experience substantial capital investment and working capital needs as 

a result of our drilling program. Our planned capital investments 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 compliance 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 facility 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 unavailable, 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 natural gas and oil prices can adversely affect our results and 

the price of our common stock. This volatility also makes valuation of natural gas and oil producing properties 

difficult and can disrupt markets. 

Natural gas and oil prices have historically been, and are likely 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 April 2012. The prices for natural gas and oil are subject to 
28 

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 natural gas and oil properties, as buyers and sellers have more 

difficulty agreeing on the purchase price of such properties. Our results of operations may fluctuate significantly as a 

result of, among other things, variations in natural gas and oil prices and production performance. In recent years, natural 

gas and oil price volatility has become increasingly severe. 

The recent adoption of financial reform legislation could have an adverse effect on our ability to use derivative 

instruments to reduce the effect of commodity price, interest rate and other risks associated with our business 

which could have a material adverse effect on our financial position, results of operations 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 required the Commodities Futures Trading Commission, or the CFTC, 

and the SEC to promulgate rules and regulations implementing 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 our derivative activities. At this time it is not possible to 

predict whether or when the CFTC will adopt those rules or include 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 could significantly increase the cost of derivative contracts 

(including through requirements to post collateral which could adversely affect our available liquidity), 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 contracts, increase our exposure to less creditworthy 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 for and fund capital investments. Our revenues could also be 

adversely affected if a consequence of the legislation and regulations is lower commodity prices. Any of these 

consequences could have a material adverse 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, Sewell & Associates, Inc., or NSAI, 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 consists primarily of substantive testing, which includes a detailed 

review of major properties that account for approximately 93% of present worth of our total proved reserves. NSAI’s audit 

process consists of sorting all fields by descending present value order and selecting the fields from highest value to 

descending value until the selected fields account for more than 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 the reasonableness of our reserve estimates for the year ended 

December 31, 2012, stating that our estimated proved oil and natural gas reserves 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 under 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 reserve estimates are also separately reviewed by our accounting 

staff. Following these reviews and the audit, 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 vary 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 development, 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 natural gas price environment encountered 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 revisions 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 Texas 
30 

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 requires significant capital investments and successful drilling 

operations. As of December 31, 2012, approximately 821 Bcfe of our estimated proved reserves were undeveloped. Our 

reserve data assume that we can and will make these expenditures 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 reserves and production will decline 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 successful exploration and development activities, 

successfully apply new technologies or identify additional behind-pipe zones or secondary recovery reserves, our proved 

reserves will decline materially as reserves are produced. Future natural gas and oil production is, therefore, highly 

dependent upon our level of success in acquiring 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 2,874 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 year-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 most successful wells in addition 

to the natural gas and oil commodity price environment. The determination 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 effective 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 would use the same production facilities; 

 receipt of additional seismic or other geologic data or reprocessing of existing data; 

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

 availability and cost of capital; or 

 the impact of federal, state and local government regulation, including 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 hold our acreage, the initial lease 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 the acreage or otherwise take action to extend 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 the acreage or otherwise take action to extend the leases. As 
31 

discussed above under “Our drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to change,” 

our ability to drill wells depends on a number of factors, including 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 governmental section of approximately 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 establishing 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 operator drilling activity could impair our ability to drill and 

maintain acreage positions. To the extent that any field rules 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 the 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 transportation and gathering agreements relating to the Marcellus Shale 

play. As of December 31, 2012, our aggregate 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 transportation 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 operation 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 initial investments. Additionally, there can be no assurance that 

leasehold acreage acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will 

be productive or that we will recover all or any portion of our 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 deducting 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 producing 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 economically. The use of seismic data and other technologies also 

requires greater pre-drilling expenditures than traditional drilling strategies. 

In addition, we may not be successful in implementing our 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 economics of a project. Further, our drilling operations may be 

curtailed, delayed or canceled as a result of numerous factors, 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 expectations 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 generate the highest possible returns. Risks 

that we face while drilling include, but are not limited to, landing our wellbore in the desired drilling zone, staying in the 

desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore, 

and being able to run tools and other equipment consistently through 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 completion 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 operations. 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 projects. 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 are established over a sufficiently long time period. If our 

drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, 

lease expirations, limited access to gathering systems and takeaway capacity, and/or oil, natural gas and NGL prices 

decline, the return on our investment for a particular project may not be as attractive as we anticipated and the value of our 

undeveloped acreage could decline in the future. 

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. 

We utilize hydraulic fracturing in our E&P operations as a means 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 future expected to also include our exploration program in New Brunswick, Canada. 

Successful hydraulic fracturing techniques are also expected to be critical to the development of our recently 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-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 hydraulic 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, storage and distribution) to regulation under the NSPS and NESHAPS programs. The EPA final 

rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the 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 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 
33 

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 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. 

In addition to the EPA’s efforts, 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 fracturing 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. 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 available 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 disposal 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 prohibit 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 currently 

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 curtailment 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 expected 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 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 and cash flows. 

We incur substantial costs to comply with government regulations, especially 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 continue to make large expenditures in our efforts to comply with 

these regulations, including environmental regulation. The natural gas and oil regulatory environment could change in 

ways that might substantially increase these costs. Hydrocarbon-producing states regulate conservation practices and the 

protection of correlative rights. These regulations affect our operations and limit the quantity of hydrocarbons we may 

produce and sell. In addition, at the U.S. federal level, the FERC regulates interstate transportation of natural gas under the 

NGA. Other regulated matters include marketing, pricing, 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, and 

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 natural 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 involve 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, natural gas, brine or well fluids, hydrocarbon drainage from adjacent third-party production, 

release of contaminants into the environment 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 interruptions on gathering systems, pipelines, processing and transportation systems 

owned or operated by us or others.

The marketability of our natural gas and oil production depends 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 lower price realizations. Although we have some contractual 

control over the transportation and gathering of our production, material changes in these business relationships could 

materially affect our operations. Federal and state regulation 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 general economic conditions could adversely affect our ability to 

produce, gather, and transport natural gas. 

 In particular, if drilling in the Marcellus Shale play continues to be successful, 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 these areas. It will be necessary for additional infrastructure, 

pipelines, gathering, and transportation systems and processing facilities to be expanded, built or developed to 

accommodate anticipated production from these areas. Because of the current economic 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 systems 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 expansion 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, processing or transportation system 

access or capacity, field labor issues or strikes, or we might voluntarily curtail production 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, services, supplies, raw materials and qualified personnel could adversely affect our 

results of operations. 

The demand for qualified and experienced 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 increased
35 

demand and result in increased prices for drilling rigs, crews and associated supplies, equipment, services and raw 

materials. In addition, our E&P operations also require local access to large quantities 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 experience 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, marketing 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 and 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 efficiency of our operations. If our exploration 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 commitments for 14 drilling rigs and related 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 operations may have an adverse effect on our relationships with 

our existing third-party service and resource providers or our 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 drilling 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 alternative services or resources, there 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 require us to attract and retain experienced technical 

personnel. 

The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our 

business strategy depends, in part, on our experienced management 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 professionals could have a material 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 natural 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 approximately 
36 

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, unless 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 price 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 contracts 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 deductions 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 deductions currently available to oil and natural gas exploration 

and production companies has been proposed in recent years. These changes have included, among other proposals: 

 the repeal of the percentage depletion allowance 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 enacted. 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 water 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 unconventional 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 exploration, 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 oil and other hazardous substances. Many state discharge regulations and the Federal 

National Pollutant Discharge Elimination 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. 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 hydraulic 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 future. 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 initiatives without materially altering our operating 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, materials and services whose production utilizes hydrocarbons. 

We may also face increased competition from alternative energy sources that do not rely on hydrocarbons. We cannot 

predict with any reasonable degree of certainty our future exposure 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 risks 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 make 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 fiscal 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 estimates 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 are 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 Citation 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 natural gas reserves in multiple basins both in the United States 

and internationally. Prior to joining Southwestern in 2008, our Senior Vice President – Corporate 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 & Associates, Inc., or NSAI, a worldwide 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 years 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 Licensed Professional Engineer in the State 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 judiciously 
38 

applying industry standard practices to engineering and geoscience 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 estimates, as internally reviewed and audited by NSAI, are submitted for review and 

approval to our Chief Executive Officer. Finally, upon his approval, 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 consolidated 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 

New 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 next 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 next three years 

will be 41,860 net acres in 2013, 13,467 net acres 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 Fayetteville 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, leasehold expiring over the next three years will be 1,200 net acres in 2013, 670 net acres 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 next 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 next three years 

will be 68,023 net acres in 2013, 237,181 net acres in 2014 and 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 next 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 acreage and our exploration license agreements are not extended, 2,518,518 net 

acres in New Brunswick will expire in March 2015. We have applied for an additional 1-year option to extend our exploration license 

agreements in New Brunswick and, if granted by the Province, this would extend our exploration license agreements until March 2016. 

 
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

New 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 natural gas wells in which we own an overriding royalty interest. 

(3) As of December 31, 2012, this includes 1 gross oil well and 12 gross natural gas wells in which we own an overriding royalty 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 development wells in Canada in the past three years. 

(2) 2012 dry wells include 5 gross wells that were use for science in the Ozark Highlands Unit that were not intended to produce. 

(3) 2010 dry wells include 2 gross wells (1.6 net wells) in the 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 Price 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 and 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 differences 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 industry. Our properties are subject to customary 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 current 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 properties, we endeavor to perform a title investigation that is 

thorough but less vigorous than that we endeavor to conduct prior 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 perform curative work with respect to significant defects before 

proceeding with operations. We believe that we have performed 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 environment. 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. Management believes any future remediation or other compliance 

related costs will not have a material effect on our financial 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 “Sixth 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 plaintiff’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 fiduciary 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 for the misappropriation of trade secrets and 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 purposes 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 the judge and it is within the judge’s discretion to award none, 

some or all the amount of profit to the plaintiff. On December 31, 2010, the plaintiff filed 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 profits from 143 wells as well as future drilling and sales of 

properties in the prospect areas. A hearing 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, 2011, SEPCO received by mail a letter dated 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 the 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 disgorgement. The judge instructed that SEPCO calculate 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 million 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 bond in the amount of $14.1 million, which stays execution 

on 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. 

 
43 

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 arguments are expected to occur 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 appellate 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 events, 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 became 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 deadlines 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 served 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 involving 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 properly accounted for and paid. The Company believes it has fully 

complied with all requests related to the federal subpoena and 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 and to cooperate with any related investigation. No assurance 

can be made as to the time or resources that will need to be devoted 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 proceedings 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 unfavorable 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 items 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 Health 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 229.106) is included in Exhibit 95.1 to this Form 10-K. 
44 

PART II 

ITEM 5. MARKET FOR REGISTRANT’S COMMON 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 market 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. The 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 94 100 

 
46 

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth a summary of selected historical financial information for each of the years in the fiveyear period ended December 31, 2012. This information and the notes thereto are derived from our consolidated financial 

statements. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” 

and “Financial Statements and Supplementary Data.” 

 

 2012 2011 2010 2009 2008 

 (in thousands except share, per share, 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

Net income (loss) (707,064) 637,769 603,833 (35,792) 568,533

Less: net income (loss) attributable to 

noncontrolling interest – – (285) (142) 587

Net income (loss) attributable 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%

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

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

Net cash provided by (used in) financing 

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

 

Common Stock Statistics 

Earnings per share: 

Net income (loss) attributable to Southwestern 

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

Net income (loss) attributable 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

Number of stockholders of record at year-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 recalculated for 2008 and now include 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 administrative 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 million for 2011, $14.4 million for 2010, $12.2 million for 

2009 and $36.2 million for 2008 related to the change 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 uncertainties. Our actual results could 

differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in 

the “Cautionary Statement About Forward-Looking Statements” below, 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 Fayetteville Shale play. We are also actively engaged in exploration 

and production activities in Pennsylvania, where we are targeting the unconventional gas reservoir known as the Marcellus 

Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma 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 and 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 asset 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 revenues will depend primarily on natural gas prices and our 

ability to increase our natural gas production. We expect our 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 factor in the capital investments we make in order to develop our 

properties and increase our production. In recent years, there has been a significant decline in natural gas prices as 

evidenced by New York Mercantile Exchange, or 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 April 2012. Natural gas prices fluctuate due to a variety of factors we 

cannot control or predict. These factors, which include increased 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 production 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 $1.73 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 natural gas prices during 2012. Our cash flow from operating 

activities decreased 5% to $1,653.9 million in 2012 due to a decrease in net income adjusted for non-cash expenses which 

was partially offset by changes in working capital accounts, and increased 6% to $1,739.8 million in 2011 due to an 

increase in net income adjusted for non-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 increase 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 our 
49 

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-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 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 opportunity to exploit and develop our position in the Fayetteville 

Shale play and Marcellus Shale play, maximize efficiency through 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 fluctuate materially from their current levels we will adjust our 

capital investment plans accordingly. 
50 

RESULTS OF OPERATIONS 

The following discussion of our results of operations for our segments is presented before intersegment eliminations. 

We evaluate our segments as if they were stand-alone operations and accordingly discuss 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 and 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 

Natural 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 volumes in 2011 increased revenues by $445.0 million while lower 

realized prices for our natural gas production decreased revenue 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 are 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 fluctuations. 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 increase 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. Although we expect production volumes in 2013 to increase, we 
51 

cannot guarantee our success in discovering, developing and 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 gas 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 natural 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 decrease in the average price realized 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 extent the decreased effect of our natural 

gas price hedging activities, which had a greater positive impact on our average realized natural gas price in 2010. 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 ensure certain desired levels of cash flow and to minimize the impact of price 

fluctuations, including fluctuations in locational market differentials. 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 price we realized by $1.10 per Mcf in 2012, compared to 

an increase of $0.63 per Mcf in 2011 and 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 basis 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 hedges 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 transportation charges and fuel charges also 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 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. 
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 Shale operations. Lease operating expenses per unit of production 

increased in 2011 compared to 2010 primarily due to increased gathering, compression and water disposal costs associated 

with our Fayetteville Shale operations. We expect our per unit 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 information system costs associated 

with the expansion of our E&P operations. These increases accounted for $8.9 million, or 86%, of the 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 capital invested, and lease operating expenses and general and 

administrative expenses per unit of production, while another 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 changes 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 average 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 associated 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 variability of each of the factors discussed above, as well as other 

factors, including but not limited to the uncertainty of the amount of future reserves attributed to our Fayetteville Shale and

Marcellus Shale plays. 

Unevaluated costs excluded from amortization 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 properties in Canada. The increase in unevaluated costs since December 31, 2011 

primarily resulted from a $90.7 million increase in our drilling activity in our wells in progress, offset slightly by a $5.3 

million decrease in undeveloped leasehold acreage and seismic costs. See Note 4 to the consolidated financial statements 

for additional information regarding our unevaluated costs excluded from amortization. 

The timing and amount of production and reserve additions could 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 decrease in the prices received for volumes marketed, which was partially offset by 

an increase in volumes marketed. Revenues from our marketing activities were up 15% to $2,451.3 million for 2011 

compared to 2010. The increase 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 average 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 gas 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 Services 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 increased 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 operating 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 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 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 marketed in 2012 and a 23% increase in volumes marketed 

in 2011, as compared to prior years, resulting from marketing 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 consolidated financial statements for additional information. 

Interest Expense 

Interest expense, net of capitalization, was $35.7 million in 2012, an increase of $11.6 million compared to 2011, 

primarily due to our increased borrowing level, 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 property 
54 

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 capitalized 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 rate 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 statutory 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 revolving 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 portion of our planned capital investments (discussed below under 

“Capital Investments”), that are expected to exceed the net cash generated by our operations. 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 facility will be adequate to meet our capital and operating 

requirements for 2013. The credit status of the financial institutions participating in our revolving credit facility could 

adversely impact our ability to borrow funds under the revolving 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 accounts. 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. For 2012, requirements for our capital 

investments were funded from our cash generated by operating activities, borrowings under our revolving credit facility, $1 

billion issuance of senior notes and the proceeds from the sale of certain East Texas oil and natural gas properties. Net 

cash from operating activities provided 78% of our cash requirements 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 overall 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. However, 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 unable 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 million in 2011 and an increase of $14.4 million in 2010 related to 

the change in accrued expenditures between years. Our E&P segment 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 $ 2,120,065
56 

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 corporate and other purposes. Of the approximate $1.8 billion, we 

expect to allocate approximately $830 million to our Fayetteville 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 December 31, 2012, compared to $1,343.3 million at December 

31, 2011. 

In February 2011, we amended and restated our unsecured revolving credit facility, 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 calculated 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 impose 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 financial 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 postretirement liabilities. Therefore, under our revolving credit 

facility, our capital structure as of December 31, 2012 would have been 29% debt and 71% equity. We were in compliance 

with all of the covenants of our revolving 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 dependent 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 facility, 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 revolving credit facility and the remaining proceeds were used for 

general corporate purposes. 

As of December 31, 2012, our capital structure consisted of 35% debt and 65% equity compared to 25% debt and 75% 

equity at December 31, 2011. Our debt percentage of total capital as of December 31, 2012 increased 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 comprehensive 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 based 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 arrangements 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 unconsolidated 
57 

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 Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Significant 

contractual obligations as of December 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 demand transportation charges on various pipelines, 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 operating leases expiring through 

2020. Additionally, this includes $38.8 million for leases of 14 drilling rigs and related equipment through 2014 and $37.5 million 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 stimulation 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 operations. 

(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 principal amount of CAD $44.5 million. See Note 8 to the consolidated financial 

statements for additional information regarding our commitments related to our exploration program in Canada. Our other significant contractual 

obligations include approximately $288.0 million for asset retirement obligations primarily relating to oil and natural gas properties, approximately 

$13.8 million for funding of benefit plans, approximately $14.0 million for various information technology support and data subscription agreements, 

approximately $6.8 million for insurance premium financing and approximately $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 $33.5 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 capital of $93.4 million at December 31, 2011. Current assets decreased $169.4 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 deferred 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 that 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 equipment and carried at cost. The carrying 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 POLICIES 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 management to make estimates and judgments that affect the 

reported amounts of assets, liabilities, revenues and expenses and 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 related to the exploration, development 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 pooled costs, net of applicable deferred taxes, 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 excess 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. 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, including the impact of derivatives qualifying as cash flow 

hedges, to calculate the ceiling value of their reserves. 

Using the average quoted price from the first day of each month from the previous 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 natural gas and oil properties exceeded the ceiling amount and resulted in a ceiling test 

impairment as of December 31, 2012. Our net book value of its United States natural gas and oil properties exceeded the 

ceiling by approximately $510.4 million (net of tax) as of December 31, 2012 and resulted in a non-cash ceiling test 

impairment. Cash flow hedges of natural 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 natural 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 natural 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 million (net of tax) at June 30, 2012 and resulted in a non-cash ceiling test impairment. 

Cash flow hedges of natural gas production 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 properties in Canada 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, a ceiling test 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 under 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 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 reserve estimates are also separately reviewed by our accounting 

staff. Following these reviews and the audit, 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 production history and pressure data over time is available for 

the majority of our proved developed properties. 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 uncertainties inherent in the reserve estimates are compounded by applying additional 

estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. 

We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent 

in estimating quantities of natural gas and oil reserves and projecting future rates of production and timing of development 

expenditures as many factors are beyond our control. We refer 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 approximately 93% of present worth of the company’s total proved reserves. NSAI’s 

audit process consists of sorting all fields by descending present value order and selecting the fields from highest value to 

descending value until the selected fields account for more than 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 the reasonableness of our reserve estimates for the year-ended 

December 31, 2012, stating that our estimated proved oil and natural gas reserves 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 reported. Our reserve base is nearly 100% natural gas, therefore 

changes in oil prices used do not have as significant an impact 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 the average 2012 natural gas price used to price our reserves 

would have resulted in an approximate $1,453.5 million decline in our standardized measure and an approximate decrease 

of 1,447 Bcfe of our reported reserves. The unit of production rate for amortization is adjusted quarterly based on changes 

in reserve estimates, capitalized costs 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 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. 

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 provided by our counterparties in 

conjunction with assumptions evaluated internally using established 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 properly 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 option positions and estimated 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 $33.5 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 Requirements in U.S. GAAP and IFRS (“Update 2011-04”). Update 2011-04 expands 

existing fair value disclosure requirements, particularly for Level 3 inputs, including: quantitative disclosure of the 

unobservable inputs and assumptions used in the measurement; description of the valuation processes in place and 

sensitivity of the fair value to changes in unobservable inputs and interrelationships between those inputs; the level of 

items (in the fair value hierarchy) that are not measured at fair value in the balance sheet but whose fair value must be 

disclosed; and the use of a nonfinancial asset if it differs 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 implementation 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 financial statements where the components 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 impact. Update 2011-05 is effective 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 Comprehensive 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 Amendments 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 significant reclassifications out of accumulated other 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 offsetting. 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 clarifies that the scope of the disclosures under 

U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing 

and securities lending transactions that are offset 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 periods presented. The implementation of the disclosure 
62 

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 Securities 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 objectives 

for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forwardlooking statements are based on reasonable 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 statements include the items identified in the preceding paragraph, information 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,” “projection,” “goal,” “plan,” “forecast,” “target” 

or similar expressions. 

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, 

uncertainties and other factors that may affect 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, risks, uncertainties and factors that could cause our actual 

results to differ materially from those indicated in any forward-looking statement include, but are not limited to: 

 the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis 

differentials); 

 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 and over the counter derivatives; 

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

including pressure pumping equipment and crews; 

 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 regulations 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 result of non-performance by our counterparties; and 

 any other factors listed in the reports we have filed and may file with the Securities 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 proved 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 assumptions required by the SEC relating to natural gas and oil 

prices, drilling and operating expenses, capital investments, taxes 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, revenues, 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 materially 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 estimated proved reserves were proved undeveloped and 1% 

were proved developed non-producing. Proved undeveloped 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 based on volumetric calculations rather than the performance data used to estimate producing 

reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling 

operations. Recovery of proved developed non-producing reserves 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 make significant capital investments to develop our reserves. Although we have 

prepared estimates of our natural gas and oil reserves and the costs associated with these 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 value 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 accordance 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% discount factor, which is required by the SEC to be used in 

calculating discounted future net cash flows 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 attributable to us are expressly qualified in their entirety by this cautionary statement. 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Market risks relating to our operations result primarily from 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 interest 
64 

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 management 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 is 

subject to the approval of our Board of Directors. These policies prohibit speculation 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 primarily of trade receivables and 

derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are 

limited due to the large number of our customers and their dispersion across geographic areas. No single customer 

accounted for greater than 10% of revenues as of December 31, 2012. See “Commodities Risk” below 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 exposures when deemed appropriate. 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 agreements and options to hedge sales of our production and to 

hedge activity in our Midstream Services segment against the inherent 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 variable price) for a notional quantity in exchange for receiving a 

variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties 

agree 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 offset 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 qualitative assessments of these counterparties based on their 

credit ratings and credit default swap rates 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 fair 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 Fixed 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 swaps 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 unrealized 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 ineffectiveness 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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 Page

Management’s Report on Internal Control Over Financial Reporting 67

Report of Independent Registered Public Accounting Firm 68

Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010 69

Consolidated Statements of Comprehensive Income (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 Cash Flows for the years ended December 31, 2012, 2011 and 2010 72

Consolidated Statements of Equity for the fiscal years ended December 31, 2012, 2011 and 2010 73

Notes to Consolidated Financial Statements, December 31, 2012, 2011 and 2010 74
67 

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 regarding the reliability of financial reporting and the preparation of 

financial statements for external purposes in accordance with generally accepted accounting 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 reflect the transactions and dispositions of the assets of the Company; (b) provide 

reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance 

with GAAP, and that receipts and expenditures of the Company are being made only in accordance 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 Company’s assets that could have a material effect on the 

consolidated financial statements. Because of its inherent limitations, internal control over financial reporting may not 

prevent or detect misstatements. Also, projections of any evaluation 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 Securities 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 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. 

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 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. This control deficiency 

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 Consolidated 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 internal control over financial reporting, our management, 

including our Chief Executive Officer and our Chief Financial 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 control over financial reporting as of December 31, 2012 has been audited by 

PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that follows. 
68 

Report of Independent Registered Public Accounting Firm 

To the Board of Directors and Stockholders of Southwestern Energy Company 

In our opinion, the accompanying consolidated financial statements listed in the accompanying index present fairly, in 

all material respects, the financial position of Southwestern Energy Company and its subsidiaries at December 31, 2012 

and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 

31, 2012 in conformity with accounting principles generally accepted in the United 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 established 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 deficiency, or a combination of deficiencies, 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 Internal Control over Financial Reporting. We considered this 

material weakness in determining the nature, timing, and extent 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 effective internal control over financial reporting and for its 

assessment of the effectiveness of internal control over financial reporting included in management's report referred to 

above. Our responsibility is to express opinions on these financial statements and on the Company's internal control over 

financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public 

Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to 

obtain reasonable assurance about whether the financial statements are free of material misstatement 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 significant 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 that 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 circumstances. We believe that our audits 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 maintenance 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 with authorizations of management and 

directors of the company; and (iii) provide reasonable assurance regarding prevention 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 financial reporting may not prevent or detect misstatements. 

Also, projections of any evaluation 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 or procedures may 

deteriorate. 

/s/ PRICEWATERHOUSECOOPERS LLP

PricewaterhouseCoopers LLP 

Houston, Texas 

February 20, 2013 
69 

 

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

Net 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) 

 

Net 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 prior 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 attributable to the noncontrolling interest – – (285)

Comprehensive income (loss) attributable to Southwestern Energy $ (965,688) $ 962,222 $ 603,817

(1) Net of ($249.4), ($126.6), and ($118.9) million in taxes for the years ended December 31, 2012, 2011 and 2010, respectively. 

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

(3) Net of $85.1, $338.4, and $119.5 million in taxes for the years ended December 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 properties, 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; authorized 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 STATEMENTS 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 investing activities (1,906,677) (2,024,790) (1,725,631)

 

Cash Flows From Financing Activities 

Payments on current portion 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 Noncontrolling 

 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 oil exploration, development and production. The Company 

engages in natural gas and oil exploration and production, natural gas gathering and natural gas marketing through its 

subsidiaries. Southwestern’s exploration, development and production (“E&P”) activities are principally focused within the 

United States on development of an unconventional natural gas 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 (Midstream 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 financial statements in conformity with GAAP requires 

management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of 

contingent assets and liabilities, if any, at the date of the 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 were not material to the Company’s consolidated financial statements. 

Principles of Consolidation

The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries. All 

significant 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 when 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 excess 

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 estimated sales prices of the anticipated future settlements of the 

imbalances. As of December 31, 2012, the Company had 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, pursuant 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 facility and generally sells natural gas from its storage 

facility during the winter gas withdrawal season. Revenue is recognized on natural gas storage sales when the natural gas is 

sold to a purchaser at a fixed or determinable price, delivery 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 related 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 market mutual funds that are readily 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 accompanying consolidated balance 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 Company 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 equipment 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 natural 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, 2012 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 cost or market and are accounted for by a moving weighted 

average cost method that is applied within specific classes of inventory items. Purchases of inventory are recorded at cost 

and inventory is relieved at the weighted average cost 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 accounting for costs related to the 

exploration, development 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-ofproduction method. These capitalized costs, less accumulated amortization and related 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 excess 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 hedges, to calculate the ceiling value of their reserves. 

Using the average quoted price from the first day of each month from the previous 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 properties exceeded the ceiling amount and resulted in a 
76 

ceiling test impairment as of December 31, 2012. The Company’s net book value of its United States natural gas and oil 

properties exceeded the ceiling by approximately $510.4 million (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 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 $4.12 per MMBtu for Henry Hub 

natural gas and $92.71 per barrel for West Texas Intermediate oil, and at December 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 capitalized 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 ceiling test impairment in the second quarter of 2012. 

All of our costs directly associated with the acquisition 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 when 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 asset. The asset retirement obligation is recorded 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 accounting for income taxes. Under this method, deferred tax 

assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the 

financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities 

are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The 

effect of a change in tax rates on deferred 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 allowance 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 tax 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 benefit that has a greater than 50% 

likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect 

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 the changes in the cash flows of the hedged 

item. In contrast, gains and losses from the ineffective portion of swaps and option contacts as well as basis swap and call 

option contracts that do not qualify for hedge accounting treatment are recognized currently 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 earnings 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 restricted shares of common stock. 

As we recognized a net loss for the year ended December 31, 2012, the unvested stock options were not recognized in 

diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. 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 calculation 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 included in the calculation of diluted shares. 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 December 31, 2012, the unvested share-based payments were not 

recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. The calculation of 

diluted shares excluded 602,429 shares of restricted because they would have had an antidilutive 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 because 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 compensation 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 related to the acquisition, exploration and development activities of 

the Company’s natural gas and oil properties or directly related to the construction 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 are presented as treasury stock and carried at cost. As of 

December 31, 2012, 64,715 shares were accounted for as treasury stock, compared to 98,889 shares 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 functional 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 Requirements in U.S. GAAP and IFRS (“Update 2011-04”). Update 2011-04 expands 

existing fair value disclosure requirements, particularly for Level 3 inputs, including: quantitative disclosure of the 

unobservable inputs and assumptions used in the measurement; description of the valuation processes in place and 

sensitivity of the fair value to changes in unobservable inputs and interrelationships between those inputs; the level of 

items (in the fair value hierarchy) that are not measured at fair value in the balance sheet but whose fair value must be 

disclosed; and the use of a nonfinancial asset if it differs 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 implementation 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 financial statements where the components 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 impact. Update 2011-05 is effective 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 Comprehensive 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 Amendments 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 significant reclassifications out of accumulated other 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 offsetting. 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 clarifies that the scope of the disclosures under 

U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing 

and securities lending transactions that are offset 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 periods 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 leases, 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 leases, 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 included 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 amortization 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 

Net 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, respectively.
80 

The table below sets forth the composition 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 Shale play, approximately $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 Ventures, 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 drilling 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 and Oil Exploration 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 amortization per Mcfe $ 1.31 $ 1.30 $ 1.34 

(1) Includes $3.6 million, $0.2 million and $2.5 million, in 2012, 2011 and 2010, respectively, related to our exploration program in Canada. 

(2) Includes $2.5 million, $18.4 million and $8.2 million in 2012, 2011 and 2010, respectively, 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. These internal costs were directly related to acquisition, 

exploration and development activities and are included as part 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 natural 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 and 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 are 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 Company’s estimates are expected to change, and 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 previous 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 taxes 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 estimated timing of cash flows (1,326,389) (3,689,838) (3,610,585)

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

Under the standardized measure, future cash inflows were estimated 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 standardized 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)

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

Extensions, discoveries, and other additions, 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 

Net 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 $ 3,013,750 

 
83 

(5) DERIVATIVES AND RISK MANAGEMENT 

The Company is exposed to volatility in market prices and basis 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 December 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 contract and pays a floating market price to the 

counterparty. 

 

Floating price swaps The Company receives a floating market price from 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, the Company receives the 

fixed price and pays the market price. If the market price is between the call and the put strike 

price, no payments are due from either party. 

Basis swaps Arrangements that guarantee a price differential for natural gas from a specified delivery point. 

The Company receives a payment from 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 balance 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 hedge 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 Company 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 financial 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 the 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 designated 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 designated 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 gains and losses from the derivative hedging 

instrument recognized in earnings immediately. 
85 

As of December 31, 2012, the Company had cash flow hedges 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 million net of a deferred income tax liability of $112.9 million. The amount recorded in 

accumulated other comprehensive income will be relieved over time and recognized in the statement of operations as the 

physical transactions being hedged 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 during the next 12 months. Gains or losses from derivative 

instruments designated as cash flow hedges are reflected as adjustments to natural gas sales in the consolidated statements 

of operations. Natural gas sales included a realized gain from 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 comprehensive income may occur in the future as a result of the 

Company’s derivative activities. 

The following tables summarize the before tax effect of all cash flow hedges 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 Accumulated (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 earnings immediately. As of December 31, 2012, the Company had no fair value hedges, and no 
86 

material fair value hedges at December 31, 2011. 

Other Derivative Contracts

Although the Company’s basis swaps meet the objective of managing commodity price exposure, these trades are 

typically not entered into concurrent with the Company’s derivative instruments that qualify as cash flow hedges and 

therefore do not generally qualify 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 qualify as cash flow hedges are recorded on the balance sheet 

at their fair values under hedging assets, other assets, other current liabilities, and other long-term liabilities, as applicable 

and all realized and unrealized gains and losses related to these contracts are recognized immediately 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 Company had call options 

on natural gas production that did not qualify for hedge accounting treatment of 18.3 Bcf for 2015. 

The following tables summarizes the before tax effect of basis swaps that did 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 options 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 Company’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 measurement 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 instruments, net $ 287,878 $ 287,878 $ 704,830 $ 704,830 

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. 

As presented in the tables below, this hierarchy 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 value measurements include fixed-price and floating-price swaps 

and are estimated using internal discounted cash flow calculations using the NYMEX futures index. The Company’s Level 

3 fair value measurements include costless-collars, basis swaps and call options. The Company’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 Company’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 the volatility input, which is the significant 

unobservable input for Level 3 fair value 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 Unobservable 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 Unobservable 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, reflect 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 the years ended December 31, 2012 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) $ 5,085 
89 

(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 credit 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 issued $1.0 billion of 4.10% Senior Notes due 2022 in a private placement. The 4.10% 

Senior Notes are redeemable at the Company’s election, in whole or in part, at any 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 scheduled payments of principal and interest on the notes to be 

redeemed (not including any portion of such payments of interest 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 either of such cases, accrued and unpaid 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 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 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 indentures governing the 4.10% Senior Notes and the Company’s 

other senior notes contain covenants that, among other things, restrict 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 assets. In December 2012, the 

Company completed its offer to exchange up to $1.0 billion aggregate principal amount of its 4.10% Senior Notes due 

2022 (the “Exchange Notes”, which 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 subject to any transfer restrictions. The 
90 

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 covenants that, among other things, 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 Company’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 occurred 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 guarantor; (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 facility, 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 any 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 are 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 Company 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 transportation 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 aggregate annual payment under the leases is approximately $19.4 million. The lease 

payments for the drilling rigs and 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 to third-party working interest owners for 

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, 2018. The Company’s current 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 to 

third-party working interest owners for their share of fracture stage charges. 

The Company leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating 

leases expiring through 2020. As of December 31, 2012, future minimum payments under these non-cancelable leases 

accounted for as operating leases are approximately $75.5 million in 2013, $66.0 million in 2014, $41.4 million 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 and 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, $10.5 
91 

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 Marcellus 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 and expansions of the system are expected to be 

in-service by the second quarter of 2013 and late 2013. In June 2011, SES entered into separate 15 year agreements 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 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 receipt locations for deliveries into the Bluestone 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 Susquehanna 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 precedent agreement for an expansion 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 application 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 transportation capacity to various delivery points on TGP’s system. SES has agreed 

to enter a ten year firm transportation agreement with a total 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 connecting to the Iroquois Gas Transmission 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 second 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 obligations for demand and similar charges under the firm 

transportation agreements and gathering 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 Brunswick 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 principal amount of $44.5 million Canadian 

dollars. The promissory notes secure the Company's capital expenditure 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 program in 2010 and, as of December 31, 2012 had invested $25.8 million in New 

Brunswick towards the Company’s commitment. 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. No liability has been 

recognized in connection with the promissory notes due to the Company’s investments 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 nature 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 position 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 “Sixth 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 plaintiff’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 fiduciary 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 for the misappropriation of trade secrets and 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 purposes 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 the judge and it is within the judge’s discretion to award none, 

some or all the amount of profit to the plaintiff. On December 31, 2010, the plaintiff filed 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 profits from 143 wells as well as future drilling and sales of 

properties in the prospect areas. A hearing 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, 2011, SEPCO received by mail a letter dated 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 the 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 disgorgement. The judge instructed that SEPCO calculate 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 million 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 bond in the amount of $14.1 million, which stays execution 

on 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 arguments are expected to occur 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 appellate process, the Company currently estimates, based on the 
93 

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 events, 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 became 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 deadlines 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 served 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 involving 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 properly accounted for and paid. The Company believes it has fully 

complied with all requests related to the federal subpoena and 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 and to cooperate with any related investigation. No assurance 

can be made as to the time or resources that will need to be devoted 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 proceedings 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 unfavorable 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 items 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 connection 

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 statutory 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

Nondeductible 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 and 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

Net 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 income tax liability of $106.1 million. The net deferred tax liability 
95 

at December 31, 2011 was comprised of net 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 statutory 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 reflected 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 benefits are not reflected in our net operating losses in deferred tax 

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 has 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 operating loss carryforward related to its Canadian 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 utilize the existing deferred tax asset associated with the Canadian 

net operating loss. Based on this assessment, the Company did not record a valuation 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 deferred tax asset considered realizable could be adjusted if 

estimates of future taxable income during the carryforward period are increased. 

(10) ASSET RETIREMENT OBLIGATIONS 

The following table summarizes 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 the asset retirement obligation by approximately $39 million. 

Because the amounts involved were not material to the Company’s financial statements 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 combination of declining treasury rates and the Company’s upgrade by Moody’s to Baa3 

in February 2012, are contributing factors to the increased asset retirement 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 development activities of the Company’s natural gas and oil properties 
96 

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 service. Effective January 1, 1998, the Company amended its pension plan to 

become a “cash balance” plan on a prospective 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 health 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 other postretirement plans by recognizing the funded status of 

each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a 

plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, 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 December 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 comprehensive income related to the pension plans was a loss of $8.4 million ($5.0 
97 

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 million after tax) for the year ended December 31, 2011. Included in accumulated other comprehensive 

income as of December 31, 2012 and 2011 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) 

 

Net actuarial loss arising during the year $ (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 benefit 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 and 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 pension 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 future 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 beneficiaries. The Retirement Committee of the Company’s Board of Directors (“Retirement 

Committee”) administers the Company’s pension plan assets. The Retirement 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 the 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 whenever 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 hierarchy, 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 appreciation growth opportunities. 

(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income. 

(3) An institutional fund that seeks 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 outside of the United States, primarily in developed markets. 

(6) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets. 

(7) An institutional fund that seeks to replicate the performance of the Barclays Capital Long-Term Corporate Bond Index before fees through a sampling 

process. 

Utilizing GAAP’s fair value hierarchy, 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 appreciation growth opportunities. 

(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income. 

(3) An institutional fund that seeks 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 outside of the United States, primarily in developed markets. 

(6) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets. 

(7) An institutional fund that seeks to replicate the performance of the Barclays Capital Long-Term Corporate 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 value measurement as Level 1. The Company’s 

Level 2 pension plan assets represent investments in institutional funds. These equity securities can be redeemed on 

demand but are not actively traded. The fair values of these Level 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-BASED 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 subsidiaries. The 2004 Plan replaced 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 16,800,000 shares. The types of 

incentives that may be awarded are comprehensive and are intended to enable the Company’s board of directors to 

structure the most appropriate incentives 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 directors that in the aggregate did not exceed 1,250,000 

shares of common stock. As initially adopted, the 2002 Plan provided for grants of options, stock appreciation rights, 
101 

shares of phantom stock and shares of restricted stock that in the aggregate did not exceed 300,000 shares to employees 

who are not officers or directors of the Company under provisions 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 restricted stock is granted. 

The Company measures the cost of employee services received 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 value 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 stock 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 granted to participants who have reached retirement age or will reach retirement age 

during the vesting period. Restricted stock and stock options granted to participants on or after December 8, 2005 

immediately vest upon death, disability or retirement (subject to a minimum of five years of service). 

Stock Options

The Company recorded the following compensation costs related to stock options 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 the stock-based payments granted. The risk free interest rate is

based on the U.S. Treasury yield curve 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 years 
102 

The following tables summarize stock option activity for the years 2012, 2011 and 2010 and provide information for 

options outstanding at December 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 Aggregate 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 following compensation costs related to restricted stock grants for the years ended 

December 31, 2012, 2011 and 2010: 

 

2012 2011 2010 

(in thousands) 

Stock-based compensation cost related to restricted stock grants 

– general and administrative expense $ 6,368 $ 5,591 $ 5,114

Stock-based compensation cost related 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 deferred tax liabilities of $2.1 million for 2011 and $1.4 million for 2010. As of 

December 31, 2012, there was $32.0 million of total unrecognized compensation cost 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 December 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 associated 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 reconciling the operating income amount shown below to consolidated income before 

income taxes, is the sum of operating income, interest expense and other income (loss), net. The “Other” column includes 

items not related to the Company’s reportable segments including real estate and corporate items. 

 

 Exploration 

 and Midstream 

 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 amortization 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 7,902,897
104 

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 amortization 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 ceiling test 

impairment of our natural gas and oil properties. 

(2) Interest income, interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts 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 natural gas and oil property 

acquisition, exploration and development activities. 

(4) Capital investments include a decrease of $36.9 million for 2012, an increase of $4.3 million for 2011 and an increase of $14.4 million for 2010 

related to the change in accrued 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 Company’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 allocated to the segments. For 2012 and 2011, capital investments 

within the E&P segment include $11.6 million and $18.7 million, respectively, related to the Company’s activities in 

Canada. As of December 31, 2012, E&P assets include $44.4 million and at December 31, 2011, assets 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)

Net income (loss) 107,704 (405,132) (54,053) (355,583)

Earnings (loss) per share - Basic 0.31 (1.16) (0.16) (1.02)

Earnings (loss) per share - Diluted 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 

Net 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 guarantors 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 subordinated debt of the subsidiary guarantors; (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 subordinated 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 occurred 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 guarantor; (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 information would not provide any additional 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 amortization – 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)

Net 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

Net income (loss) 637,769 507,914 129,855 (637,769) 637,769

Comprehensive income (loss) $ 962,222 $ 836,291 $ 129,294 $ (965,585) $ 962,222

 

 
107 

 

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

Net income (loss) 604,118 509,166 94,667 (604,118) 603,833

Less: Net loss attributable to noncontrolling 

interest – (285) – – (285)

Net 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) $ 603,817

 
108 

 

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 depreciation, 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 subsidiaries (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) $ 6,737,527

 
109 

 

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 depreciation, 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 contingencies 

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) $ 7,902,897 

 
110 

 

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS 

 

 Parent Guarantors Non-Guarantors Eliminations Consolidated 

 (in thousands) 

Year ended December 31, 2012: 

Net 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 property 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 

Net 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)

Net 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: 

Net 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 property 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

Net 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

Net 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: 

Net 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)

Net 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)

Net 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 $ – $ 16,055
111 

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 Financial Officer, of the effectiveness of our disclosure 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 information 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 reasonable 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 overstatement 

of our full cost ceiling test impairment of natural gas and oil properties, our Chief Executive Officer and Chief Financial 

Officer, concluded that our disclosure controls and procedures were not effective as of December 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 procedures, 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 (the “Bylaws”) to reduce the number of years 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 “Amended 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 and 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. Mueller served first as the Senior Vice President and General 

Manager Onshore and later as the Executive Vice President and Chief Operating 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 managerial roles at Tenneco Oil Company, Fina Oil Company, 

American Exploration Company, Belco Oil & Gas Company and The Houston Exploration Company. Mr. Mueller is the 

president of Southwestern Energy’s subsidiaries, Southwestern 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, SWN 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 President of Southwestern Energy’s subsidiaries, 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 Energy Services Company. Prior to joining the Company, he was Senior Vice 

President, Americas of BG Group plc with responsibility for 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 Southwestern Energy’s subsidiaries and a director 

of Southwestern Energy’s subsidiaries, SEECO, Inc., Southwestern Energy Production Company, DeSoto Drilling Inc., 

Southwestern Midstream Services Company, Southwestern Energy Services Company, A.W. Realty Company, Certified 

Title Company and SWN Resources Canada, Inc. Prior to joining 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 2012. 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 PricewaterhouseCoopers 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 Energy Company. Mr. Owen holds 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 President, 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, and 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 between any of our executive officers or between any of them and 

our directors. 

The definitive Proxy Statement to holders of our common stock 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 Compliance” in the 2013 Proxy Statement 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 Executive 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 compensation, 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 incorporated 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 Nominees,” 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 information 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 pre-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 principal accountant and the audit committee’s pre-approval policies 

and procedures and other required information. 

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1) The consolidated financial statements of Southwestern Energy and its subsidiaries and the report of independent 

registered public accounting firm are included 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 Board

Harold M. Korell 

/s/ STEVEN L. MUELLER Director, President and Chief Executive Officer

Steven L. Mueller

/s/ R. CRAIG OWEN Senior Vice President and Chief Financial Officer

R. Craig Owen 

/s/ JOSH C. ANDERS Vice President, Controller and Chief Accounting Officer

Josh C. Anders 

/s/ LEWIS E. EPLEY, JR Director

Lewis E. Epley, Jr

/s/ JOHN D. GASS Director

John D. Gass 

/s/ ROBERT L. HOWARD Director

Robert L. Howard

/s/ CATHERINE A. KEHR Director

Catherine A. Kehr 

/s/ GREG D. KERLEY Director

Greg D. Kerley 

/s/ VELLO A. KUUSKRAA Director

Vello A. Kuuskraa 

/s/ KENNETH R. MOURTON Director

Kenneth R. Mourton 

/s/ ELLIOTT PEW Director

Elliott Pew 

/s/ CHARLES E. SCHARLAU Director

Charles E. Scharlau 

/s/ ALAN H. STEVENS Director

Alan H. Stevens 

 
116 

EXHIBIT INDEX

 Exhibit Number Description

 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 Common 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 Company, 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 successor 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). (Incorporated 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 by 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 

New 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 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, 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 Company, 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 Chase 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 Agreement between Southwestern 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 Severance Agreement between Southwestern Energy 

Company and each of the Executive 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 Agreement between Southwestern 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 Supplemental 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 Company Non-Qualified Retirement Plan 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 Employee 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 Performance 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 Agreement for awards granted on or after December 

8, 2005 and through December 8, 2011 (Incorporated by reference to Exhibit 10.4 to the 

Registrant’s Current Report on Form 8-K filed on December 13, 2005) 

 10.20 Form of Non-Qualified Stock Option Agreement 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 between 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 Southwestern 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 pursuant 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 Document
119 

 101.SCH* Interactive Data File Schema Document

 101.CAL* Interactive Data File Calculation Linkbase Document

 101.LAB* Interactive Data File Label Linkbase Document

 101.PRE* Interactive Data File Presentation Linkbase Document

 101.DEF* Interactive Data File Definition Linkbase Document

____________ 

*Filed herewith