10-K

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, 2010
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. Yesx     Noo
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 o    Nox
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. Yesx   Noo
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). Yesx   Noo    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. o
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 x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o     No x
The aggregate market value of the voting stock held by non-affiliates of the registrant was $13,138,958,969 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2010, of $38.64. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.
As of February 22, 2011, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 347,754,343.
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 17, 2011 are incorporated by reference into Part III of this Form 10-K.

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SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 2010

TABLE OF CONTENTS

Page

Business

Glossary of Certain Industry Terms

Risk Factors

Unresolved Staff Comments

Properties

Legal Proceedings

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of

Equity Securities

Stock Performance Graph

Selected Financial Data

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

Results of Operations

Liquidity and Capital Resources

Critical Accounting Policies and Estimates

Cautionary Statement about Forward-Looking Statements

Quantitative and Qualitative Disclosures about Market Risk

Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Controls and Procedures

Other Information

Directors, Executive Officers and Corporate Governance

Executive Compensation

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Certain Relationships and Related Transactions, and Director Independence

Principal Accounting Fees and Services

Exhibits, Financial Statement Schedules

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 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.

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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 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 Texas, Pennsylvania and to a lesser extent Oklahoma.  We 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 gas reserves, and conducts the Fayetteville Shale drilling program and the conventional Arkoma Basin drilling program in the Arkoma Basin. SEPCO conducts development drilling and exploration programs in the Oklahoma portion of the Arkoma Basin as well as in Texas and Pennsylvania.  DeSoto Drilling, Inc., or DDI, a wholly-owned subsidiary of SEPCO, operates drilling rigs in the Fayetteville Shale play as well as our other operating areas.  In addition, in 2010, we commenced an exploration program for natural gas and crude oil under 32 licenses in New Brunswick, Canada and formed SWN Resources Canada, Inc. to conduct those operations.

Midstream Services - We engage in natural gas gathering activities in Arkansas, Texas and Pennsylvania through our gathering subsidiaries, DeSoto Gathering Company, L.L.C., which we refer to as DeSoto Gathering, and Angelina Gathering Company, L.L.C., which we refer to as Angelina Gathering. DeSoto Gathering and Angelina Gathering primarily support our E&P operations and generate revenue from gathering fees associated with the transportation of our and third party gas to market. 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 2010, 81% of our operating income and 86% of our EBITDA were generated from our E&P business, compared to 86% of our operating income and 90% of our EBITDA in 2009, absent our $907.8 million, or $558.3 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties, and 92% of our operating income and 89% of our EBITDA in 2008. In 2010, 19% of our operating income and 14% of our EBITDA were generated from Midstream Services, compared to 14% of our operating income and 10% of our EBITDA in 2009, absent the non-cash ceiling test impairment of our natural gas and oil properties, and 7% of our operating income and 5% of our EBITDA in 2008. In 2008, the remainder of our EBITDA was generated from our Gas Distribution business which was sold effective July 1, 2008.  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.   

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 of the future expected cash flows for each project is determined using a 10% discount rate.  We target creating at least $1.30 of discounted pre-tax 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 Position in the Fayetteville Shale and Our Other Emerging Unconventional Plays.  We seek to maximize the value of our significant acreage position in the Fayetteville Shale play, which we believe will

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continue to provide significant production and reserve growth. At December 31, 2010, we held approximately 915,884 net acres in the Fayetteville Shale play and the area accounted for approximately 88% of our total proved oil and natural gas reserves and approximately 87% of our total oil and natural gas production during 2010.  We intend to further develop our acreage position in the Fayetteville Shale Play and improve our well results through the use of advanced technologies and detailed technical analysis of our properties.  Additionally, we are actively drilling on portions of our 173,009 net acres in the Marcellus Shale and believe our production and reserves from this play will grow substantially.

·

Maximize Efficiency through 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.  In our Fayetteville Shale play, we have achieved significant cost savings by operating a fleet of drilling rigs designed specifically for the play and from our other associated oilfield services including our sand mine that is a source of proppant for our well completions.  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.

·

Enhancing 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, 2010, we have invested approximately $788.5 million in the 1,569 mile gas gathering system built for our Fayetteville Shale play, which was gathering approximately 1.8 Bcf per day at year-end, and have invested approximately $29.0 million in 37 miles of gas gathering lines in other areas in support of our E&P business.  Our gathering system for the Fayetteville Shale play has developed into a strategic asset that not only supports our E&P operations but also will increase our overall returns on a standalone basis.  We are currently considering various strategic alternatives for maximizing and/or recognizing the value of this asset.

·

Grow through New Exploration and Development Activities.  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.” 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.  Our Fayetteville Shale play and our Marcellus Shale play began as New Ventures projects in 2002 and 2007, respectively, and are no longer included within New Ventures.  As of December 31, 2010, we held 3,009,643 net undeveloped acres in connection with our New Ventures prospects, of which 2,518,518 net acres were located in New Brunswick, Canada.

Recent Developments

2011 Planned Capital Investments and Production Guidance.  Our planned capital investment program for 2011 is approximately $1.9 billion, which includes approximately $1.6 billion for our E&P segment, $225 million for our Midstream Services segment and $60 million for corporate and other purposes.  Our 2011 capital program is expected to be primarily funded by our cash flow from operations and borrowings under our $1.5 billion revolving credit facility (see update below).  The planned capital program for 2011 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 2011 natural gas and oil production of approximately 465 to 475 Bcfe, an increase of approximately 15 to 17% over our 2010 production.

Amendment of Revolving Credit Facility.  On February 14, 2011, we amended and restated our revolving credit facility which was scheduled to expire February 2012, and among other things, the maturity date was extended to February 2016 and the borrowing capacity was increased to $1.5 billion from $1.0 billion, with an accordion feature that permits us to increase to $2.0 billion with agreement of existing or new lenders.  We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Financing Requirements” and Note 7 to the consolidated financial statements included in this Form 10-K for additional discussion of our revolving credit facility.

Exploration and Production

Overview

Our operations are primarily focused on the Fayetteville Shale, an unconventional reservoir located in the Arkoma Basin in Arkansas.  In addition to our Arkansas operations, we are also undertaking an active drilling program in 2011 on our acreage in Pennsylvania targeting the Marcellus Shale and we conduct both conventional and unconventional

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operations in the Arkoma Basin and in East Texas targeting various formations.  We continue to actively seek to develop both conventional and unconventional natural gas and oil resource plays with significant exploration and exploitation potential.

Our E&P segment recorded operating income of $829.5 million in 2010. Our E&P segment recorded an operating loss of $157.7 million in 2009 as a result of the recognition of a $907.8 million, or $558.3 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties recorded for the three months ended March 31, 2009 and operating income of $813.5 million in 2008. The increase in operating income in 2010 was primarily due to a 35% increase in our total natural gas and oil production which was partially offset by lower prices realized from the sale of our natural gas production and an increase in operating costs and expenses.  The operating loss in 2009 was primarily due to the recognition of this ceiling test impairment, however, even without the write-down, operating income would have decreased, when compared to 2008 operating income, due to lower prices realized from the sale of our production and an increase in operating costs and expenses which more than offset the higher revenues realized from increased natural gas production.  EBITDA from our E&P segment was $1.4 billion in 2010, compared to $1.2 billion in 2009 and $1.2 billion in 2008. The increase in our EBITDA in 2010 was due to our increased production volumes which was partially offset by lower prices realized from the sale of our natural gas production and increased operating costs and expenses.  Our EBITDA in 2009 was approximately equal to 2008 as the impact of our increased production volumes was offset by decreased prices realized from the sale of our production 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 4,937 Bcfe at year-end 2010, compared to 3,657 Bcfe at year-end 2009 and 2,185 Bcfe at year-end 2008. The overall increase in total estimated proved reserves in the past three years is primarily due to the development of the Fayetteville Shale play in Arkansas.  In 2009, the SEC adopted a number of revisions to its oil and gas reporting disclosure requirements which were effective for the Form 10-K for the year ended December 31, 2009 and among other things require the value of estimated proved natural gas and oil reserves utilizing the average prices in the preceding 12 month period, which is defined, with certain exceptions, as the unweighted arithmetic average of the first-day-of-the-month price for each month within such period.  The average prices utilized to value our estimated proved natural gas and oil reserves at December 31, 2010 were $4.38 per Mcf for natural gas and $75.96 per barrel for oil compared to $3.87 per Mcf for natural gas and $57.65 per barrel for oil at December 31, 2009.  The market prices for natural gas and crude oil used in calculating the value of our estimated proved natural gas and oil reserves for 2008 were single day prices permitted to be used under the SEC’s prior rules, which were $5.71 per Mcf for natural gas and $41.00 per barrel for oil at year-end 2008.

The after-tax PV-10, or standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities, was $3.0 billion at year-end 2010, compared to $1.8 billion at year-end 2009 and $2.1 billion at year-end 2008.  The increase in our after-tax PV-10 value in 2010 was primarily due to the increase in our reserves and a comparative increase in average 2010 prices for natural gas from average 2009 prices, partially offset by higher operating and future development costs.  The decrease in the after-tax PV-10 value in 2009 is primarily due to a comparative decrease in the average 2009 price from the year-end 2008 natural gas price and higher operating and future development costs, which were partially offset by an increase in reserves. Our proved reserves are almost entirely natural gas and as such the after-tax PV-10 measure is highly dependent upon the natural gas price used in the after-tax PV-10 calculation. The reconciling difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2010 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 2010 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pre-tax PV-10, of $4.3 billion, compared to $2.3 billion at year-end 2009 and $3.0 billion at year-end 2008.  

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.

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Approximately 100% of our year-end 2010 estimated proved reserves were natural gas and 55% were classified as proved developed, compared to 100% and 54%, respectively, in 2009 and 100% and 62%, respectively, in 2008.  We operate approximately 95% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index approximated 12.2 years at year-end 2010.  Sales of natural gas production accounted for nearly 99% of total operating revenues for this segment in 2010, 100% in 2009 and 97% in 2008.

The following table provides an overall and by category summary of our oil and natural gas reserves, as of fiscal year-end 2010 based on average fiscal year prices, and our well count, net acreage and PV-10 as of December 31, 2010 and sets forth 2010 annual information related to production and capital investments for each of our operating areas:

2010 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA

		U.S. Exploitation
	Fayetteville	East	Arkoma		New
	Shale Play	Texas	Basin	Appalachia	Ventures	Total
Estimated Proved Reserves:
Natural Gas (Bcf):
Developed (Bcf)	2,213	266	197	11	-	2,687
Undeveloped (Bcf)	2,132	55	29	27	-	2,243
	4,345	321	226	38	-	4,930
Crude Oil (MMBbls):
Developed (MMBbls)	-	1	-	-	-	1
Undeveloped (MMBbls)	-	-	-	-	-	-
	-	1	-	-	-	1
Total Proved Reserves (Bcfe)(1):
Proved Developed (Bcfe)	2,213	273	197	11	-	2,694
Proved Undeveloped (Bcfe)	2,132	55	29	27	-	2,243
	4,345	328	226	38	-	4,937
Percent of Total	88%	7%	4%	1%	-	100%
Percent Proved Developed	51%	83%	87%	29%	-	55%
Percent Proved Undeveloped	49%	17%	13%	71%	-	45%
Production (Bcfe)	350.2	34.3	19.2	1.0	-	404.7
Capital Investments (millions)(2)	$           1,333	$              150	$                13	$              118	$              145	$           1,759
Total Gross Producing Wells	2,120	605	1,185	8	-	3,918
Total Net Producing Wells	1,437	465	572	7	-	2,481
Total Net Acreage	790,898(3)	125,563(4)	433,109(5)	173,009(6)	3,009,643(7)	4,532,222
Net Undeveloped Acreage	367,206(3)	53,228(4)	250,657(5)	169,095(6)	3,009,643(7)	3,849,829
PV-10:
Pre-tax (millions)(8)	$           3,604	$              352	$              261	$                45	$                  -	$           4,262
PV of taxes (millions)(8)	1,056	103	76	13	-	1,248
After-tax (millions)(8)	$           2,548	$              249	$              185	$                32	$                  -	$           3,014
Percent of Total	85%	8%	6%	1%	-	100%
Percent Operated(9)	95%	98%	87%	100%	-	95%

(1)

We have no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. Our proved reserves increased by 1,431.1 Bcfe as a result of our drilling program and net upward revisions of 309.6 Bcfe in 2010.  Of the reserve additions, 698.0 Bcfe were proved developed and 733.2 Bcfe were proved undeveloped.  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 $13 million related to our drilling rig related equipment, sand facility and other equipment.  

(3)

Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 17,502 net acres in 2011, 3,711 net acres in 2012 and 215,194 net acres in 2013.

(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 22,827 net acres in 2011, 6,371 net acres in 2012 and 1,388 net acres in 2013.

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(5)

Includes 123,442 net developed acres and 1,544 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 32,720 net acres in 2011, 29,699 net acres in 2012 and 2,971 net acres in 2013.

(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 2,325 net acres in 2011, 63,117 net acres in 2012 and 43,077 net acres in 2013.

(7)

Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 19,735 net acres in 2011, 22,500 net acres in 2012 and 60 net acres in 2013. With regard to the company’s acreage in New Brunswick, Canada, assuming the options are not extended/exercised by March 2013 then, in such event, 2,518,518 net acres will expire in 2013.

(8)

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.

(9)

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 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 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.

Proved Undeveloped Reserves

As of December 31, 2010, we had 2,243 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 2010, we invested $312.4 million in connection with converting 213.1 Bcfe or 13% of our proved undeveloped reserves as of December 31, 2009 into proved developed reserves and added 733.2 Bcfe of proved undeveloped reserve additions, primarily in the Fayetteville Shale play. Our 2010 proved undeveloped reserve additions are expected to be developed and to begin to generate cash inflows over the next five years.  At December 31, 2009, we had 1,677 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 2009, we invested $221.1 million in connection with converting 120.8 Bcfe or 15% of our proved undeveloped reserves as of December 31, 2008 into proved developed reserves and added 927.5 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 2,243 Bcfe as of December 31, 2010, will require us to invest an additional $3.0 billion 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 affect on us,” “We may have difficulty financing our planned capital investments, which could adversely affect our growth” and “Our future 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.  Our reserve replacement ratio, including revisions, has averaged over 500% for the three year period ended December 31, 2010, primarily driven by increases in the reserves associated with our Fayetteville Shale play.

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

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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.

In 2009, our reserve replacement ratio was 592% with an increase of 1,685.2 Bcfe of proved natural gas and oil reserves as a result of our drilling program and net upward revisions of 92.9 Bcfe.  Of the 2009 reserve additions, 757.6 Bcfe were proved developed and 927.5 Bcfe were proved undeveloped. The upward reserve revisions during 2009 were primarily due to 384.8 Bcf in upward revisions related to the improved performance of wells in our Fayetteville Shale play, partially offset by downward reserve revisions of 251.5 Bcf due to a comparative decrease in the average gas price for 2009 as compared to year-end 2008.  Additionally, we had downward performance revisions of 25.5 Bcfe and 15.1 Bcf in our East Texas and conventional Arkoma Basin operating areas, respectively.

In 2008, our reserve replacement ratio was 523% (from reserve additions of 920.2 Bcfe primarily driven by our drilling program in the Fayetteville Shale play), including net upward revisions of 98.1 Bcfe. Of the 2008 reserve additions, 568.2 Bcfe were proved developed and 352.0 Bcfe were proved undeveloped.  The improved performance of wells in our Fayetteville Shale play resulted in upward performance reserve revisions of 159.7 Bcf during 2008, which were partially offset by downward reserve revisions of 58.7 Bcfe due to a comparative decrease in year-end gas prices and performance revisions in our conventional Arkoma and East Texas operating areas.  Additionally, our reserves decreased by 89.5 Bcfe as a result of our sale of oil and natural gas leases and wells in 2008.

For the period ending December 31, 2010, our three-year average reserve replacement ratio, including revisions, was 505%. Our reserve replacement ratio for 2010, excluding the effect of reserve revisions, was 354%, compared to 561% in 2009 and 473% in 2008. Excluding reserve revisions, our three-year average reserve replacement ratio is 449%.

Since 2005, the substantial majority of our reserve additions have been generated from our drilling program in the Fayetteville Shale play.  We expect our drilling program in the Fayetteville Shale play to continue to 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 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 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 Operations

Fayetteville Shale Play

Our Fayetteville Shale play is currently the 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.  The Barnett Shale found in north Texas is an analogous reservoir.  At December 31, 2010, we held leases for approximately 915,884 net acres in the play area (367,206 net undeveloped acres, 423,692 net developed acres held by Fayetteville Shale production, 123,442 net developed acres held by conventional production and an additional 1,544 net undeveloped acres in the traditional Fairway portion of the Arkoma Basin), compared to approximately 888,695 net acres at year-end 2009 and 875,000 net acres at year-end 2008.  The increase in our acreage during 2010 was primarily due to additional acreage capture related to the integration of new sections.  The increase in our net acreage during 2009 as compared to 2008 was primarily due to additional acreage capture related to the integration of new sections and a small acquisition of producing properties in the play.  

Approximately 4,345 Bcf of our reserves at year-end 2010 were attributable to our Fayetteville Shale play, compared to approximately 3,117 Bcf at year-end 2009 and 1,545 Bcf at year-end 2008.  Gross production from our operated wells in the Fayetteville Shale play increased from approximately 1,225 MMcf per day at the beginning of 2010 to approximately 1,635 MMcf per day by year-end.  Our net production from the Fayetteville Shale play was 350.2 Bcf in 2010, compared to 243.5 Bcf in 2009 and 134.5 Bcf in 2008. In 2011, we estimate our production from the Fayetteville Shale play will be in the range of 410 to 420 Bcf.

Our leases generally require that we drill at least one producing well per governmental drilling unit (640 acres) in order to prevent our leases from terminating upon the expiration date.  At year-end 2010, approximately 54% of our Fayetteville Shale leasehold acreage was held by production, excluding our acreage in the traditional Fairway portion of the Arkoma Basin.  We refer you to the risk factor “If we fail to drill all of the wells that are necessary to hold our

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Fayetteville Shale 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.  Excluding our acreage in the traditional Fairway, our acreage position was obtained at an average cost of approximately $245 per acre with an average royalty interest of 15%, and as of December 31, 2010, the undeveloped portion of our acreage had an average remaining lease term of 2.5 years.  For more information about our acreage and well count, we refer you to “Properties” in Item 2 of Part I of this Form 10-K.

As of December 31, 2010, we had spud a total of 2,445 wells in the play since its commencement in 2004, 2,001 of which were operated by us and 444 of which were outside-operated wells.  Of the wells spud, 658 were in 2010, 570 were in 2009 and 604 were in 2008.  Of the wells spud in 2010, 655 were designated as horizontal wells.  At year-end 2010, 1,820 operated wells had been drilled and completed overall, including 1,730 horizontal wells.  Of the 1,730 horizontal wells, 1,712 wells were fracture stimulated using either slickwater or crosslinked gel stimulation treatments, or a combination thereof.

During 2010, we continued to improve our drilling practices in the Fayetteville Shale play.  Our operated horizontal wells had an average completed well cost of $2.8 million per well, average horizontal lateral length of 4,528 feet and average time to drill to total depth of 11 days from re-entry to re-entry.  This compares to an average completed operated well cost of $2.9 million per well, average horizontal lateral length of 4,100 feet and average time to drill to total depth of 12 days from re-entry to re-entry during 2009.  In 2008, our average completed operated well cost was $3.0 million per well with an average horizontal lateral length of 3,619 feet and average time to drill to total depth of 14 days from re-entry to re-entry.  The operated wells we placed on production during 2010 averaged initial production rates of 3,364 Mcf per day, down 3% from average initial production rates of 3,478 Mcf per day in 2009, but significantly higher than the average of 2,777 Mcf per day in 2008.  In 2010, 220 operated wells (or 40% of total operated wells) placed on production were the first well in a new section, significantly changing the mix of wells, which we believe had the effect of reducing average production rates as compared to 2009 results.  In 2009 and 2008, respectively, there were 142 and 132 operated wells placed on production that were the first well in a new section representing 32% and 40%, respectively of total operated wells placed on production in each year.  During 2010, we placed 72 operated wells on production with initial production rates that exceeded 5.0 MMcf per day, including 17 wells that exceeded 6.0 MMcf per day and the play’s highest rate well, the Harlan 09-10 #1-12H located in Cleburne County, which was placed on production with an initial production rate of approximately 8.7 MMcf per day with a 3,900-foot completed lateral.

Beginning in late 2008 and continuing through 2010, we drilled a significant number of wells to test tighter well spacing. At December 31, 2010, we had placed 645 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less.  Previously, we had stated that, based on the wells drilled to date, we expected a minimum of 10 to 12 wells per section to effectively drain the reserves, which would represent approximately 65-acre spacing.  Early production performance from recent well spacing tests suggests that there are areas of the field that may be economically developed at tighter spacing.  At this time, we believe that approximately 20% of the approximately 600,000 net acres drilled to date can be developed at 30- to 40-acre spacing, approximately 40% can be developed at 65-acre spacing and the remaining 40% requires more testing to determine if development on tighter spacing than 65-acres would be economic.  We will continue our well spacing program in 2011 to better define the areas of the field that are suitable for tighter spacing.

Our total proved net reserves booked in the play at year-end 2010 were 4,345 Bcf from a total of 3,682 locations, of which 2,120 were proved developed producing, 36 were proved developed non-producing and 1,526 were proved undeveloped.  Of the 3,682 locations, 3,610 were horizontal. The average gross proved reserves for the undeveloped wells included in our year-end reserves was approximately 2.4 Bcf per well, up from 2.2 Bcf per well at year-end 2009 and 1.9 Bcf per well at year-end 2008.  Total proved net gas reserves booked in the play in 2009 totaled approximately 3,117 Bcf from a total of 2,675 locations, of which 1,428 were proved developed producing, 97 were proved developed non-producing and 1,150 were proved undeveloped.  Total proved net gas reserves booked in the play in 2008 totaled approximately 1,545 Bcf from a total of 1,508 locations, of which 882 were proved developed producing, 18 were proved developed non-producing and 608 were proved undeveloped.  If the Fayetteville Shale play continues to be successfully developed, we expect a continued significant level of proved undeveloped reserves in the Fayetteville Shale play over the next few years.

In 2010, we invested approximately $1.3 billion in our Fayetteville Shale play, which included approximately $1.2 billion to spud 658 wells, 569 of which we operated.  We increased our reserves in the Fayetteville Shale play by 1,579 Bcf, which included net upward reserve revisions of 273 Bcf due primarily to improved well performance of 267 Bcf and upward price revisions of 6 Bcf.  Included in our total capital investments in the play during 2010 was $48 million for acquisition of properties and $111 million in capitalized costs and other expenses.  At December 31, 2010, 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

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Basin.  In 2009, we invested approximately $1.3 billion in our Fayetteville Shale play, which included $1.1 billion to spud 570 wells, $40 million for acquisition of properties, $22 million for seismic and $106 million in capitalized costs and other expenses.  In 2008, we invested approximately $1.2 billion in our Fayetteville Shale play, which included $1.0 billion to spud 604 wells, $23 million for acquisition of properties, $61 million for 3-D seismic and $83 million in capitalized costs and other expenses.  

In 2011, we plan to invest approximately $1.15 billion in our Fayetteville Shale play, which includes participating in approximately 530 to 540 gross wells, 440 to 450 of which are planned to be operated by us.  

We believe that our Fayetteville Shale acreage continues to have significant development potential.  Our strategy going forward is to increase our production through 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 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 are subject to change” in Item 1A of Part I of this Form 10-K.

U.S. Exploitation

East Texas.  We have been an active operator in East Texas since 2000, when we first began our activities in the area targeting the Cotton Valley sand formation with the purchase of the Overton Field, or Overton, in Smith County, Texas.  We have expanded our activities to include additional opportunities at Overton as well as significant potential drilling targeting the Travis Peak, James Lime, Pettet, Haynesville Shale and Middle Bossier formations.

At December 31, 2010, we had approximately 328 Bcfe of reserves in East Texas, compared to 330 Bcfe at year-end 2009 and 351 Bcfe at year-end 2008.  Our proved reserves have decreased over the past three years primarily due to our annual field production, asset dispositions and downward reserve revisions resulting from comparative decreases in natural gas prices and negative performance revisions, which have more than offset our successful drilling in the James Lime and Haynesville Shale and Middle Bossier formations.  In 2010, we invested approximately $150 million in East Texas and participated in 25 wells, of which 17 were successful and 8 were in progress at year-end, resulting in a 100% success rate and adding new reserves of 85 Bcfe.  This area recorded net upward revisions of approximately 2.7 Bcfe, comprised of upward revisions of approximately 41.6 Bcfe primarily due to a comparative increase in the average 2010 natural gas price from the average 2009 natural gas price, offset by 38.9 Bcfe of negative performance revisions.  Net production from East Texas was 34.3 Bcfe in 2010, compared to 34.9 Bcfe in 2009 and 31.6 Bcfe in 2008.  

Production has remained stable over the past three years primarily due to our successful drilling program in the James Lime formation which, combined with successful drilling in the Haynesville and Middle Bossier Shales in 2010 and 2009, more than offset the natural production decline at Overton and the sale of the Jebel Haynesville assets in June 2010.  In June 2010, we sold the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 20,063 net acres.  We expect the sale together with our planned decrease in capital investments, to decrease net production in 2011.

Our original interest in Overton of approximately 10,800 gross acres was acquired in April 2000 for $6 million. Our wells in Overton produce from four Taylor series sands in the Cotton Valley formation at approximately 12,000 feet.  At December 31, 2010, we held approximately 24,400 gross acres in Overton with an average working interest of 83% and an average net revenue interest of 67%.  Our proved reserves in Overton were 176 Bcfe at year-end 2010, compared to 189 Bcfe at year-end 2009 and 273 Bcfe at year-end 2008.  Net production from Overton was 11.7 Bcfe in 2010, compared to 14.6 Bcfe in 2009 and 19.9 Bcfe in 2008. We expect our production and reserves from Overton to continue to decline due to the planned lack of significant investment in the field over the past several years and the natural production decline in existing wells.

Our Angelina River Trend properties, collectively referred to as Angelina, are concentrated in several separate development areas located primarily in four counties in East Texas targeting the Travis Peak, James Lime, Pettet, Haynesville Shale and Middle Bossier Shale formations. At December 31, 2010, we held approximately 55,000 gross undeveloped acres and 42,000 gross developed acres at Angelina with an average working interest of 65% and an average net revenue interest of 51%.  Our acreage position was obtained at an average cost of approximately $454 per acre and the undeveloped portion of our acreage has an average remaining lease term of 1 year.  Our proved reserves in the Angelina

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area were 149 Bcfe at year-end 2010, compared to 137 Bcfe at year-end 2009 and 74 Bcfe at year-end 2008.  Net production from our Angelina properties was 22.4 Bcfe in 2010, compared to 19.7 Bcfe in 2009 and 11.3 Bcfe in 2008.

In 2010, we invested approximately $70 million to drill 24 wells at Angelina, all of which were successful or in progress at December 31, 2010.  Our 2010 drilling program was primarily focused on developing the James Lime, Haynesville Shale and Middle Bossier Shale formations.  During 2010, we participated in the drilling and completion of 4 Haynesville and Middle Bossier wells which production tested between 12.1 and 22.5 MMcf per day.  Additionally, during 2010, we participated in the drilling of 9 wells which are expected to be completed and put to sales early in 2011.  In 2009, we participated in the drilling and completion of 6 Haynesville and Middle Bossier wells which production tested between 7.2 and 21.0 MMcf per day.

Conventional Arkoma Basin.  We have traditionally operated in a portion of the Arkoma Basin located in western Arkansas that we refer to as the “Fairway.”  In recent years, we have expanded our activity in the Arkoma Basin to the south and east of the traditional Fairway area, primarily in the Ranger Anticline and Midway areas.  We refer to our drilling program targeting stratigraphic Atokan-age objectives in Oklahoma and Arkansas as the “conventional Arkoma” drilling program.  

At December 31, 2010, we had approximately 226 Bcf of reserves that were attributable to our conventional Arkoma properties, representing approximately 5% of our total reserves, compared to 208 Bcf at year-end 2009 and 281 Bcf at year-end 2008.  Our proved reserves have declined over the past three years primarily due to lower capital investments in the area which were not sufficient to offset our annual field production and downward revisions due to comparative decreases in natural gas prices and negative performance revisions.  In 2010, we invested approximately $13 million in our conventional Arkoma drilling program and participated in 9 wells, of which 5 were successful and 3 were in progress at year-end, resulting in an 83% success rate and adding new reserves of 3 Bcf.  This area recorded net upward revisions of approximately 34 Bcf, comprised of upward price revisions of approximately 30 Bcf primarily due to a comparative increase in the average 2010 natural gas price from the average 2009 natural gas price, in addition to an increase of 4 Bcf of positive performance revisions. Net production from our conventional Arkoma properties was 19.2 Bcf in 2010, compared to 22.0 Bcf in 2009 and 24.4 Bcf in 2008.  Production has declined over the past three years due to significantly lower capital investments in the area.

Appalachia.  We began leasing in northeastern Pennsylvania in 2007 in an effort to gain a position in the emerging Marcellus Shale play.  At December 31, 2010, we had approximately 173,009 net acres in Pennsylvania under which we believe the Marcellus Shale is prospective.  Our undeveloped acreage position as of December 31, 2010 had an average remaining lease term of 3 years, an average royalty interest of 13% and was obtained at an average cost of approximately $720 per acre.  

In 2010, we invested approximately $118 million in Pennsylvania and participated in 21 wells, of which 6 were successful and 15 were in progress at year-end, resulting in a 100% success rate and adding new reserves of 38 Bcf.  These 6 wells are all horizontal wells located in our Greenzweig area in Bradford County that production tested between 4 and 8 MMcf per day, resulting in net production from our Pennsylvania properties of 1.0 Bcf in 2010.  

In 2009, we invested approximately $40 million in the Marcellus Shale play in Pennsylvania substantially all of which was for the acquisition of properties.  In 2008, we invested approximately $58 million and drilled our first four wells (three vertical and one horizontal) on our acreage in Bradford and Susquehanna Counties, three of which have been production tested.  

In 2011, we plan to begin the year drilling with one operated rig in Pennsylvania and end the year with two operated rigs.  We plan to invest approximately $265 million in Appalachia, which includes participating in a total of 40 to 45 gross wells, all of which will be operated.  

In 2011, we expect to invest approximately $30 million combined in our East Texas and Conventional Arkoma Basin programs.

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 unconventional plays (including coalbed methane, shale gas and basin-centered gas and unconventional oil) as well as determining 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 

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both inside and outside of the United States.  As of December 31, 2010, we held 3,009,643 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 36,125 and 138,638 net undeveloped acres held at year-end 2009 and 2008, respectively.  At December 31, 2008, 114,738 of the 138,638 net undeveloped acres were in Pennsylvania where we are targeting the Marcellus Shale. The Marcellus Shale acreage was transferred to our U.S. Exploitation group in 2009 and is discussed in more detail in Appalachia above.

In March 2010, we announced that the Department of Natural Resources of the Province of New Brunswick, Canada accepted our bids for exclusive licenses to search and conduct an exploration program covering over 1,018,000 hectares (2,518,518 net acres) in the province in order to test new hydrocarbon basins.  As a result, we are required to make investments of approximately $47 million USD in the province over the next three years. The three-year exploration program represents our first venture outside of the United States.

In 2010, we invested approximately $145 million in our New Ventures program substantially all of which was for the acquisition of properties, compared to approximately $25 million invested in our New Ventures program in 2009 and approximately $73 million in 2008.  Of the amount invested during 2008, approximately $58 million was invested in the Marcellus Shale play in Pennsylvania.  In 2011, we plan to invest approximately $170 million in various unconventional, exploration and New Ventures projects, which includes drilling two operated wells.  

Divestitures

In June 2010, we sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $357.8 million, to Exco Resources, Inc.  The sale included only the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 20,063 net acres. The net production from the Haynesville and Middle Bossier Shale intervals in this acreage was approximately 13.5 MMcf per day and proved net reserves were approximately 55.4 Bcf when the sale was closed in June 2010.  

During 2008, we sold the oil and natural gas leases, wells and equipment that comprised our Permian Basin and onshore Texas Gulf Coast operating assets to various buyers for approximately $240 million in the aggregate.  The sales included 95,700 net acres of leasehold, 69 Bcfe of proved reserves and approximately 16 MMcfe per day of production from the properties as of April 1, 2008.

In 2008, we also sold certain oil and natural gas leases, wells and gathering equipment in our Fayetteville Shale play for approximately $518.3 million.  The sale included 55,631 net acres of leasehold, 20 Bcf of proved reserves and approximately 10.5 MMcf per day of production from the Fayetteville Shale as of March 17, 2008.  

Capital Investments

During 2010, we invested a total of $1.8 billion in our E&P business and participated in drilling 713 wells, 483 of which were successful, 3 were dry (including 2 wells in the Fayetteville Shale play that were plugged and abandoned due to mechanical issues encountered during drilling) and 227 were in progress at year-end.  Of the 227 wells in progress at year-end, 201 were located in our Fayetteville Shale play.  Of the approximately $1.8 billion invested in our E&P business in 2010, approximately $1.3 billion was invested in our Fayetteville Shale play, $150 million in East Texas, $118 million in Appalachia, $13 million in our conventional Arkoma Basin program and $145 million in New Ventures projects.

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 our drilling rig related equipment, sand facility and other equipment.  In 2009, we invested approximately $1.6 billion in our primary E&P business activities and participated in drilling 750 wells. Of the $1.6 billion invested in 2009, approximately $1.3 billion was invested in exploratory and development drilling and workovers, $82 million for acquisition of properties, $32 million for seismic expenditures and $155 million in capitalized interest and expenses and other technology-related expenditures. Additionally, we invested approximately $35 million in drilling rig related and ancillary equipment.  In 2008, we invested approximately $1.6 billion in our primary E&P business activities and participated in drilling 750 wells. Of the $1.6 billion invested in 2007, approximately $1.3 billion was invested in exploratory and development drilling and workovers, $83 million for acquisition of properties, $66 million for seismic expenditures and $118 million in capitalized interest and expenses and other technology-related expenditures.  

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In 2011, we plan to invest approximately $1.6 billion in our E&P program and participate in drilling 580 to 600 gross wells, 480 to 500 of which are planned to be operated by us.  The Fayetteville Shale play will be the primary focus of our capital investments, with planned investments of approximately $1.15 billion.  Our planned 2011 capital investments also include approximately $265 million in Appalachia, $170 million in unconventional, exploration and New Ventures projects and $30 million combined in East Texas and our conventional drilling program in the Arkoma Basin.  

Of the $1.6 billion allocated to our 2011 E&P capital budget, approximately $1.2 billion will be invested in development and exploratory drilling, $50 million in seismic and other geological and geophysical expenditures, $145 million in acquisition of properties and $255 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 2011.

Other Revenues

Other revenues and operating income for 2010 included gains of approximately $2.5 million related to the sale of gas-in-storage inventory.  Other revenues and operating income for 2009 included gains of approximately $3.4 million related to the sale of gas-in-storage inventory and charges totaling $6.1 million primarily related to a $4.3 million non-cash impairment to reduce the current portion of our natural gas inventory to the lower of cost or market. Other revenues and operating income for 2008 included gains of approximately $4.8 million related to the sale of gas-in-storage inventory.

Sales, Delivery Commitments and Customers

Sales. Our daily natural gas equivalent production averaged 1,108.8 MMcfe in 2010, compared to 823.1 MMcfe in 2009 and 533.1 MMcfe in 2008.  Total natural gas equivalent production was 404.7 Bcfe in 2010, up from 300.4 Bcfe in 2009 and 194.6 Bcfe in 2008.  Our natural gas production was 403.6 Bcf in 2010, compared to 299.7 Bcf in 2009 and 192.3 Bcf in 2008.  The increase in production in 2010 resulted primarily from a 106.7 Bcf increase in net production from our Fayetteville Shale play and a 1.0 Bcf increase in net production from our Appalachia properties, which more than offset a combined 3.4 Bcfe decrease in net production from our East Texas and Arkoma Basin properties.  The increase in production in 2009 resulted primarily from a 109.0 Bcf increase in production from the Fayetteville Shale play and an increase in our East Texas production, which more than offset a combined decrease in net production arising from decreased production from our Arkoma and other properties and the sale of our Permian Basin and Gulf Coast properties in 2008.  We also produced 171,000 barrels of oil in 2010, compared to 124,000 barrels of oil in 2009 and 385,000 barrels of oil in 2008.  Our oil production has decreased over the last three years primarily due to the sale of our Permian and Gulf Coast properties in 2008.  For 2011, we are targeting total natural gas and crude oil production of approximately 465 to 475 Bcfe, which represents a growth rate of approximately 15 to 17% over our 2010 production volumes.

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 crude 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. At December 31, 2010, we had NYMEX commodity price hedges in place on 128.6 Bcf, or approximately 27% of our targeted 2011 natural gas production, 148.6 Bcf of our expected 2012 natural gas production and 36.5 Bcf of our expected 2013 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 at December 31, 2010.

Including the effect of hedges, we realized an average wellhead price of $4.64 per Mcf for our natural gas production in 2010, compared to $5.30 per Mcf in 2009 and $7.52 per Mcf in 2008.  Our hedging activities increased our average gas price $0.71 per Mcf in 2010, increased our average gas price $1.96 per Mcf in 2009 and decreased our average price $0.21 per Mcf in 2008.  Our average oil price realized was $76.84 per barrel in 2010, compared to $54.99 per barrel in 2009 and $107.18 per barrel in 2008.  None of our crude oil production was hedged during 2010, 2009 or 2008.  

In recent years, locational differences in market prices for natural gas have been wider than historically experienced.  Disregarding the impact of hedges, during 2008 and 2009, widening market differentials caused the difference in our annual average price received for our natural gas production to range from approximately $0.65 to $1.30 per Mcf lower than market prices.  The discount was at its highest in late 2008, due to increased production in the Fayetteville Shale for which there was not sufficient transportation to other markets as a result of the delay in the completion of the Boardwalk

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Pipeline. Due to the completion of the Boardwalk Pipeline in April 2009 and the completion of the Fayetteville Express Pipeline in late 2010, the locational differences in the market prices for our natural gas production have narrowed from these levels.  During 2010, the average price received for our natural gas production, excluding the impact of hedges, was approximately $0.46 Mcf lower than average NYMEX spot market prices.  Assuming a NYMEX commodity price for 2011 of $4.50 per Mcf of natural gas, the average price received for our natural gas production is expected to be approximately $0.10 to $0.20 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges. Our E&P segment receives a sales price for our natural gas at a discount to NYMEX spot prices due to locational basis differentials, while transportation charges and fuel charges also reduce the price received.  In 2011, we expect to pay average third-party transportation charges in the range of $0.25 to $0.30 per Mcf and average fuel charges in the range of 0.50% to 1.00% of our sales price for natural gas.

Delivery Commitments. As of February 1, 2011, we had natural gas delivery commitments of 168 Bcf in 2011 and 45 Bcf in 2012 under existing agreements.  These commitments require the delivery of natural gas in Arkansas and Texas.   These amounts are well below our forecasted 2011 and anticipated 2012 production from our available reserves in our Fayetteville 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. We may have to borrow funds to pay for these natural gas purchases and if we are unable to do so, our earnings could be adversely affected.

Customers. Our customers include major and small energy companies, utilities and industrial consumers of natural gas. During the years ended December 31, 2010, 2009 and 2008, 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

Historically, the sale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, or the FERC.  In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, or the Decontrol Act.  The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993 and sales by producers of natural gas can be made at uncontrolled market prices.  

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 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.

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 should increase our access to markets for our natural gas production, these markets will also be 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.

Commencing in 1992, the FERC issued a series of orders (collectively, “Order No. 636”), which require interstate pipelines to provide transportation separately, or “unbundled,” from the pipelines’ sales of natural gas.  Order No. 636 also requires pipelines to provide open-access transportation on a basis that is equal for all shippers.  Although Order No. 636 does not directly regulate our activities, the FERC has stated that it intends for Order No. 636 to foster increased

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competition within all phases of the natural gas industry.  Starting in 2000, the FERC issued a series of orders (collectively, “Order No. 637”), which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC pricing policy by waiving price ceilings for short-term released capacity for a two-year period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, pipeline penalties, rights of first refusal and information reporting.  The implementation of these orders has not had a material adverse effect on our results of operations to date.

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.

Midstream Services

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.

Our operating income from this segment was $191.6 million on revenues of $2.5 billion in 2010, compared to $122.6 million on revenues of $1.6 billion in 2009 and $62.3 million on revenues of $2.2 billion in 2008.  Revenues increased in 2010 primarily due to increased gathering revenues and increased volumes marketed.  The decrease in revenue in 2009 was largely attributable to increased gathering revenues and increased volumes marketed which were more than offset by considerably lower natural gas prices. EBITDA generated by our Midstream Services segment was $220.5 million in 2010, compared to $141.9 million in 2009 and $73.9 million in 2008.  The increases in 2010 and 2009 operating income and EBITDA were primarily due to increased gathering revenues and marketing margins, partially offset by increased operating costs and expenses.  We expect that the operating income and EBITDA of our Midstream Services segment will increase significantly over the next few years as we continue to develop our Fayetteville Shale acreage.  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 2010, we invested approximately $271.3 million related to these activities and had gathering revenues of $316.0 million, compared to $214.2 million invested and revenues of $205.6 million in 2009 and $183.0 million invested and $114.9 million in revenues in 2008.  

DeSoto Gathering is rapidly expanding its network of gathering lines and facilities throughout the Fayetteville Shale play area. During 2010, DeSoto Gathering gathered approximately 562.6 Bcf of natural gas volumes in the Fayetteville Shale play area, including 56.6 Bcf of third-party natural gas.  During 2009, DeSoto Gathering gathered approximately 367.3 Bcf of natural gas volumes in the Fayetteville Shale play area, including 26.9 Bcf of third-party natural gas. In 2008, DeSoto Gathering gathered approximately 208.3 Bcf of natural gas volumes in the Fayetteville Shale play area, including 23.8 Bcf of third-party natural gas.  The increase in volumes gathered in over the past three years was primarily due to our growing production volumes from the Fayetteville Shale play.  At the end of 2010, DeSoto Gathering had approximately 1,569 miles of pipe from the individual wellheads to the transmission lines and compression equipment representing in aggregate approximately 475,000 horsepower had been installed at 58 central point gathering facilities in the field.  Our gathering revenues are expected to grow substantially over the next few years largely as a result of increased development of our acreage in the Fayetteville Shale and the increased development activity undertaken by other operators in the play area.

Angelina Gathering currently engages in gathering activities in East Texas and in Pennsylvania.  At year-end 2010, Angelina Gathering had approximately 25 miles of pipe in Texas and 12 miles of pipe 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 production and sells it to end-users and manages the basis and marketing portfolio and acquires transportation rights on third party pipelines and gathering lines.  Our current marketing

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operations primarily relate to the marketing of our own natural gas production and some third-party natural gas.  During 2010, we marketed 495.8 Bcf of natural gas, compared to 382.5 Bcf in 2009 and 258.0 Bcf in 2008.  Of the total volumes marketed, production from our E&P operated wells accounted for 95% in 2010, compared to 92% in 2009 and 96% in 2008.

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, have already been constructed by Texas Gas Transmission, LLC, or Texas Gas, a subsidiary of Boardwalk Pipeline Partners, LP.  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.  Our projections, financial condition, results of operation and planned capital expenditures could be adversely impacted by lack of available capacity and continued capacity reductions, shutdowns or other curtailments of the laterals or other pipelines.

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 end-users.

Regulation

On March 15, 2006, the United States Department of Transportation, or DOT, issued new rules pertaining to certain gathering lines. Compliance with the new rules has not had a material adverse impact on our operations. 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.

On November 20, 2008, the FERC issued a Final Rule in Order No. 720, which requires, in relevant part, major non-interstate 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 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 is be required to comply with the requirements of Order No. 720 which became effective in 2010.

Natural Gas Distribution

Effective July 1, 2008, we sold all of the capital stock of Arkansas Western Gas for $223.5 million (net of expenses related to the sale). In order to receive regulatory approval for the sale and certain related transactions, we paid $9.8 million to Arkansas Western Gas for the benefit of its customers.  We recorded a pre-tax gain on the sale of $57.3 million in the third quarter of 2008.  As a result of the sale of the utility, we are no longer engaged in natural gas distribution operations. Arkansas Western Gas provided operating income for the first half of 2008 of $10.7 million.

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Other

Our other operations have primarily consisted of real estate development activities concentrated on tracts of land located in Arkansas.  There were no sales of commercial real estate in 2010, 2009 or 2008. As of December 31, 2010, we owned our office complex in Fayetteville, Arkansas, an interest in approximately 15 acres of undeveloped real estate near the Fayetteville complex, our office complex in Conway, Arkansas and 1,353 acres in or near Conway, Arkansas, related to our operations in the Fayetteville Shale play.

Other Items

Reconciliation of Non-GAAP Measures

EBITDA is defined as net income (loss) attributable to Southwestern Energy plus interest, income tax expense, 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, 2010, 2009 and 2008:

		Midstream	Natural Gas
	E&P	Services	Distribution	Other	Total
	(in thousands)
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 for income taxes	323,748	67,834	—	77	391,659
EBITDA	$   1,391,000	$      220,510	$               —	$             762	$ 1,612,272
2009
Net income (loss) attributable to Southwestern Energy	$     (109,690)	$        73,950	$               —	$               90	$     (35,650)
Depreciation, depletion and amortization	474,014	19,213	—	431	493,658
Impairment of natural gas and oil properties	907,812	—	—	—	907,812
Net interest expense	15,237	3,401	—	—	18,638
Provision (benefit) for income taxes	(61,724)	45,303	—	58	(16,363)
EBITDA	$   1,225,649	$      141,867	$               —	$             579	$ 1,368,095
2008
Net income attributable to Southwestern Energy	$      492,283	$        35,145	$          5,050	$        35,468	$    567,946
Depreciation, depletion and amortization	399,159	11,402	3,484	415	414,460
Net interest expense	20,528	6,059	2,317	—	28,904
Provision for income taxes	304,636	21,278	3,095	21,990	350,999
EBITDA	$   1,216,606	$        73,884	$        13,946	$        57,873	$ 1,362,309

Environmental Regulation

Our operations are subject to numerous federal, state and local 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, the prevention and cleanup of pollutants and other matters.  We maintain insurance against costs of clean-up

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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 crude 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.

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 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 Environmental

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Protection Agency, or 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.

We utilize hydraulic fracturing in our E&P operation as a means of maximizing the productivity of our wells.  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, including our Marcellus Shale acreage.  In our Fayetteville Shale play, the fracturing fluids we use are comprised of over 99% water, with small quantities of additives containing compounds such as hydrochloric acid, mineral oil, citric acid and biocide. Many of these additives can be found in common consumer and household products.  The fracturing fluid is combined with sand and injected under high pressure into the target formation. As the mixture is forced into the formation, the pressure causes the rock to fracture and the sand remains behind to prop open the fractures. These fractures create a pathway for the natural gas to flow out of the formation and into the wellbore. A 2004 study conducted by the EPA found that certain hydraulic fracturing posed no risk to drinking water and Congress exempted hydraulic fracturing from the Safe Drinking Water Act, or SDWA. Recently, there has been a heightened debate over whether the fluids used in hydraulic fracturing may contaminate drinking water supply and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing. Both the United States House of Representatives and Senate are considering Fracturing Responsibility and Awareness of Chemicals (FRAC) Act bills and a number of states, including states in which we have operations, are looking to more closely regulate hydraulic fracturing due to concerns about water supply. The recent congressional legislative efforts seek to regulate hydraulic fracturing to Underground Injection Control program requirements, which would significantly increase well capital costs. We are actively exploring and/or testing new alternatives for certain of the compounds we use in our additives but there can be no assurance that these alternatives will be effective at the volumes and rates we require.  If the exemption for hydraulic fracturing is removed from the SDWA, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operation.

Employees

At December 31, 2010, we had 2,088 total employees.  None of our employees were covered by a collective bargaining agreement at year-end 2010.  We believe that our relationships with our employees are good.

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GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below shall 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 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 crude 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 crude 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 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.

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“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and 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

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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.

“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 crude 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 crude oil to six Mcf of natural gas.

“MMBbls”  One million barrels of crude 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 crude 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.

“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 the

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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 crude oil to six Mcf of natural gas.

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“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 gas reserves” Undeveloped oil and 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 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 crude oil in the United States.

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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.”

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.  The prices for natural gas and oil are subject to 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 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.  

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

In the first half of 2008, natural gas and oil prices were at or near their highest historical levels but subsequently natural gas and oil prices declined significantly.  Natural gas prices remained at substantially lower levels throughout 2009 and did not significantly increase in 2010. The further 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:

·

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.

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Lower natural gas and oil prices and/or increased development costs may cause us to record ceiling test write-downs.  

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.”  This is equal to the present value of estimated future net cash flows from proved natural gas and oil reserves, discounted at 10 percent, 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, 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. They 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.

In the period ended March 31, 2009, we incurred a ceiling test write-down of $907.8 million which resulted in an operating loss for our company for 2009. If natural gas and oil prices decline below levels utilized in our ceiling limit test at December 31, 2009 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.

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 expenditure and working capital needs as a result of our drilling program. Our planned capital investments for 2011 are expected to significantly exceed the net cash generated by our operations under current natural gas prices.  We expect to borrow under our 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 credit facility is subject to certain conditions.  At December 31, 2010, we were in compliance with the borrowing conditions of our credit facility.  If we are not in compliance with the terms of our credit facility in the future or if the lenders under our credit facility are unable to fulfill their commitments, we may not be able to borrow under the 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.

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 (the “Act”) was passed by Congress and signed into law.  The new legislation requires the Commodities Futures Trading Commission (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.

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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.

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 85% 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 85% present value as of December 31, 2010, accounted for approximately 88% of our total proved reserves and approximately 95% 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. For the year-ended December 31, 2010, on January 27, 2011, NSAI issued its audit opinion as to the reasonableness of our reserve estimates, stating that our estimated proved oil and 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 Vice President – EP&A who was the technical person primarily responsible for the preparation of our reserve estimates, and has over twenty years of experience in petroleum engineering, including over fifteen years in estimating oil and natural gas reserves. On our behalf, the Vice President – EP&A 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 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 and final authority over the estimates of our proved reserves rests with our Board of Directors. 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 results 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,

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operating and development costs and other factors.  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 properties.  In 2009, our reserves were revised upward by 92.9 Bcfe, primarily due to improved performance in our Fayetteville Shale properties, partially offset by downward revisions due to a comparative decrease in the average 2009 price from the year-end 2008 gas price. In 2008, our reserves were revised upward by 98.1 Bcfe, primarily due to improved performance in our Fayetteville Shale properties, partially offset by downward revisions due to lower year-end oil and natural gas prices combined with the performance revisions in some of our East Texas and conventional Arkoma Basin properties. These revisions represented no greater than 7% of our total reserve estimates in each of these years, which we believe is indicative of the effectiveness of our internal controls.  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.  At December 31, 2010, approximately 2,243 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.

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

At December 31, 2010, we had total indebtedness of $1,094.2 million, including borrowings of $421.2 million under our revolving credit facility.  At February 22, 2011, we had total long-term indebtedness of $1,219.4 million, including borrowings of $546.4 million under our revolving credit facility.  We currently expect to utilize the borrowing availability under our revolving credit facility in order to fund a portion of our capital investments in 2011.  See also our risk factor headed “We may have difficulty financing our planned capital investments which could adversely affect our growth,” above.

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 an equity offering.  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

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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 an offering of our capital stock, 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.

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 are subject to change.

As of December 31, 2010, we had drilled and completed 1,820 operated wells relating to our Fayetteville Shale play.  At year-end 2010, approximately 54% of our leasehold acreage was held by production, excluding our acreage in the traditional Fairway portion of the Arkoma Basin. Our drilling plans with respect to our Fayetteville Shale play are flexible and are dependent upon a number of factors, including the extent to which we can replicate the results of our most successful Fayetteville Shale wells on our other Fayetteville Shale acreage as well as the natural gas and oil commodity price environment.  The determination as to whether we continue to drill wells in the Fayetteville Shale may depend on any one or more of the following factors:

·

our ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation;

·

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 oil field 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 the Fayetteville Shale, 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 Fayetteville Shale acreage, the initial lease terms could expire, which would result in the loss of certain leasehold rights.

Approximately 236,607 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 174,329 net acres are held on federal lands.  As discussed above under “Our drilling plans for the Fayetteville 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.  The number of wells we will be required to drill to retain our leasehold rights will be determined by field rules established by the Arkansas Oil and Gas Commission, or the AOGC.

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In 2006, the AOGC approved field rules in the Fayetteville Shale, the Moorefield Shale and the Chattanooga Shale as “unconventional sources of supply.”  Under the rules, each drilling unit would consist of a governmental section of approximately 640 acres and operators would be permitted to drill up to 16 wells per drilling unit for each unconventional source of supply.  However, current rules are subject to change and could impair our ability to drill or maintain our acreage position.  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 for certain of our Fayetteville Shale acreage.

If our Fayetteville Shale drilling program fails to continue to produce a significant supply of natural gas, our investments in our gas gathering operations could be lost and our commitments for transportation on pipelines 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, 2010, we had invested approximately $788.5 million in our gas gathering system built for the Fayetteville Shale play.  We intend to continue to make substantial investments in the expansion of our gas gathering system as we further develop the play.  Our gas gathering business will largely rely on natural gas sourced in our Fayetteville Shale play area in Arkansas.  In addition, we have entered into 10-year firm transportation agreements committing us to transportation on Texas Gas Fayetteville and Greenville Laterals built by Texas Gas as well as the Fayetteville Express Pipeline.  Our marketing subsidiary has also entered into multiple other firm transportation agreements relating to natural gas volumes from our Fayetteville Shale play. As of December 31, 2010, our aggregate demand charge commitments under these firm transportation agreements were approximately $1.8 billion. If our Fayetteville Shale drilling program fails to produce a significant supply of natural gas, our investments in our gas gathering operations could be lost, and we could be forced to pay demand charges for transportation on pipelines 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.

We require significant amounts of undeveloped leasehold acreage in order to further our development efforts.  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 are dependent upon the current and future market prices for natural gas and crude oil, costs associated with producing natural gas and crude 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.

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

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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, and an owner of gas gathering systems, 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.

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.

Our financial condition and results of operation could be adversely affected if the exemption for hydraulic fracturing is removed from the Safe Drinking Water Act, or if legislation is enacted at the federal, state or local level regulating hydraulic fracturing.

We utilize hydraulic fracturing in our E&P operation as a means of maximizing the productivity of our wells.  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, including our Marcellus Shale acreage.  In our Fayetteville Shale play, the fracturing fluids we use are comprised of over 99% water, with small quantities of additives containing compounds such as hydrochloric acid, mineral oil, citric acid and biocide. Many of these additives can be found in common consumer and household products.  The fracturing fluid is combined with sand and injected under high pressure into the target formation. As the mixture is forced into the formation, the pressure causes the rock to fracture and the sand remains behind to prop open the fractures. These fractures create a pathway for the natural gas to flow out of the formation and into the wellbore. A 2004 study conducted by the EPA found that certain hydraulic fracturing posed no risk to drinking water and Congress exempted hydraulic fracturing from the Safe Drinking Water Act, or SDWA. Recently, there has been a heightened debate over whether the fluids used in hydraulic fracturing may contaminate drinking water supply and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing. Both the United States House of Representatives and Senate are considering Fracturing Responsibility and Awareness of Chemicals (FRAC) Act bills and a number of states, including states in which we have operations, are looking to more closely regulate hydraulic fracturing due to concerns about water supply. The recent congressional legislative efforts seek to regulate hydraulic fracturing to Underground Injection Control program requirements, which would significantly increase well capital costs. We are actively exploring and/or testing new alternatives for certain of the compounds we use in our additives but there can be no assurance that these alternatives will be effective at the volumes and rates we require.  If the exemption for hydraulic fracturing is removed from the SDWA, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operation.

Natural gas and oil drilling and producing operations involve various risks.

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.  

We cannot control activities on properties we do not operate.  Failure to fund capital investments may result in reduction or forfeiture of our interests in some of our non-operated projects.

We do not operate some of the properties in which we have an interest and we have limited ability to exercise influence over operations for these properties or their associated costs.  As of December 31, 2010, approximately 5% of

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our natural gas and oil properties, based on the PV-10 value of our proved developed producing reserves, were operated by other companies.  Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and our targeted production growth rate.  The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond our control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of technology.

When we are not the majority owner or operator of a particular natural gas or oil project, we may have no control over the timing or amount of capital investments associated with such project.  If we are not willing or able to fund our capital investments relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

Our ability to sell our natural gas and crude oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

Our ability to bring natural gas and crude oil production to market depends on a number of factors including the availability and proximity of pipelines, gathering systems and processing facilities. In some of the areas where we have operations, we deliver natural gas and crude oil through gathering systems and pipelines that we do not own.  With respect to our Fayetteville Shale production, we rely on interstate pipelines to bring our production to market. The unavailability of these pipelines or other facilities due to market conditions, mechanical reasons or otherwise could have an adverse impact on our results of operations and financial condition.  Any significant change affecting these facilities or our failure to obtain access to existing or future facilities on acceptable terms could restrict our ability to conduct normal 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 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 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 own drilling rig 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 disrupted, these operations may adversely impact our results of operations.  In addition, 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 and we may make additional investments to expand these operations in the future.  Our drilling operations are conducted through our subsidiary, DDI, which had 365 employees as of December 31, 2010.  We have lease commitments for 14 drilling rigs and related equipment with respect to DDI's operations and we also

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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 2010, another of our subsidiaries, DeSoto Sand, LLC, 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 operations and/or sand mine are disrupted or our existing third-party 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 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, our failure to hedge a significant portion of our expected 2011 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 22, 2011, we had NYMEX commodity price hedges on approximately 40% of our targeted 2011 natural gas production as compared to approximately 60% to 80% from 2006 to 2008, 45% for 2009 and 30% for 2010.  Our price risk management activities increased natural gas sales by $290.3 million in 2010, increased natural gas sales by $587.8 million in 2009 and decreased natural gas sales by $40.5 million in 2008. If natural gas prices decline in 2011, 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.

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. 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

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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 Environmental Protection Agency, or 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 affect on our operations and financial condition.

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.

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ITEM 2.  PROPERTIES

The summary of our oil and natural gas reserves as of fiscal year-end 2010 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2010 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 Vice President-Economic Planning and Acquisitions, or Vice President-EP&A, who was the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Vice President-EP&A has more than thirty years of experience in petroleum engineering, including over twenty years of experience in estimating oil and natural gas reserves and holds a Bachelor of Science in Petroleum Engineering.  Prior to joining us in 2007, our Vice President-EP&A served in various engineering and senior management roles for Gulf Oil Corporation, Tenneco Oil Company, Fina Oil and Chemical Company, Southwest Royalties, Inc., Total and The Houston Exploration Company.  Our Vice President-EP&A is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.  On our behalf, the Vice President-EP&A 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 technical persons primarily responsible for auditing our proved reserves estimates each (1) have at a minimum over 25 years of practical experience in petroleum engineering; (2) have at a minimum over 18 years of experience in the estimation and evaluation of reserves; (3) have college degrees; (4) is a registered Professional Engineer in the State of Texas or a Certified Petroleum Geologist and Geophysicist in the State of Texas; (5) 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) is proficient in judiciously 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 and final authority over the estimates of our proved reserves rests with our Board of Directors.  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.

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The information regarding oil and gas properties, wells, operations and acreage required by Item 1205 of Regulation S-K is set forth below:   

Leasehold acreage as of December 31, 2010:

	Undeveloped		Developed
	Gross	Net	Gross	Net
Fayetteville Shale Play(1)	670,720	367,206	627,200	423,692
U.S. Exploitation:
Conventional Arkoma(2)	296,886	250,657	257,107	182,452
East Texas(3)	79,954	53,228	103,761	72,335
Appalachia(4)	187,864	169,095	3,914	3,914
New Ventures:
USA New Ventures(5)	536,000	491,125	-	-
Canada New Ventures(6)	2,518,518	2,518,518	-	-
	4,289,942	3,849,829	991,982	682,393

(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 17,502 net acres in 2011, 3,711 net acres in 2012 and 215,394 net acres in 2013.

(2)

Includes 123,442 net developed acres and 1,544 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 32,720 net acres in 2011, 29,699 net acres in 2012 and 2,971 net acres in 2013.

(3)

Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 22,827 net acres in 2011, 6,371 net acres in 2012 and 1,388 net acres in 2013.

(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 2,325 net acres in 2011, 63,117 net acres in 2012 and 43,077 net acres in 2013.

(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 19,735 net acres in 2011, 22,500 net acres in 2012 and 60 net acres in 2013.

(6)

Assuming the options are not extended/exercised by March 2013 then, in such event, 2,518,518 net acres will expire in 2013.

Producing wells as of December 31, 2010:

	Natural Gas		Oil		Total		Gross Wells
	Gross	Net	Gross	Net	Gross	Net	Operated
Fayetteville Shale Play	2,120	1,437	-	-	2,120	1,437	1,738
U.S. Exploitation:
Conventional Arkoma	1,185	572	-	-	1,185	572	550
East Texas	594	458	11	7	605	465	541
Appalachia	8	7	-	-	8	7	8
	3,907	2,474	11	7	3,918	2,481	2,837

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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
2010	0.0	0.0	0.0	0.0	0.0	0.0
2009	1.0	0.9	2.0	1.2	3.0	2.1
2008	34.0	22.4	2.0	2.0	36.0	24.4

	Development(1)
	Productive Wells		Dry Wells		Total
Year	Gross	Net	Gross	Net	Gross	Net
2010(2)	483.0	305.5	3.0	1.9	486.0	307.4
2009	418.0	253.6	3.0	1.8	421.0	255.4
2008	445.0	270.2	9.0	6.8	454.0	277.0

(1)

We have not drilled any exploratory or development wells in Canada in the past three years.

(2)

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.

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, 2010 ⁽¹⁾

	Gross	Net
Drilling:
Exploratory	-	-
Development	96.0	68.6
Total	96.0	68.6
Completing:
Exploratory	-	-
Development	131.0	85.3
Total	131.0	85.3
Drilling & Completing:
Exploratory	-	-
Development	227.0	153.9
Total	227.0	153.9

(1)

As of December 31, 2010, we did not have any drilling activities in Canada.

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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 December31,
	2010	2009	2008
Natural Gas
Production (Bcf):
Fayetteville Shale	350.2	243.5	134.5
Total	403.6	299.7	192.3
Average gas price per Mcf, including hedges:
Fayetteville Shale	$           4.73	$            5.73	$             7.22
Total	$           4.64	$            5.30	$             7.52
Average gas price per Mcf, excluding hedges:
Fayetteville Shale	$           3.89	$            3.31	$             7.52
Total	$           3.93	$            3.34	$             7.73
Oil
Oil production (MBbls)(1)	171	124	385
Average oil price per Bbl(1)	$         76.84	$          54.99	$         107.18
Average Production Cost
Cost per Mcfe, excluding ad valorem and severance taxes:
Fayetteville Shale	$           0.86	$            0.80	$             0.99
Total	$           0.83	$            0.77	$             0.89

(1)

Our Fayetteville Shale operations did not produce any oil for the years ended December 31, 2010, 2009 and 2008.

During 2010, 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.

Miles of Pipe

At December 31, 2010, our Midstream Services segment had 1,569 miles, 25 miles and 12 miles of pipe in its gathering systems located in Arkansas, Texas, and Pennsylvania, 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 natural 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.

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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.

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 273 ^rd District Court in Shelby County, Texas (collectively, the “Sixth Petition”) the plaintiffs 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 plaintiffs, subsequently acquired leases based upon such proprietary data and profited therefrom.  Among other things, the plaintiffs’ 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, plaintiffs sought actual damages of over $55 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, plaintiffs were permitted, over the Company’s objections, to file a Seventh Amended Petition claiming actual damages of approximately $46 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 plaintiffs with respect to all of the statutory and common law claims and awarded approximately $11.4 million in compensatory damages. The jury did not, however, award plaintiffs 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 plaintiffs’ 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 plaintiffs.  On December 31, 2010, the plaintiff and intervenor 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.  A hearing on the post-verdict motions has been scheduled for March 14, 2011, subject to any postponements or adjournments thereof.

The Company has not accrued any amounts with respect to this lawsuit and cannot reasonably estimate the amount of any potential liability based on the Company's understanding and judgment of the facts and merits of this case, including appellate remedies, and the advice of counsel.  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 could be material to the Company's results of operations, financial position or cash flows.

In March 2010, the Company’s subsidiary, SEECO, Inc., 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. The Company cannot reasonably estimate the amount of any potential liability from this matter and does not believe that this matter will have a material adverse effect on its results of operations, financial position or cash flows, however, 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.

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 or our results of operations 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

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reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.

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 under the symbol “SWN.”  On February 22, 2011, the closing price of our stock was $36.36 and we had 3,001 stockholders of record.  The following table presents the high and low sales prices for closing market transactions as reported on the New York Stock Exchange, which prices have been adjusted as appropriate to reflect the two-for-one stock split effected in March 2008.

	Range of Market Prices
Quarter Ended	2010		2009		2008
March 31	$  51.65	$  37.70	$  34.14	$  25.99	$  34.07	$  24.82
June 30	$  44.99	$  35.86	$  45.65	$  30.01	$  48.69	$  33.77
September 30	$  38.83	$  31.44	$  45.08	$  35.39	$  48.53	$  27.91
December 31	$  38.45	$  32.73	$  50.62	$  40.28	$  37.22	$  20.81

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

Issuer Purchases of Equity Securities

During 2010, we retired 3,109 shares for the payment of withholding taxes due on employee stock plan share issuances.  All changes in common stock in treasury in 2010 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 12 “Equity” 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 2010.

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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, 2005, and that all dividends were reinvested.  The stock performance shown on the graph below is not indicative of future price performance.

	Southwestern Energy Company		Dow Jones U.S. Exploration & Production
	S&P 500 Index

	12/31/05	12/31/06	12/31/07	12/31/08	12/31/09	12/31/10
Southwestern Energy Company	100	98	155	161	268	208
Dow Jones U.S. Exploration & Production	100	105	151	91	127	149
S&P 500 Index	100	116	122	77	97	112

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2010. 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.”

	2010	2009	2008	2007	2006
	(in thousands except share, per share, stockholder data and percentages)
Financial Review
Operating revenues:
Exploration and production	$  1,890,444	$    1,593,231	$    1,491,302	$       795,944	$       491,545
Midstream services	2,453,840	1,603,332	2,173,971	961,994	475,207
Gas distribution and other	984	687	118,399	174,914	172,655
Intersegment revenues	(1,734,605)	(1,051,471)	(1,472,120)	(677,721)	(376,295)
	2,610,663	2,145,779	2,311,552	1,255,131	763,112
Operating costs and expenses:
Gas purchases – midstream services	611,161	482,836	710,129	306,336	128,387
Gas purchases – gas distribution	—	—	61,439	85,445	79,363
Operating and general	337,334	259,159	209,536	166,095	132,691
Depreciation, depletion and amortization	590,332	493,658	414,408	293,914	151,290
Impairment of natural gas and oil properties	—	907,812	—	—	—
Taxes, other than income taxes	50,608	37,280	29,272	21,875	25,109
	1,589,435	2,180,745	1,424,784	873,665	516,840
Operating income (loss)	1,021,228	(34,966)	886,768	381,466	246,272
Interest expense, net	26,163	18,638	28,904	23,873	679
Other income (loss), net	427	1,449	4,404	(219)	17,079
Gain on sale of utility assets	—	—	57,264	—	—
Income (loss) before income taxes	995,492	(52,155)	919,532	357,374	262,672
Provision (benefit) for income taxes:
Current	11,939	(64,969)	122,000	—	—
Deferred	379,720	48,606	228,999	135,855	99,399
	391,659	(16,363)	350,999	135,855	99,399
Net income (loss)	603,833	(35,792)	568,533	221,519	163,273
Less: net income (loss) attributable to noncontrolling interest	(285)	(142)	587	345	637
Net income (loss) attributable to Southwestern Energy	$     604,118	$        (35,650)	$       567,946	$       221,174	$       162,636
Return on equity(1)	20.4%	(1.5%)	22.6%	13.3%	11.2%
Net cash provided by operating activities	$  1,642,585	$    1,359,376	$    1,160,809	$       622,735	$       429,937
Net cash used in investing activities	$(1,725,631)	$   (1,780,604)	$      (792,078)	$  (1,513,497)	$      (630,006)
Net cash provided by (used in) financing activities	$       86,240	$ 238,135	$      (174,286)	$       849,667	$         19,291
Common Stock Statistics (2)
Earnings per share:
Net income (loss) attributable to Southwestern stockholders – Basic	$            1.75	$            (0.10)	$             1.66	$             0.65	$             0.49
Net income (loss) attributable to Southwestern stockholders – Diluted	$            1.73	$            (0.10)	$             1.64	$             0.64	$             0.47
Cash dividends declared and paid per share	$                —	$                —	$                —	$                —	$                —
Book value per average diluted share(1)	$            8.49	$             6.82	$             7.27	$             4.77	$             4.22
Market price at year-end	$          37.43	$           48.20	$           28.97	$           27.86	$           17.52
Number of stockholders of record at year-end	3,043	2,639	2,497	2,275	2,412
Average diluted shares outstanding	349,310,666	343,420,568	346,245,938	347,442,660	342,575,500

(1)

The return on equity and the book value per average diluted share calculations have been recalculated for 2008, 2007 and 2006 and now include an addition to equity for the Company’s noncontrolling interest in partnership.

(2)

Share and per share amounts in 2007 and 2006 have been restated to reflect the two-for-one stock split effected in March 2008.  

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	2010	2009	2008	2007	2006
Capitalization (in thousands)
Total debt	$ 1,094,200	$      998,700	$       735,400	$      978,800	$      137,800
Total equity	2,964,876	2,340,981	2,517,963	1,657,070	1,445,677
Total capitalization	$ 4,059,076	$   3,339,681	$    3,253,363	$   2,635,870	$   1,583,477
Total assets	$ 6,017,463	$   4,770,250	$    4,760,158	$   3,622,716	$   2,379,069
Capitalization ratios:
Debt	27.0%	29.9%	22.6%	37.1%	8.7%
Equity	73.0%	70.1%	77.4%	62.9%	91.3%
Capital Investments (in millions) (1)
Exploration and production:
Exploration and development	$     1,771.1	$       1,556.3	$        1,569.1	$       1,375.2	$          767.4
Drilling rigs and related equipment (2)	4.4	9.2	26.7	4.5	93.6
	1,775.5	1,565.5	1,595.8	1,379.7	861.0
Midstream services	271.3	214.2	183.0	107.4	48.7
Gas distribution (3)	—	—	3.6	11.4	11.2
Other	73.3	29.4	13.8	4.6	21.5
	$     2,120.1	$       1,809.1	$        1,796.2	$       1,503.1	$          942.4
Exploration and Production
Natural gas:
Production, Bcf	403.6	299.7	192.3	109.9	68.1
Average price per Mcf, including hedges	$           4.64	$            5.30	$             7.52	$            6.80	$            6.55
Average price per Mcf, excluding hedges	$           3.93	$            3.34	$             7.73	$            6.16	$            6.37
Oil:
Production, MBbls	171	124	385	614	698
Average price per barrel, including hedges	$         76.84	$          54.99	$         107.18	$          69.12	$          58.36
Average price per barrel, excluding hedges	$         76.84	$          54.99	$         107.18	$          69.12	$          63.17
Total natural gas and oil production, Bcfe	404.7	300.4	194.6	113.6	72.3
Lease operating expenses per Mcfe	$           0.83	$            0.77	$             0.89	$            0.73	$            0.66
General and administrative expenses per Mcfe	$           0.30	$            0.35	$             0.41	$            0.48	$            0.58
Taxes, other than income taxes per Mcfe	$           0.11	$            0.11	$             0.13	$            0.16	$            0.30
Proved reserves at year-end:
Natural gas, Bcf	4,930	3,650	2,176	1,397	979
Oil, MMBbls	1	1	2	9	8
Total reserves, Bcfe	4,937	3,657	2,185	1,450	1,026
Midstream Services
Gas volumes marketed, Bcf	495.8	382.5	258.0	145.7	72.7
Gas volumes gathered, Bcf	588.3	387.1	224.1	78.7	14.6
Natural Gas Distribution (3)
Sales and transportation volumes, Bcf	—	—	14.5	23.6	21.8
Off-system transportation, Bcf (4)	—	—	—	0.3	0.1
Total volumes delivered	—	—	14.5	23.9	21.9
Customers at year-end:
Residential	—	—	—	134,616	133,679
Commercial	—	—	—	17,180	17,151
Industrial	—	—	—	192	173
	—	—	—	151,988	151,003
Annual degree days	—	—	—	3,699	3,413
Percent of normal	—	—	—	91%	83%

(1)

Capital investments include increases of $14.4 million for 2010, $12.2 million for 2009, $36.2 million for 2008, a reduction of $20.6 million for 2007 and an increase of $88.9 million for 2006 related to the change in accrued expenditures between years.

(2)

The 2006 drilling rigs and related equipment capital investments were sold in December 2006 as part of a sale and leaseback transaction.

(3)

Effective July 1, 2008, we sold our utility subsidiary, Arkansas Western Gas Company and, as a result, we no longer have any natural gas distribution operations. The 2008 column reflects results for the first six months of 2008 for Arkansas Western Gas Company.

(4)

Off-system transportation volumes for the first six months of 2008 were less than 0.1 Bcf.

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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 crude oil exploration, development and production (E&P). We are also focused on creating and capturing additional value through our gas gathering and marketing businesses, which we refer to as Midstream Services. We have historically operated principally in three segments: E&P, Midstream Services and Natural Gas Distribution.  On July 1, 2008, we closed the sale of our utility subsidiary, Arkansas Western Gas Company, or Arkansas Western Gas, and as a result, no longer have any natural gas distribution operations. The operating results and cash flows from Arkansas Western Gas through June 30, 2008 are included in the consolidated statements of operations and statements of cash flows, as applicable, and are not presented as “discontinued operations.” We refer you to Note 2 to the consolidated financial statements included in this Form 10-K for additional information.

Our primary business is the exploration for and production of natural gas within the United States with our current operations being principally focused 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 Texas, Pennsylvania and to a lesser extent in Oklahoma.  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, which we achieve in our E&P business through the drillbit. 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 primarily depend 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 the ongoing development of our Fayetteville Shale play in Arkansas. 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 (“NYMEX”) natural gas prices ranging from a high of $13.58 per Mcf in 2008 to a low of $2.51 per Mcf in 2009.  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

We reported net income attributable to Southwestern Energy of $604.1 million in 2010, or $1.73 per diluted share, up from a net loss attributable to Southwestern Energy of $35.7 million, or $0.10 per diluted share, in 2009. The loss in 2009 included a $907.8 million, or $558.3 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 the first quarter of 2009. We reported net income attributable to Southwestern Energy of $567.9 million in 2008, or $1.64 per diluted share. Net income attributable to Southwestern Energy in 2008 included a $35.4 million net of tax gain, or $0.10 per diluted share, related to the sale of Arkansas Western Gas that closed on July 1, 2008. Our cash flow from operating activities increased 21% to $1,642.6 million in 2010 due to an increase in net income adjusted for non-cash expenses and changes in working capital, and increased 17% to $1,359.4 million in 2009 due to an increase in net income adjusted for non-cash expenses, partially offset by changes in working capital.

In 2010, our natural gas and oil production increased 35% to 404.7 Bcfe, up from 300.4 Bcfe in 2009.  The 104.3 Bcfe increase in our 2010 production resulted from a 106.7 Bcf increase in net production from our Fayetteville Shale play and a 1.0 Bcf increase in net production from our Appalachia properties, which more than offset a combined 3.4 Bcfe

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decrease in net production from our East Texas and Arkoma Basin properties. In 2009, our natural gas and oil production increased to 300.4 Bcfe, up from 194.6 Bcfe in 2008.  We are targeting 2011 natural gas and oil production of 465 to 475 Bcfe, an increase of approximately 15 to 17% over our 2010 production.  Our year-end reserves grew 35% in 2010 to 4,937 Bcfe, up from 3,657 Bcfe at the end of 2009 and 2,185 Bcfe at the end of 2008, primarily as a result of the continued development of our Fayetteville Shale play.

Our E&P segment reported operating income of $829.5 million in 2010, up from an operating loss of $157.7 million in 2009.  The operating loss in 2009 included a $907.8 million non-cash ceiling test impairment of our United States natural gas and oil properties.  Excluding the $907.8 million non-cash ceiling test impairment, operating income in 2010 increased $79.4 million over 2009 as a result of the revenue impact of our 35% increase in production which was partially offset by the 12% decline in our average realized gas prices and a $217.8 million increase in operating costs and expenses that resulted from our significant production growth. We recorded operating income from our E&P segment of $813.5 million for 2008. Excluding the $907.8 million non-cash ceiling test impairment in 2009, operating income decreased $63.4 million in 2009 compared to 2008 as a result of a 30% decline in our average realized gas prices and a $165.3 million increase in operating costs and expenses that resulted from our significant production growth, which was partially offset by the revenue impact of our 54% increase in production.

Operating income for our Midstream Services segment was $191.6 million in 2010, up from $122.6 million in 2009 and $62.3 million in 2008. Operating income for our Midstream Services segment increased in 2010 due to an increase of $110.4 million in gathering revenues and an increase of $5.5 million in the margin generated from our natural gas marketing activities, which were partially offset by a $46.9 million increase in operating costs and expenses, exclusive of gas purchase costs, that resulted from our continued significant growth in volumes gathered. Volumes gathered grew to 588.3 Bcf in 2010 compared to 387.1 Bcf in 2009. Operating income for our Midstream Services segment increased in 2009 due to an increase of $90.7 million in gathering revenues and an increase of $6.3 million in the margin generated from our natural gas marketing activities, which were partially offset by a $36.7 million increase in operating costs and expenses, exclusive of gas purchase costs, that resulted from our significant growth in volumes gathered. Volumes gathered grew to 387.1 Bcf in 2009 compared to 224.1 Bcf in 2008.

Operating income for our Natural Gas Distribution segment was $10.7 million for the first six months in 2008, prior to the sale of Arkansas Western Gas.

We had total capital investments of $2,120.1 million in 2010, compared to $1,809.1 million in 2009 and $1,796.2 million in 2008.  Of our total capital investments, $1,775.5 million was invested in our E&P segment in 2010 compared to $1,565.5 million and $1,595.8 million invested in our E&P segment in 2009 and 2008, 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, 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 2011 is based on our expectation that natural gas prices will remain near 2010 price levels and the realized sales price for our production continues to meet our targeted return of $1.30 of discounted pre-tax PVI for each dollar we invest in our E&P projects.

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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,
	2010	2009	2008
Revenues (in thousands)	$  1,890,444	$     1,593,231	$     1,491,302
Impairment of natural gas and oil properties (in thousands)	$                —	$        907,812	$                 —
Operating costs and expenses(in thousands)	$  1,060,982	$        843,144	$        677,798
Operating income (loss) (in thousands)	$     829,462	$      (157,725)	$        813,504
Natural gas production (Bcf)	403.6	299.7	192.3
Oil production (MBbls)	171	124	385
Total production (Bcfe)	404.7	300.4	194.6
Average gas price per Mcf, including hedges	$             4.64	$              5.30	$              7.52
Average gas price per Mcf, excluding hedges	$             3.93	$              3.34	$              7.73
Average oil price per Bbl	$          76.84	$            54.99	$          107.18
Average unit costs per Mcfe:
Lease operating expenses	$             0.83	$              0.77	$              0.89
General and administrative expenses	$             0.30	$              0.35	$              0.41
Taxes, other than income taxes	$             0.11	$              0.11	$              0.13
Full cost pool amortization	$             1.34	$              1.51	$              1.99

Revenues

Revenues for our E&P segment were up $297.2 million, or 19%, in 2010 compared to 2009. Higher natural gas production volumes in 2010 increased revenues by $551.0 million while lower realized prices for our natural gas production decreased revenue by $265.1 million compared to 2009.  E&P revenues were up $101.9 million, or 7%, in 2009 compared to 2008. Higher natural gas production volumes in 2009 increased revenues by $807.4 million while lower realized prices for our natural gas production decreased revenue by $663.4 million. We expect our natural gas production volumes to continue to increase due to the development of our Fayetteville Shale play. Natural gas and oil prices are difficult to predict and subject to wide price fluctuations. As of February 22, 2011, we had hedged 186.2 Bcf of our remaining 2011 natural gas production, 186.1 Bcf of our 2012 natural gas production and 99.5 Bcf of our 2013 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 2010, our natural gas and oil production increased 35% to 404.7 Bcfe, up from 300.4 Bcfe in 2009 and was produced entirely by our properties in the United States.  The 104.3 Bcfe increase in our 2010 production resulted from a 106.7 Bcf increase in net production from our Fayetteville Shale play and a 1.0 Bcf increase in net production from our Appalachia properties, which more than offset a combined 3.4 Bcfe decrease in net production from our East Texas and Arkoma Basin properties.  Natural gas and oil production was up approximately 54% to 300.4 Bcfe in 2009, as compared to 2008, due to a 109.0 Bcf increase in net production from our Fayetteville Shale play as a result of our ongoing development program and increases in our East Texas and Arkoma net production of 3.3 Bcfe, which more than offset decreases in net production due to the sale of our Permian Basin and Gulf Coast properties. Our net production from the Fayetteville Shale play was 350.2 Bcf in 2010, up from 243.5 Bcf in 2009 and 134.5 Bcf in 2008.

We are targeting 2011 natural gas and oil production of 465 to 475 Bcfe, an increase of approximately 15 to 17% over our 2010 production. Approximately 410 to 420 Bcf of our 2011 targeted natural gas production is projected to come from our activities in the Fayetteville Shale play. Although we expect production volumes in 2011 to increase, we cannot guarantee our success in discovering, developing and producing reserves, including with respect to our Fayetteville Shale

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play. 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 12% to $4.64 per Mcf in 2010 and decreased 30% to $5.30 per Mcf in 2009. The decrease in the average price realized in 2010 compared to 2009 primarily reflects the decreased effect of our natural gas price hedging activities, which had a greater positive impact on our average realized gas price in 2009 (see additional discussion below). The decrease in the average price realized in 2009 compared to 2008 primarily reflected the decrease in average market prices, which was partially offset by the positive effect of our price hedging activities in 2009.  We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude 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 gas price $0.71 per Mcf in 2010, compared to an increase of $1.96 per Mcf in 2009 and a decrease of $0.21 per Mcf in 2008. Disregarding the impact of hedges, the average price received for our natural gas production in 2010 was $0.59 per Mcf higher than 2009 and $0.46 lower than the average monthly NYMEX settlement price, primarily due to locational market differentials. During 2009 and 2008, widening market differentials caused the difference in our annual average price received for our natural gas production to range from approximately $0.65 to $1.30 per Mcf lower than market prices. The discount was at its highest in late 2008, due to increased production in the Fayetteville Shale for which there was not sufficient transportation to other markets as a result of the delay in the completion of the Boardwalk Pipeline. Since the completion of the Boardwalk Pipeline, the locational differences in the market prices for our natural gas production have narrowed.  Assuming a NYMEX commodity price of $4.50 per Mcf for 2011, the average price received for our natural gas production is expected to be approximately $0.10 to $0.20 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges. At December 31, 2010, we had basis protected on approximately 111 Bcf of our 2011 expected natural gas production through financial hedging activities and physical sales arrangements at a basis differential to NYMEX gas prices of approximately $0.05 per Mcf. 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. For 2011, we expect our total gas sales discount to NYMEX to be $0.45 to $0.50 per Mcf.

In addition to the basis hedges discussed above, at December 31, 2010, we had NYMEX fixed price hedges in place on notional volumes of 66.5 Bcf of our remaining 2011 natural gas production at an average price of $5.76 per MMBtu and collars on place on notional volumes of 62.1 Bcf of our 2011 natural gas production at an average floor and ceiling price of $5.09 and $6.50 per MMBtu, respectively.

At December 31, 2010, we had NYMEX fixed price hedges in place on notional volumes of 68.1 Bcf and 36.5 Bcf of our 2012 and 2013 natural gas production, respectively, and collars in place on notional volumes of 80.5 Bcf of our 2012 natural gas production.

We realized an average price of $76.84 per barrel for our oil production for the year ended December 31, 2010, up approximately 40% from the prior year. The 2009 average realized price of $54.99 per barrel was down 49% from 2008. We did not hedge any of our 2010, 2009 or 2008 oil production.

Operating Income

Operating income from our E&P segment was $829.5 million in 2010 compared to an operating loss of $157.7 million in 2009. The operating loss in 2009 includes a $907.8 million 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 the first quarter of 2009. Excluding the $907.8 million non-cash ceiling test impairment, operating income in 2010 increased $79.4 million over 2009 as a result of the revenue impact of our 35% increase in production which was partially offset by a 12% decline in our average realized gas prices and a $217.8 million increase in operating costs and expenses that resulted from our significant production growth.  We recorded operating income from our E&P segment of $813.5 million for 2008. Excluding the $907.8 million non-cash ceiling test impairment in 2009, operating income decreased $63.4 million in 2009 compared to 2008 as a result of a 30% decline in our average realized gas prices and a $165.3 million increase in operating costs and

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expenses that resulted from our significant production growth, which was partially offset by the revenue impact of our 54% increase in production.

Operating Costs and Expenses

Lease operating expenses per Mcfe for the E&P segment were $0.83 in 2010, compared to $0.77 in 2009 and $0.89 in 2008. Lease operating expenses per unit of production increased in 2010 primarily due to increased gathering, compression and water disposal costs associated with our Fayetteville Shale operations. Lease operating expenses per unit of production decreased in 2009 compared to 2008 primarily due to the impact that lower natural gas prices had on the cost of compressor fuel in 2009. We expect our per unit operating cost for this segment to range between $0.88 and $0.92 per Mcfe in 2011.

General and administrative expenses for the E&P segment were $0.30 per Mcfe in 2010, down from $0.35 per Mcfe in 2009 and $0.41 per Mcfe in 2008. The decreases in general and administrative costs per Mcfe in 2010 and 2009 were due to the effects of our increased production volumes. In total, general and administrative expenses for the E&P segment were $120.3 million in 2010, $105.0 million in 2009 and $80.2 million in 2008. The increases in general and administrative expenses since 2008 were primarily a result of increased payroll, incentive compensation and employee-related costs associated with the expansion of our E&P operations due to the continued development of the Fayetteville Shale play. These increases accounted for $13.6 million, or 89%, of the 2010 increase and $19.7 million, or 79%, of the 2009 increase. We added 253 new E&P employees during 2010 compared to 261 employees added in 2009.

We expect our per unit cost for general and administrative expenses in 2011 to range between $0.32 and $0.36 per Mcfe.  The expected increase in our per unit general and administrative costs in 2011 is due to initial development of our Appalachian properties and increased compensation costs associated with ongoing development of our Fayetteville Shale play. Future changes in our general and administrative expenses for this segment are primarily dependent upon our salary costs, level of pension expense, amount of stock-based compensation expense and the amount of incentive compensation paid to our employees. 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 $0.11 in both 2010 and 2009 and were $0.13 in 2008. 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. We recognized $4.9 million, or $0.01 per Mcfe, in 2010 for severance tax refunds related to our East Texas production, compared to $3.3 million, or $0.01 per Mcfe, in 2009 and $5.0 million, or $0.03 per Mcfe, in 2008.  Effective January 1, 2009, the State of Arkansas increased the severance tax on natural gas wells, new discovery gas wells and gas wells that produce below a specified level.  The new severance tax rates increased the severance taxes we pay with respect to all of our production within Arkansas, including our Fayetteville Shale operations, and impacted our results of operations by increasing taxes other than income by $11.1 million, or $0.04 per Mcfe, in 2009 compared to 2008.

Our full cost pool amortization rate averaged $1.34 per Mcfe for 2010, $1.51 per Mcfe for 2009 and $1.99 per Mcfe for 2008. The decline in the average amortization rate for 2010 compared to 2009 was primarily the result of lower acquisition and development costs combined with the $907.8 million non-cash ceiling test impairment recorded in the first quarter of 2009 and the sale of certain East Texas oil and natural gas leases and wells in the second quarter of 2010 as the proceeds from the sale were appropriately credited to the full cost pool. The decline in the average amortization rate for 2009 compared to 2008 was primarily the result of the $907.8 million non-cash ceiling test impairment recorded in the first quarter of 2009 as well as sales of natural gas and oil properties in 2008, the proceeds of which were credited to the full cost pool. 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 play.

Unevaluated costs excluded from amortization were $712.1 million at the end of 2010 compared to $595.4 million at the end of 2009 and $540.6 million at the end of 2008.  Unevaluated costs excluded from amortization at the end of 2010 included $10.7 million related to our properties in Canada. The increase in unevaluated costs since December 31, 2009 primarily resulted from a $123.9 million increase in our undeveloped leasehold acreage and seismic costs, partially offset by a $7.7 million decrease in our drilling activity in our wells in progress. See Note 4 to the consolidated financial

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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.

Midstream Services

	Year Ended December 31,
	2010	2009	2008
	($ in millions)
Revenues – marketing	$    2,137.8	$      1,397.7	$      2,059.1
Revenues – gathering	$        316.0	$         205.6	$         114.9
Gas purchases – marketing	$    2,110.4	$      1,375.8	$      2,043.5
Operating costs and expenses	$        151.8	$         104.9	$           68.2
Operating income	$        191.6	$         122.6	$           62.3
Gas volumes marketed (Bcf)	495.8	382.5	258.0
Gas volumes gathered (Bcf)	588.3	387.1	224.1

Revenues

Revenues from our marketing activities were up 53% to $2,137.8 million for 2010 compared to 2009. The increase in marketing revenues resulted from increases in the volumes marketed combined with an increase in the prices received for volumes marketed. Revenues from our marketing activities were down 32% to $1,397.7 million for 2009 compared to 2008. The decrease in marketing revenues for 2009 resulted from a decrease in the prices received for volumes marketed and was partially offset by an increase in gas volumes marketed. The average price received for volumes marketed increased 18% in 2010 compared to 2009, and decreased 54% in 2009 compared to 2008. Volumes marketed increased 30% in 2010 compared to 2009, and increased 48% in 2009 compared to 2008. Of the total volumes marketed, production from our E&P operated wells accounted for 95% in 2010, 92% in 2009 and 96% in 2008. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expenses.

Revenues from our gathering activities were up 54% to $316.0 million for 2010 compared to 2009, and were up 79% to $205.6 million for 2009 compared to 2008. The increases in gathering revenues primarily resulted from a 52% increase in gas volumes gathered in 2010 compared to 2009 and a 73% increase in gas volumes gathered in 2009 compared to 2008. Substantially all of the increases in gathering revenues for 2010 and 2009 resulted from increases in the volumes gathered from our operated production from the Fayetteville Shale play. Gathering volumes, revenues and expenses for this segment are expected to continue to grow as production from our Fayetteville Shale play increases and as we develop our Appalachian properties.

Operating Income

Operating income from our Midstream Services segment increased 56% to $191.6 million in 2010 and increased 97% to $122.6 million in 2009. The increases in operating income reflect the substantial increases in gas volumes gathered and marketed which resulted primarily from our increased E&P production volumes. The increase in operating income for 2010 compared to 2009 was due to an increase of $110.4 million in gathering revenues and an increase of $5.5 million in the margin generated from our gas marketing activities, which were partially offset by a $46.9 million increase in operating costs and expenses, exclusive of purchased gas costs.  The increase in operating income for 2009 compared to 2008 was due to a $90.7 million increase in gathering revenues and an increase of $6.3 million in the margin generated from our gas marketing activities, which were partially offset by a $36.7 million increase in operating costs and expenses, exclusive of purchased gas costs.

The margin generated from gas marketing activities was $27.4 million for 2010, compared to $21.9 million for 2009 and $15.6 million for 2008.  Margins are primarily driven by volumes of 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 30% increase in volumes marketed in 2010 and a 48% increase in volumes marketed in 2009, 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 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.

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Natural Gas Distribution

	Year Ended December 31,
	2010	2009	2008(1)
	($ in thousands, except per Mcf amounts)
Revenues	$                   —	$                   —	$          117,710
Gas purchases	$                   —	$                   —	$            79,120
Operating costs and expenses	$                   —	$                   —	$            27,857
Operating income	$                   —	$                   —	$            10,733
Sales and end-use transportation deliveries (Bcf)	—	—	14.5
Sales customers at year-end	—	—	—
Average sales rate per Mcf	—	—	$ 11.61
Annual heating weather – degree days	—	—	—
Percent of normal	—	—	—

(1)

The 2008 column reflects results for the first six months of 2008, prior to the sale of the utility.

Effective July 1, 2008, we sold all of the capital stock of Arkansas Western Gas for $223.5 million (net of expenses related to the sale). In order to receive regulatory approval for the sale and certain related transactions, we paid $9.8 million to Arkansas Western Gas for the benefit of its customers.  A gain on the sale of $57.3 million ($35.4 million after-tax) was recorded in the third quarter of 2008. As a result of the sale of Arkansas Western Gas, we no longer have any natural gas distribution operations.  The 2008 column in the table above reflects results for the first six months of 2008, which represents the period of our ownership of Arkansas Western Gas in 2008.

Interest Expense and Interest Income

Interest expense, net of capitalization, was $26.2 million in 2010, an increase of $7.5 million compared to 2009, primarily due to a decrease in capitalized interest. Interest capitalized decreased to $32.9 million in 2010 from $40.2 million in 2009, primarily due to a decrease in our weighted average interest rate during 2010 as a result of the increase in our average borrowed balance under our credit facility, which had a weighted average interest rate of 1.06% for 2010.

In 2009, interest expense, net of capitalization, was $18.6 million, a decrease of $10.3 million compared to 2008 primarily due to an increase in capitalized interest and a decrease in our weighted average interest rate during 2009. Our weighted average interest rate decreased during 2009 as a result of the redemption of our 7.625% Senior Notes and an increase in our borrowings under our credit facility, which had a 2009 weighted average interest rate of 1.16%.  Interest capitalized increased to $40.2 million in 2009 from $34.5 million in 2008, as our costs excluded from amortization in the E&P segment increased along with the overall increased level of our capital investments.

During 2010, 2009 and 2008, we earned interest income of $0.3 million, $0.4 million and $4.4 million, respectively, related to our cash investments. These amounts are recorded in Other Income on the Statements of Operations.

Income Taxes

Our effective tax rates were 39.3% in 2010, 31.5% in 2009 and 38.2% in 2008.  The decrease in our 2009 effective tax rate resulted from our permanent tax differences comprising a larger percentage of our before tax operating results than in 2008. Our effective tax rate, excluding the $907.8 million non-cash ceiling test impairment of our natural gas and oil properties, would have been 39.0% for 2009. 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.    

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 Stock-Based Compensation Expense

We recognized expense of $9.8 million and capitalized $6.8 million for stock-based compensation in 2010, compared to $10.2 million expensed and $5.9 million capitalized in 2009 and $7.6 million expensed and $3.9 million capitalized in 2008. We refer you to Note 13 to the consolidated financial statements for additional discussion of our equity based compensation plans.  

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on internally-generated funds, our Credit Facility and funds accessed through debt and equity markets as our primary sources of liquidity.

During 2011, assuming natural gas prices remain at current levels, we expect to draw on a portion of the funds available under the Credit Facility to fund our planned capital investments (discussed below under “Capital Investments”), which 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 Credit Facility.

Net cash provided by operating activities increased 21% to $1.6 billion in 2010, due to an increase in net income adjusted for non-cash expenses and changes in working capital accounts.  Net cash provided by operating activities increased 17% to $1.4 billion in 2009, due to an increase in net income adjusted for non-cash expenses which was partially offset by changes in working capital accounts.  For 2010, requirements for our capital investments were funded from our cash generated by operating activities, borrowings under our Credit Facility and the proceeds from the sale of certain East Texas oil and natural gas properties.  Net cash from operating activities provided 79% of our cash requirements for capital investments in 2010, 76% in 2009 and 66% in 2008.

At December 31, 2010, our capital structure consisted of 27% debt and 73% equity. We believe that our operating cash flow and available funds under our Credit Facility will be adequate to meet our capital and operating requirements for 2011. The credit status of the financial institutions participating in our Credit Facility could adversely impact our ability to borrow funds under the 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.

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 price received 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.

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Capital Investments

Our capital investments were $2.1 billion in 2010, up from $1.8 billion in 2009. Capital investments include an increase of $14.4 million in 2010, an increase of $12.2 million in 2009 and an increase of $36.2 million in 2008 related to the change in accrued expenditures between years. Our E&P segment investments in 2010 were $1.8 billion, compared to $1.6 billion in 2009 and $1.6 billion in 2008.

	2010	2009	2008
	(in thousands)
Exploration and production
Exploration and development	$  1,771,156	$     1,556,260	$     1,569,089
Drilling rigs and related equipment	4,362	9,190	26,739
	1,775,518	1,565,450	1,595,828
Midstream services	271,316	214,208	183,021
Natural gas distribution	—	—	3,574	(1)
Other	73,231	29,459	13,745
	$  2,120,065	$     1,809,117	$     1,796,168

(1)

Natural gas distribution capital investments are through June 30, 2008, prior to the sale of this segment.

Our capital investments for 2011 are planned to be $1.9 billion, consisting of $1.6 billion for E&P, $225 million for Midstream Services and $60 million for corporate and other purposes. Of the approximate $1.6 billion, we expect to allocate approximately $1.15 billion to our Fayetteville Shale play. Our planned level of capital investments in 2011 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 2011 capital investment program is expected to be funded through cash flow from operations and borrowings under our Credit Facility. The planned capital program for 2011 is flexible and can be modified, including downward, if the low natural gas price environment persists for an extended period of time.  We will reevaluate our proposed investments as needed to take into account prevailing market conditions and, if natural gas prices change significantly in 2011, we could change our planned investments.

Financing Requirements

Our total debt outstanding was $1,094.2 million at December 31, 2010, compared to $998.7 million at December 31, 2009.

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 Company’s agreement with its existing or additional lenders. We had $421.2 and $324.5 million outstanding under its revolving credit facility at December 31, 2010 and December 31, 2009, respectively.

The interest rate on our Credit Facility is calculated based upon our public debt rating and is currently 200 basis points over LIBOR. Our publicly traded notes are rated BBB- by Standard and Poor’s and we have a Corporate Family Rating of Ba1 by Moody’s. Any downgrades in our public debt ratings could increase our cost of funds under the Credit Facility.

Our Credit Facility contains covenants which impose certain restrictions on us. Under the 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 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 Credit Facility, our capital structure at December 31, 2010 would have been 24% debt and 76% equity. We were in compliance with all of the covenants of our Credit Facility at December 31, 2010. 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 Credit Facility, we would have to decrease our capital investment plans.

At December 31, 2010, our capital structure consisted of 27% debt and 73% equity compared to 30% debt and 70% equity at December 31, 2009.  Our debt percentage of total capital at December 31, 2010 decreased in 2010, primarily due to our profitable results and the minimal funding of our capital investments and operational needs through debt.  Equity at

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December 31, 2010 included an accumulated other comprehensive gain of $96.5 million related to our hedging activities and a loss for $12.5 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 at December 31, 2010 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 22, 2011, we had NYMEX commodity price hedges in place on 186.2 Bcf, or approximately 40% of our targeted 2011 natural gas production, 186.1 Bcf of our expected 2012 natural gas production and 99.5 Bcf of our expected 2013 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

In December 2006, we entered into a sale and leaseback transaction pursuant to which we sold 13 operating drilling rigs, 2 rigs yet to be delivered and related equipment and then leased such drilling rigs and equipment under leases that expire on January 1, 2015. Subject to certain conditions, we have options to purchase the rigs and related equipment from the lessors either at the end of the 84^th month of the lease term at an agreed upon price or at the end of the lease term for the then fair market value.  Additionally, we have the option to renew each lease for a negotiated renewal term at a periodic rental equal to the fair market rental value of the rigs as determined at the time of renewal. In 2007, we sold and leased back additional drilling rig equipment receiving proceeds of $3.1 million, and leased an additional $5.9 million of drilling rig equipment, under similar terms as the 2006 transaction. In December 2008, pursuant to the terms of the lease, one of the lessors required us to pay $10.5 million, the stipulated loss value, for a rig that suffered a casualty. The payment of the stipulated loss value is treated as a purchase of the rig and is reflected in capital investments within the Statement of Cash Flows. Our current aggregate annual rental payment for drilling rigs and related equipment under the leases is approximately $19.4 million.

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 at December 31, 2010, 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)	$ 1,791,578	$      163,765	$      390,484	$      386,102	$      851,227
Debt	1,094,200	1,200	423,600	2,400	667,000
Interest on senior notes	377,489	53,958	100,809	99,843	122,879
Operating leases(2)	291,473	64,128	117,819	78,728	30,798
Operating agreements(3)	287,066	145,769	141,297	—	—
Compression services(4)	65,309	28,235	30,967	6,107	—
Purchase obligations(5)	48,784	48,784	—	—	—
Other obligations(6)	184,353	39,697	61,286	4,482	78,888
	$ 4,140,252	$      545,536	$   1,266,262	$      577,662	$   1,750,792

(1)

As of December 31, 2010, our Midstream Services segment had commitments for demand transportation charges on various pipelines, including approximately $1.0 billion related to the FEP pipeline and $0.7 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 2019. Additionally, this includes $77.5 million for leases of 14 drilling rigs and related equipment through 2014.

(3)

As of December 31, 2010, our E&P segment had commitments for approximately $282.6 million to companies for fracture stimulation services, which are cancellable under certain circumstances.  

(4)

As of December 31, 2010, our Midstream Services segment had commitments of approximately $60.0 million and our E&P segment had commitments of approximately $5.3 million for compression services associated primarily with our Fayetteville Shale play and our Overton operations.

(5)

Purchase obligations consist of outstanding purchase orders under existing agreements.  As of December 31, 2010, our Midstream Services segment had outstanding purchase obligations of $38.1 million relating to compression units.

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(6)

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 $88.6 million for asset retirement obligations primarily relating to oil and gas properties, approximately $11.5 million for funding of benefit plans, approximately $10.8 million for various information technology support and data subscription agreements, approximately $6.9 million for insurance premium financing and approximately $6.4 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 $11.3 million to our pension plans and $0.1 million to our postretirement benefit plan in 2011. For 2010, we contributed $9.7 million to our pension plans and contributed less than $0.1 million to our postretirement benefit plan. At December 31, 2010 we recognized a liability of $15.9 million as a result of the underfunded status of our pension and other postretirement benefit plans compared to a liability of $13.3 million at December 31, 2009. 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.

Working Capital

We maintain access to funds that may be needed to meet capital requirements through our Credit Facility described in “Financing Requirements” above. We had negative working capital of $113.1 million at December 31, 2010 and positive working capital of $28.1 million at December 31, 2009. Current assets increased $16.4 million during 2010 primarily due to an $88.5 increase in accounts receivable, which was partially offset by a $32.7 million decrease in our current hedging asset and a $19.2 million decrease in our net current deferred income tax asset. Current liabilities increased $157.6 million as a result of a $69.2 million increase in accounts payable, a $44.1 million increase in our current deferred income taxes related to our hedging activities and a $29.3 million increase in advances from partners.  

Natural Gas in Underground Storage

We record our natural gas stored in inventory that is owned by the E&P segment at the lower of weighted average cost or market. We recorded a $4.3 million non-cash natural gas inventory impairment charge for the three months ended March 31, 2009 to reduce the current portion of our natural gas inventory to the lower of cost or market. 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 result in additional write-downs 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 reserves. 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 percent (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.

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The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Effective December 31, 2009, companies using the full cost method were 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. For quarter and annual periods ending prior to December 31, 2009, prices in effect at the date of each accounting quarter, including the impact of derivatives qualifying as cash flow hedges, were required to be used.

Using the 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 and $75.96 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 did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2010. Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $164.4 million at December 31, 2010. Decreases in average market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and service costs could result in future ceiling test impairments.  At December 31, 2009, the ceiling value of the Company’s reserves was calculated based upon year-end quoted market prices of $3.87 per Mcf for Henry Hub natural gas and $57.65 per barrel for West Texas Intermediate oil, and at December 31, 2008, the ceiling value of the Company’s reserves was calculated based upon year-end quoted market prices of $5.71 per Mcf for Henry Hub natural gas and $41.00 per barrel for West Texas Intermediate oil. 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 March 31, 2009, the net capitalized costs of our natural gas and oil properties exceeded the ceiling by approximately $558.3 million (net of tax) and resulted in a non-cash ceiling test impairment in the first quarter of 2009.

All of our costs directly associated with the acquisition and evaluation of properties in New Brunswick, Canada relating to our exploration program at December 31, 2010 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 Vice President-EP&A, who was the technical person primarily responsible for the preparation of our reserve estimates, and has over twenty years of experience in petroleum engineering, including over fifteen years in estimating oil and natural gas reserves.  On our behalf, the Vice President-EP&A 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 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 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 and final authority over the estimates of our proved reserves rests with our Board of Directors.  

In each of the past three years, revisions to our proved reserve estimates represented no greater than 7% of our total proved reserve estimates, which we believe is indicative of the effectiveness of our internal controls. 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 55% of our total reserve base at December 31, 2010. 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

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major properties that account for approximately 85% 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 85% present value as of December 31, 2010, accounted for approximately 88% of our total proved reserves and approximately 95% 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. For the year-ended December 31, 2010, on January 27, 2011, NSAI issued its audit opinion as to the reasonableness of our reserve estimates, stating that our estimated proved oil and 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.

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 at December 31, 2010, were $3,013.8 million and 4,937.3 Bcfe, respectively. An assumed decrease of $1.00 per Mcf in the average 2010 natural gas price used to price our reserves would have resulted in an approximate $1,519.7 million decline in our standardized measure and an approximate decrease of 131 Bcfe of our reported reserves. The decline in reserve quantities, assuming this decrease in natural gas price, would have the impact of increasing our unit of production amortization of the full cost pool. 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 crude 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.  However, only 45%  of our 2009 production and 30% of our 2010 production was hedged due to credit and overall market events of late 2008 and in 2009 as well as the low commodity price environment throughout 2009 and 2010. The primary market risks related to our derivative contracts are the volatility in market prices and basis differentials for natural gas and crude 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, 2010, we recorded an unrealized gain of $11.4 million related to basis differential swaps that did not qualify for hedge accounting in addition to a $6.8 million loss related to the change in 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

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funds invested. For the December 31, 2010 benefit obligation and the periodic benefit cost to be recorded in 2011, the discount rate assumed is 5.50%. For the 2011 periodic benefit cost, the expected return assumed is 7.50%. This compares to a discount rate of 5.75% and an expected return of 7.50% used in 2010.  

Using the assumed rates discussed above, we recorded pension expense of $9.4 million in 2010 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 2010 pension expense:

	Increase (Decrease) of Annual Pension Expense
	50 Basis Point Increase	50 Basis Point Decrease
	(in thousands)
Discount rate	$               (463)	$                 504
Expected long-term rate of return	$               (234)	$                 234

At December 31, 2010, we recognized a liability of $15.9 million, compared to $13.3 million at December 31, 2009, related to our pension and other postretirement benefit plans. During 2010, we also made cash payments totaling $9.7 million to fund our pension and other postretirement benefit plans. In 2011, we expect to make cash payments totaling $11.4 million to fund our pension and other postretirement benefit plans and recognize pension expense of $10.2 million and a postretirement benefit expense of $1.9 million.

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.  At December 31, 2010 and 2009, the current portion of natural gas in storage was $10.0 million and $9.2 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 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 result in a write-down of our natural gas in storage carrying cost.

New Accounting Standards Implemented in this Report

On December 31, 2009, the Company implemented certain provisions of FASB ASC 932, “Extractive Activities-Oil and Gas,” as updated by Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932)” (“FASB ASC 932”), which (a) expand the definition of oil- and gas-producing activities; (b) require energy companies to value their proved reserves by averaging the price from the first day of each month from the previous 12 months instead of using a year-end price; and (c) allow for additional drilling locations to be classified as proved undeveloped reserves assuming such locations are supported by reliable technologies. The Company accounted for the FASB ASC 932 changes as a change in accounting principle that is inseparable from a change in accounting estimate and will account for the change prospectively. The Company is not able to disclose the effects resulting from the implementation of these changes on the amount of proved reserves and disclosed quantities because personnel and time constraints made it infeasible for the Company to perform a second internal reserve estimation process under the prior standards on its approximately 4,850 properties.

On January 1, 2010, the Company implemented certain provisions of Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) Topic 810, “Consolidation.” The new provisions (a) require a qualitative rather than a quantitative approach to determining the primary beneficiary of a variable interest entity (“VIE”); (b) amend certain guidance pertaining to the determination of the primary beneficiary when related parties are involved; (c) amend certain guidance for determining whether an entity is a VIE; and (d) require continuous assessments of whether an enterprise is the primary beneficiary of a VIE. The implementation did not have an impact on the Company’s results of operations or financial condition.

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On January 1, 2010, the Company implemented certain provisions of Accounting Standards Update No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements” (“Update 2010-06”). Update 2010-06 requires the Company to (a) provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy; (b) provide a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method; and (c) provide fair value measurement disclosures for each class of financial assets and liabilities. The implementation did not have an impact on the Company’s results of operations or financial condition.

On December 31, 2010, the Company implemented provisions of Accounting Standards Update (ASU) No. 2010-25, Plan Accounting—Defined Contribution Pension Plans (Topic 962): Reporting Loans to Participants by Defined Contribution Pension Plans (“Update 2010-25”). Update 2010-25 amends FASB ASC 962-325 to specify that loans to pension plan participants be classified as notes receivable, segregated from the plan's investments and measured at their unpaid principal balance plus any accrued but unpaid interest. The implementation did not have a material impact on the Company’s results of operations or financial condition.

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

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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 of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking 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 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 formation;

·

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”).

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,

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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 investments, 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.

At December 31, 2010, approximately 45% 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 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.

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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 crude oil swap agreements and options and interest 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 at December 31, 2010.  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, 2010. At December 31, 2010, we had $1,094.2 million of total debt with a weighted average interest rate of 4.93% and we had $421.2 million of indebtedness outstanding under our 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.

										Fair
	Expected Maturity Date									Value
	2011	2012		2013		2014	2015	Thereafter	Total	12/31/10
	($ in millions)
Fixed Rate	$         1.2	$        1.2			$        1.2	$        1.2	$        1.2	$     667.0	$    673.0	$     761.4
Average Interest Rate	7.15%	7.15%			7.15%	7.15%	7.15%	7.47%	7.47%	—
Variable Rate	—	$    421.2	(1)		—	—	—	—	$    421.2	$     421.2
Average Interest Rate	—	0.89%			—	—	—	—	0.89%	—

(1)

In February 2011, we amended and restated our unsecured revolving credit facility, extending the maturity date to February 2016.  In connection with the amendment and restatement, the interest rate under the facility increased to 2.26%.

Commodities Risk

We use over-the-counter natural gas and crude 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 index-related 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 crude 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 non-performance 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 non-

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performance and do not anticipate any losses given the information we have currently. However, given the current volatility in the financial markets, 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. At December 31, 2010, the fair value of our financial instruments related to natural gas production and gas-in-storage was a $157.2 million asset.

		Weighted	Weighted	Weighted	Weighted
		Average	Average	Average	Average	Fair value at
		Price to be	Floor	Ceiling	Basis	December 31,
	Volume	Swapped	Price	Price	Differential	2010
	(Bcf)	($/MMBtu)	($/MMBtu)	($/MMBtu)	($/MMBtu)	($ in millions)
Natural Gas:
Fixed Price Swaps:
2011	66.8(1)	$               5.76	$                  —	$                  —	$                  —	$                   79.9
2012	68.1	$               5.00	$                  —	$                  —	$                  —	$                   (5.3)
2013	36.5	$               5.00	$                  —	$                  —	$                  —	$                 (11.7)
Floating Price Swaps:
2011	2.5	$               4.79	$                  —	$                  —	$                  —	$                   (0.9)
2012	4.4	$               5.67	$                  —	$                  —	$                  —	$                   (3.1)
Costless-Collars:
2011	62.1	$                  —	$               5.09	$               6.50	$                  —	$                   45.0
2012	80.5	$                  —	$               5.50	$               6.67	$                  —	$                   55.3
Basis Swaps:
2011	12.0	$                  —	$                  —	$                  —	$             (0.28)	$                   (2.0)

(1)

Includes fixed-price swaps for 0.3 Bcf relating to future sales from our underground storage facility that have a fair value asset of approximately $0.3 million.

At December 31, 2010, our basis swaps did not qualify for hedge accounting treatment. Changes in the fair value of derivatives that do not qualify as hedges are recorded in gas and oil sales. At December 31, 2010, we had outstanding fixed-price basis differential swaps on 12.0 Bcf of 2011 natural gas production. For the year ended December 31, 2010, we recorded an unrealized gain of $11.4 million related to the differential swaps that did not qualify for hedge accounting treatment and a loss of $6.8 million related to the change in 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.

At December 31, 2009, we had outstanding fixed-price basis differential swaps on 46.5 Bcf of 2010 and 9.0 Bcf of 2011 natural gas production that did not qualify for hedge accounting treatment. 

Subsequent to December 31, 2010 and prior to February 22, 2011, we hedged an additional 57.6 Bcf of 2011 natural gas production using fixed-price swaps at an average price of $5.00 per MMBtu, 37.5 Bcf of 2012 natural gas production at an average price of $5.00 per MMBtu and 63.0 Bcf of 2013 natural gas production at an average price of $5.00 per MMBtu.

Midstream Services

At December 31, 2010, our Midstream Services segment had outstanding fair value hedges in place on 0.1 Bcf for 2011 and 0.1 Bcf for 2012.  These hedges are a mixture of fixed-price swap purchases and sales relating to our gas marketing activities. These hedges have contract months from January 2011 through March 2012 and have a net fair value asset of $0.5 million as of December 31, 2010.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Management’s Report on Internal Control Over Financial Reporting	64
Report of Independent Registered Public Accounting Firm	65
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008	66
Consolidated Balance Sheets as of December 31, 2010 and 2009	67
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008	68
Consolidated Statements of Equity for the fiscal years ended December 31, 2010, 2009 and 2008	69
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2010,                                     2009 and 2008	70
Notes to Consolidated Financial Statements, December 31, 2010, 2009 and 2008	71

63 SWN

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 Exchange Act.  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, 2010.  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.

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 this assessment, our management, including our Chief Executive Officer and our Chief Financial Officer, concluded, that as of December 31, 2010, our internal control over financial reporting was effective based on those criteria.   

The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report below.

64 SWN

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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  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 the accompanying Management's Report on Internal Control over Financial Reporting.  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.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it estimates the quantities of oil and natural gas reserves in 2009 and the limitation on its capitalized costs as of December 31, 2009.  

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

Tulsa, Oklahoma

February 24, 2011

65 SWN

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the years ended December 31,
	2010	2009	2008
	(in thousands, except share/per share amounts)
Operating Revenues:
Gas sales	$     1,856,241	$    1,578,256	$    1,500,408
Gas marketing	615,913	488,663	719,909
Oil sales	13,111	6,843	41,240
Gas gathering	122,912	74,281	41,748
Other	2,486	(2,264)	8,247
	2,610,663	2,145,779	2,311,552
Operating Costs and Expenses:
Gas purchases – midstream services	611,161	482,836	710,129
Gas purchases – gas distribution	—	—	61,439
Operating expenses	191,771	136,541	107,577
General and administrative expenses	145,563	122,618	101,959
Depreciation, depletion and amortization	590,332	493,658	414,408
Impairment of natural gas and oil properties	—	907,812	—
Taxes, other than income taxes	50,608	37,280	29,272
	1,589,435	2,180,745	1,424,784
Operating Income (Loss)	1,021,228	(34,966)	886,768
Interest Expense:
Interest on debt	57,144	55,581	61,152
Other interest charges	1,935	3,266	2,284
Interest capitalized	(32,916)	(40,209)	(34,532)
	26,163	18,638	28,904
Other Income, Net	427	1,449	4,404
Gain on Sale of Utility Assets	—	—	57,264
Income (Loss) Before Income Taxes	995,492	(52,155)	919,532
Provision (Benefit) for Income Taxes:
Current	11,939	(64,969)	122,000
Deferred	379,720	48,606	228,999
	391,659	(16,363)	350,999
Net Income (Loss)	603,833	(35,792)	568,533
Less: Net Income (Loss) Attributable to Noncontrolling Interest	(285)	(142)	587
Net Income (Loss) Attributable to Southwestern Energy	$        604,118	$        (35,650)	$       567,946
Earnings Per Share:
Net income (loss) attributable to Southwestern Energy stockholders-Basic	$              1.75	$            (0.10)	$             1.66
Net income (loss) attributable to Southwestern Energy stockholders-Diluted	$              1.73	$            (0.10)	$             1.64
Weighted Average Common Shares Outstanding:
Basic	345,581,568	343,420,568	341,621,814
Effect of:
Stock options	3,512,242	—	4,237,263
Restricted stock awards	216,857	—	386,861
Diluted	349,310,666	343,420,568	346,245,938

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2010	2009
ASSETS	(in thousands)
Current Assets:
Cash and cash equivalents	$            16,055	$           13,184
Accounts receivable	351,573	263,076
Inventories	35,098	30,009
Hedging asset	130,412	163,069
Other	47,755	95,163
Total current assets	580,893	564,501
Property and Equipment:
Natural gas and oil properties, using the full cost method, including $712.1 million in 2010 and $595.4 million in 2009 excluded from amortization	7,749,863	6,329,117
Gathering systems	817,465	547,637
Other	413,557	305,030
Total property and equipment	8,980,885	7,181,784
Less: Accumulated depreciation, depletion and amortization	3,682,688	3,054,531
	5,298,197	4,127,253
Other Assets	138,373	78,496
TOTAL ASSETS	$       6,017,463	$      4,770,250
LIABILITIES AND EQUITY
Current Liabilities:
Current portion of long-term debt	$              1,200	$             1,200
Accounts payable	473,890	404,695
Taxes payable	50,051	25,500
Interest payable	19,954	19,775
Advances from partners	81,705	52,406
Hedging liability	7,685	20,052
Current deferred income taxes	44,089	—
Other	15,409	12,788
Total current liabilities	693,983	536,416
Long-Term Debt	1,093,000	997,500
Other Liabilities:
Deferred income taxes	1,130,292	811,902
Long-term hedging liability	40,188	3,057
Pension and other postretirement liabilities	15,777	12,630
Other long-term liabilities	79,347	67,764
	1,265,604	895,353
Commitments and Contingencies
Equity:
Southwestern Energy stockholders’ equity:
Common stock, $0.01 par value; authorized 1,250,000,000 shares in 2010 and 540,000,000 in 2009; issued 347,733,839 shares in 2010 and 346,081,210 in 2009	3,477	3,461
Additional paid-in capital	862,423	833,494
Retained earnings	2,018,445	1,414,327
Accumulated other comprehensive income	83,975	84,276
Common stock in treasury, 156,636 shares in 2010 and 203,830 in 2009	(3,444)	(4,333)
Total Southwestern Energy stockholders’ equity	2,964,876	2,331,225
Noncontrolling interest	—	9,756
Total Equity	2,964,876	2,340,981
TOTAL LIABILITIES AND EQUITY	$       6,017,463	$      4,770,250

The accompanying notes are an integral part of these consolidated financial statements.

67 SWN

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the years ended December 31,
	2010	2009	2008
	(in thousands)
Cash Flows From Operating Activities
Net income (loss)	$       603,833	$        (35,792)	$       568,533
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	591,943	495,291	416,151
Impairment of natural gas and oil properties	—	907,812	—
Deferred income taxes	379,720	48,606	228,999
Gain on sale of utility assets	—	—	(57,264)
Unrealized (gain) loss on derivatives	(4,289)	5,309	4,644
Stock-based compensation expense	9,820	10,177	7,663
Other	(1,348)	9,625	(1,232)
Change in assets and liabilities:
Accounts receivable	(88,488)	(8,519)	(60,117)
Inventories	5,099	11,779	(39,475)
Accounts payable	65,782	(21,739)	70,975
Taxes payable	24,551	(6,451)	20,855
Interest payable	179	(1,082)	18,522
Advances from partners	29,299	(18,197)	38,418
Deferred tax benefit – stock options	—	—	(43,107)
Other assets and liabilities	26,484	(37,443)	(12,756)
Net cash provided by operating activities	1,642,585	1,359,376	1,160,809
Cash Flows From Investing Activities
Capital investments	(2,073,174)	(1,780,165)	(1,755,888)
Proceeds from sale of property and equipment	350,227	818	750,310
Net proceeds from sale of utility assets	—	—	213,721
Transfers to restricted cash	(356,035)	—	—
Transfers from restricted cash	356,035	—	—
Other	(2,684)	(1,257)	(221)
Net cash used in investing activities	(1,725,631)	(1,780,604)	(792,078)
Cash Flows From Financing Activities
Payments on current portion of long-term debt	(1,200)	(61,200)	(1,200)
Payments on revolving long-term debt	(2,958,100)	(1,371,700)	(1,843,600)
Borrowings under revolving long-term debt	3,054,800	1,696,200	1,001,400
Proceeds from issuance of long-term debt	—	—	600,000
Debt issuance costs and revolving credit facility costs	—	—	(8,895)
Deferred tax benefit – stock options	—	—	43,107
Change in bank drafts outstanding	(11,545)	(30,920)	31,397
Proceeds from exercise of common stock options	3,897	5,755	3,505
Other	(1,612)	—	—
Net cash provided by (used in) financing activities	86,240	238,135	(174,286)
Effect of exchange rate changes on cash	(323)	—	—
Increase (decrease) in cash and cash equivalents	2,871	(183,093)	194,445
Cash and cash equivalents at beginning of year	13,184	196,277	1,832	(1)
Cash and cash equivalents at end of year	$         16,055	$         13,184	$       196,277

(1)

Cash and cash equivalents at the beginning of 2008 include amounts classified as “held for sale.”  See Note 2 for additional information.

The accompanying notes are an integral part of these consolidated financial statements.

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

STATEMENTS OF EQUITY

	Southwestern Energy Stockholders
					Accumulated
	Common Stock(1)		Additional		Other	Common
	Shares		Paid-In	Retained	Comprehensive	Stock in	Noncontrolling
	Issued	Amount	Capital(1)	Earnings	Income	Treasury	Interest	Total
	(in thousands)
Balance at December 31, 2007	341,578	$      3,416	$  752,369	$    882,031	$          13,348	$     (4,664)	$         10,570	$    1,657,070
Comprehensive income (loss):
Net Income (loss)	—	—	—	567,946	—	—	587	568,533
Change in derivatives	—	—	—	—	234,259	—	—	234,259
Change in pension and other postretirement liabilities	—	—	—	—	58	—	—	58
Total comprehensive income (loss)							587	802,850
Deferred tax benefit – stock options	—	—	43,107	—	—	—	—	43,107
Stock-based compensation	—	—	12,415	—	—	—	—	12,415
Exercise of stock options	1,690	17	3,488	—	—	—	—	3,505
Issuance of restricted stock	417	4	(4)	—	—	—	—	—
Cancellation of restricted stock	(66)	(1)	1	—	—	—	—	—
Issuance of stock awards	6	—	116	—	—	—	—	116
Treasury stock – non-qualified plan	—	—	—	—	—	(76)	—	(76)
Distributions to noncontrolling interest in partnership	—	—	—	—	—	—	(1,024)	(1,024)
Balance at December 31, 2008	343,625	$      3,436	$  811,492	$ 1,449,977	$        247,665	$     (4,740)	$         10,133	$    2,517,963
Comprehensive income (loss):
Net Income (loss)	—	—	—	(35,650)	—	—	(142)	(35,792)
Change in derivatives	—	—	—	—	(163,591)	—	—	(163,591)
Change in pension and other postretirement liabilities	—	—	—	—	202	—	—	202
Total comprehensive income (loss)							(142)	(199,181)
Stock-based compensation	—	—	16,003	—	—	—	—	16,003
Exercise of stock options	2,153	22	5,733	—	—	—	—	5,755
Issuance of restricted stock	312	3	(3)	—	—	—	—	—
Cancellation of restricted stock	(10)	—	—	—	—	—	—	—
Issuance of stock awards	1	—	65	—	—	—	—	65
Treasury stock – non-qualified plan	—	—	204	—	—	407	—	611
Distributions to noncontrolling interest in partnership	—	—	—	—	—	—	(235)	(235)
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
Change in derivatives	—	—	—	—	1,175	—	—	1,175
Change in pension and other postretirement liabilities	—	—	—	—	(1,458)	—	—	(1,458)
Currency translation adjustment	—	—	—	—	(18)	—	—	(18)
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

(1)

2007 restated to reflect the two-for-one stock split effected on March 25, 2008.

The accompanying notes are an integral part of these consolidated financial statements.

69 SWN

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	For the years ended December 31,
	2010	2009	2008
	(in thousands)
Net income (loss)	$     603,833	$        (35,792)	$        568,533
Change in derivatives:
Reclassification to earnings (1)	(182,619)	(376,259)	45,830
Ineffectiveness (2)	4,145	(6,031)	4,319
Change in fair value of derivative instruments (3)	179,649	218,699	184,110
Total change in derivatives	1,175	(163,591)	234,259
Change in pension and other postretirement liabilities:
Sale of utility – divestiture, curtailment and settlement (4)	—	—	9,040
Change in value of pension and other postretirement liabilities (5)	(1,458)	202	(8,982)
Total change in pension and other postretirement liabilities	(1,458)	202	58
Change in currency translation adjustment	(18)	—	—
Comprehensive income (loss)	603,532	(199,181)	802,850
Less: comprehensive income (loss) attributable to the noncontrolling interest	(285)	(142)	587
Comprehensive income (loss) attributable to Southwestern Energy	$     603,817	$      (199,039)	$        802,263

(1) Net of ($118.9), ($234.1) and $28.1 million in taxes for the years ended December 31, 2010, 2009 and 2008, respectively.

(2) Net of $2.6, ($3.8) and $2.6 million in taxes for the years ended December 31, 2010, 2009 and 2008, respectively.

(3) Net of $119.5, $137.7 and $112.8 million in taxes for the years ended December 31, 2010, 2009 and 2008, respectively.

(4) Net of $5.5 million in taxes for the year ended December 31, 2008.

(5) Net of ($1.3), $0.2 and ($5.6) million in taxes for the years ended December 31, 2010, 2009 and 2008, respectively.

The accompanying notes are an integral part of these consolidated financial statements.

70 SWN

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 primarily focused on the exploration and production of natural gas. 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 on the development of an unconventional natural gas play in Arkansas. The Company also is actively engaged in E&P activities in Texas, Pennsylvania and to a lesser extent in Oklahoma.  In 2010, the Company commenced an exploration program in New Brunswick, Canada, its first operations outside of the United States.  Southwestern’s marketing and gas gathering business (“Midstream Services”) is located in the core areas of its E&P operations. In the past, the Company also engaged in natural gas distribution and transmission through a wholly-owned utility subsidiary, Arkansas Western Gas Company (“Arkansas Western Gas”), which operated in northern Arkansas. Effective July 1, 2008, the Company sold all of its stock in Arkansas Western Gas and, as a result, no longer has any natural gas distribution operations.

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.

Prior to its July 1, 2008 disposition date, the cash flows from natural gas sales to Arkansas Western Gas were deemed “significant” under accounting rules. Therefore, the results of operations for Arkansas Western Gas are included in the consolidated statements of operations and are not presented as “discontinued operations” for the applicable periods through July 1, 2008.

Certain reclassifications have been made to the prior years financial statements to conform to the 2010 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 accordance with GAAP, the Company recognized profit on intercompany sales of natural gas delivered to storage by its utility subsidiary, Arkansas Western Gas, prior to the sale of this segment.  In 2010, the Company purchased the non-controlling interest in Overton Partners, L.P.  

Revenue Recognition

Gas and oil sales. 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 revenue interest of sales from its properties.  Accordingly, revenue is not recognized for deliveries in excess of the Company’s net revenue interest, while revenue is recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. At December 31, 2010, the Company had overproduction of 3.9 Bcf valued at $13.3 million and underproduction of 3.7 Bcf valued at $12.8 million. At December 31, 2009, the Company had overproduction of 2.2 Bcf valued at $6.4 million and underproduction of 2.6 Bcf valued at $8.2 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.

71 SWN

Gas gathering. The Company gathers its natural gas, as well as some 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.

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 include gains of $2.5 million, $3.4 million and $4.8 million in 2010, 2009 and 2008, respectively, primarily related to the sale of 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 $23.1 million and $34.6 million at December 31, 2010 and 2009, respectively.

Inventory

Inventory recorded in current assets includes $10.0 million at December 31, 2010 and $9.2 million at December 31, 2009, for natural gas in underground storage owned by the Company’s E&P segment, and $25.1 million at December 31, 2010 and $20.8 million at December 31, 2009 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. During 2009, the Company recorded a $4.3 million non-cash impairment to reduce the current portion of our natural gas inventory to the lower of cost or market. The non-current portion of the gas is classified in property and equipment and carried at cost.  The carrying value of the non-current 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 includes $20.6 million at December 31, 2010 and $31.2 million at December 31, 2009 for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems for the Fayetteville Shale play.

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 reserves. 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, 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 percent (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 $4.38 per MMBtu and $75.96 per barrel for West Texas Intermediate oil, adjusted for market differentials, the

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Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2010. Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $164.4 million at December 31, 2010. At December 31, 2009, this ceiling amount of the Company’s reserves was calculated based upon average quoted market prices of $3.87 per Mcf for Henry Hub natural gas and $57.65 per barrel for West Texas Intermediate oil, and at December 31, 2008, the ceiling value of the Company’s reserves was calculated based upon year-end quoted market prices of $5.71 per Mcf for Henry Hub natural gas and $41.00 per barrel for West Texas Intermediate oil. 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 March 31, 2009, the net capitalized costs of our natural gas and oil properties exceeded the ceiling by approximately $558.3 million (net of tax) and resulted in a non-cash ceiling test impairment in the first quarter of 2009.

All of our costs directly associated with the acquisition and evaluation of properties in New Brunswick, Canada relating to our exploration program at December 31, 2010 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.

On December 31, 2009, the Company implemented certain provisions of FASB ASC 932, “Extractive Activities-Oil and Gas,” as updated by Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932)” (“FASB ASC 932”), which (a) expand the definition of oil- and gas-producing activities; (b) require energy companies to value their proved reserves by averaging the price from the first day of each month from the previous 12 months instead of using a year-end price; and (c) allow for additional drilling locations to be classified as proved undeveloped reserves assuming such locations are supported by reliable technologies. The Company accounted for the FASB ASC 932 changes as a change in accounting principle that is inseparable from a change in accounting estimate and will account for the change prospectively. The Company is not able to disclose the effects resulting from the implementation of these changes on the amount of proved reserves and disclosed quantities because personnel and time constraints made it infeasible for the Company to perform a second internal reserve estimation process under the prior standards on its approximately 4,850 properties.

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

Capitalized Interest. Interest is capitalized on the cost of unevaluated 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

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.

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 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

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hedging activities.

Earnings Per Share

Basic earnings per common share attributable to Southwestern Energy stockholders is computed by dividing net income (loss) attributable to Southwestern Energy by the weighted average number of common shares outstanding during each year. The diluted earnings per share attributable to Southwestern Energy 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.

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. For the year ended December 31, 2009, 6,683,085 of the Company’s outstanding options with an average exercise price of $8.33 were excluded from the calculation of diluted shares because they would have had an antidilutive effect.  For the year ended December 31, 2008, 7,166,354 of the Company’s outstanding options with an average exercise price of $3.99 were included in the calculation of diluted shares.  Options for 441,620 shares were excluded from the calculation because they would have had an antidilutive effect.

For the year ended December 31, 2010, 700,512 shares of restricted stock were included from the calculation of diluted shares. The calculation excluded 39,600 shares of restricted stock because they would have had an antidilutive effect. For the year ended December 31, 2009, the number of shares of restricted stock excluded from the calculation of diluted shares was 836,861 because they would have had an antidilutive effect.  For the year ended December 31, 2008, the number of shares of restricted stock included in the calculation of diluted shares was 708,725.  The calculation excluded 82,985 shares of restricted stock because they would have had an antidilutive effect.

All historical per share information in the consolidated financial statements and footnotes has been adjusted, as necessary, to reflect the two-for-one stock split effective in March 2008.

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. See Note 13 for further discussion of the Company’s stock-based compensation.

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.

Accounting Standards Implemented in this Report

On January 1, 2010, the Company implemented certain provisions of Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”) Topic 810, “Consolidation.” The new provisions (a) require a qualitative rather than a quantitative approach to determining the primary beneficiary of a variable interest entity (“VIE”); (b) amend certain guidance pertaining to the determination of the primary beneficiary when related parties are involved; (c) amend certain guidance for determining whether an entity is a VIE; and (d) require continuous assessments of whether an enterprise is the primary beneficiary of a VIE. The implementation did not have an impact on the Company’s results of operations or financial condition.

On January 1, 2010, the Company implemented certain provisions of Accounting Standards Update No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements” (“Update 2010-06”). Update 2010-06 requires the Company to (a) provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy; (b) provide a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method; and (c) provide fair value measurement disclosures for each class of financial assets and liabilities. The implementation did not have an impact on the Company’s results of operations or financial condition.

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On December 31, 2010, the Company implemented provisions of Accounting Standards Update (ASU) No. 2010-25, Plan Accounting—Defined Contribution Pension Plans (Topic 962): Reporting Loans to Participants by Defined Contribution Pension Plans (“Update 2010-25”). Update 2010-25 specifies that loans to pension plan participants be classified as notes receivable, segregated from the plan's investments and measured at their unpaid principal balance plus any accrued but unpaid interest. The implementation did not have a material impact on the Company’s results of operations or financial condition.

(2) DIVESTITURES AND ASSETS HELD FOR SALE

In the second quarter of 2010, the Company sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $357.8 million. The sale included only producing rights to the Haynesville and Middle Bossier Shales in approximately 20,063 net acres.  Under full cost accounting, this divestiture was accounted for as an adjustment of capitalized natural gas and oil properties with no gain recognized.  

In the second quarter of 2008, the Company sold certain oil and natural gas properties, wells and gathering equipment in its Fayetteville Shale play for $518.3 million. Additionally, the Company sold various oil and natural gas properties in the Gulf Coast and the Permian Basin for approximately $240.0 million in the aggregate. All proceeds from the sales of oil and natural gas properties were appropriately credited to the full cost pool.

Effective July 1, 2008, the Company sold all of the capital stock of Arkansas Western Gas for $223.5 million (net of expenses related to the sale). In order to receive regulatory approval for the sale and certain related transactions, the Company paid $9.8 million to Arkansas Western Gas for the benefit if its customers. The Company recorded a pre-tax gain on the sale of the utility of $57.3 million in the third quarter of 2008. As a result of the sale of the utility, the Company is no longer engaged in any natural gas distribution operations. The assets and liabilities of Arkansas Western Gas were previously presented as “held for sale” and the consolidated statements of cash flows include $1.1 million of cash and cash equivalents in the 2008 beginning of the year cash and cash equivalents balances.

(3) PREPAID EXPENSES

The components of prepaid expenses included in other current assets as of December 31, 2010 and 2009 consisted of the following:

	2010		2009
	(in thousands)
Prepaid drilling costs	$               21,997	$                 53,819
Prepaid insurance	7,690	6,572
Total	$               29,687	$                 60,391

(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 at December 31, 2010 and 2009:

	2010		2009
	(in thousands)
Proved properties	$     7,037,746		$        5,733,759
Unproved properties	712,117	(1)	595,358
Total capitalized costs	7,749,863		6,329,117
Less:  Accumulated depreciation, depletion and amortization	3,444,477		2,916,947
Net capitalized costs	$     4,305,386		$        3,412,170

(1)

Includes $10.7 million related to our exploration program in New Brunswick, Canada.

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The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2010.

	2010		2009		2008	Prior	Total
	(in thousands)
Property acquisition costs	$        176,812	(1)		$         55,883	$          50,951	$          78,123	$     361,769
Exploration and development costs	111,854	(1)		88,263	43,856	56,028	300,001
Capitalized interest	6,302	(1)		9,486	10,398	24,161	50,347
	$        294,968			$       153,632	$        105,205	$        158,312	$     712,117

(1)

Property acquisition costs include $2.5 million, exploration costs include $8.0 million and capitalized interest includes $0.2 million related to our exploration program in New Brunswick, Canada.

Of the total net unevaluated costs excluded from amortization at December 31, 2010, approximately $110.8 million is related to unevaluated seismic costs in the Fayetteville Shale play, approximately $115.5 million is related to acquisition of undeveloped properties in the Company’s Fayetteville Shale play, approximately $132.6 million is related to acquisition of undeveloped properties in the Company’s Appalachia properties and approximately $92.2 million is related to acquisition of undeveloped properties in the Company’s New Ventures, excluding our exploration program in New Brunswick, Canada. The Company has $10.7 million of unevaluated costs related to its exploration program in Canada. Additionally, the Company has approximately $153.8 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 the Fayetteville Shale play property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells to further develop the play. The timing and amount of costs to be included in future amortization computations related to Appalachia and New Ventures will depend on the 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:

	2010		2009	2008
	(in thousands, except per Mcfe amounts)
Proved property acquisition costs	$               —		$         4,372	$                —
Unproved property acquisition costs	229,909	(1)	115,217	97,645
Exploration costs	27,062	(1)	52,178	245,363
Development costs	1,524,453		1,358,109	1,216,987
Capitalized costs incurred	1,781,424		1,529,876	1,559,995
Full cost pool amortization per Mcfe	$            1.34		$            1.51	$             1.99

(1)

Includes unproved property acquisition costs and exploration costs include $2.5 million and $8.2 million, respectively, related to our exploration program in New Brunswick, Canada.

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $32.9 million, $40.2 million and $34.5 million during 2010, 2009 and 2008, 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 $139.2 million, $112.9 million and $82.4 million during 2010, 2009 and 2008, 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.

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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:

	2010	2009	2008
	(in thousands)
Sales	$  1,890,444	$     1,593,231	$     1,491,302
Production (lifting) costs	(376,939)	(259,588)	(194,234)
Depreciation, depletion and amortization	(561,003)	(474,014)	(399,159)
Impairment of natural gas and oil properties	—	(907,812)	—
	952,502	(48,183)	897,909
Provision (benefit) for income taxes	371,281	(15,650)	342,658
Results of operations	$      581,221	$        (32,533)	$        555,251

The results of operations shown above exclude interest costs and general and administrative expenses 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

The 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 85%, 88% and 83% of the present worth of the Company’s total proved reserves at December 31, 2010, 2009 and 2008, 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 and 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 2010, 2009 and 2008 all of which were located in the United States:

	2010		2009		2008
	Natural		Natural		Natural
	Gas	Oil	Gas	Oil	Gas	Oil
	(MMcf)	(MBbls)	(MMcf)	(MBbls)	(MMcf)	(MBbls)
Proved reserves, beginning of year	3,650,303	1,059	2,175,528	1,507	1,396,856	8,912
Revisions of previous estimates	309,292	50	94,930	(346)	100,230	(355)
Extensions, discoveries and other additions	1,429,439	281	1,683,264	22	919,623	93
Production	(403,636)	(171)	(299,698)	(124)	(192,265)	(385)
Acquisition of reserves in place	—	—	1,795	—	—	—
Disposition of reserves in place	(55,418)	—	(5,516)	—	(48,916)	(6,758)
Proved reserves, end of year	4,929,980	1,219	3,650,303	1,059	2,175,528	1,507
Proved developed reserves:
Beginning of year	1,972,767	1,028	1,336,370	1,352	880,278	7,269
End of year	2,687,238	1,173	1,972,767	1,028	1,336,370	1,352
Proved undeveloped reserves:
Beginning of year	1,677,536	31	839,158	155	516,578	1,643
End of year	2,242,741	47	1,677,536	31	839,158	155

The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil.

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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 at December 31, 2010, 2009 and 2008 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:

	2010	2009	2008
	(in thousands)
Future cash inflows	$ 19,620,254	$   12,533,868	$   11,395,056
Future production costs	(6,826,915)	(4,488,884)	(3,115,947)
Future development costs	(3,025,433)	(2,367,206)	(1,491,449)
Future income tax expense	(3,143,571)	(1,569,242)	(2,178,756)
Future net cash flows	6,624,335	4,108,536	4,608,904
10% annual discount for estimated timing of cash flows	(3,610,585)	(2,306,718)	(2,499,642)
Standardized measure of discounted future net cash flows	$   3,013,750	$     1,801,818	$     2,109,262

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 in 2009 and 2010, and utilized year-end pricing in 2008. Prices used for the standardized measure above were average market prices of $4.38 per Mcf for natural gas and $75.96 per barrel for oil in 2010, average market prices of $3.87 per Mcf for natural gas and $57.65 per barrel for oil in 2009, and year-end prices of $5.71 per Mcf for natural gas and $41.00 per barrel for oil in 2008. 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, after consideration of permanent differences, to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties.

Following is an analysis of changes in the standardized measure during 2010, 2009 and 2008:

	2010	2009	2008
	(in thousands)
Standardized measure, beginning of year	$  1,801,818	$     2,109,262	$     2,015,156
Sales and transfers of natural gas and oil produced, net of production costs	(1,516,571)	(1,330,256)	(1,297,068)
Net changes in prices and production costs	706,062	(1,321,404)	(325,300)
Extensions, discoveries, and other additions, net of future production and development costs	1,205,464	978,327	1,400,044
Acquisition of reserves in place	—	—	—
Sales of reserves in place	(6,269)	(4,430)	(246,223)
Revisions of previous quantity estimates	324,284	88,261	161,956
Accretion of discount	230,355	302,439	259,163
Net change in income taxes	(746,971)	413,399	(338,661)
Changes in estimated future development costs	(10,558)	204,005	(1,101)
Previously estimated development costs incurred during the year	353,560	218,625	178,444
Changes in production rates (timing) and other	672,576	143,590	302,852
Standardized measure, end of year	$  3,013,750	$     1,801,818	$     2,109,262

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(5) DERIVATIVES AND RISK MANAGEMENT

The Company is exposed to commodity price risk which impacts the predictability of its cash flows related to the sale of natural gas and oil. The primary risk managed by the Company’s use of certain derivative financial instruments is commodity price risk. These derivative financial instruments allow the Company to limit its price exposure to a portion of its projected gas sales. At December 31, 2010 and 2009, the Company’s derivative financial instruments consisted of price swaps, costless-collars 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.   

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 financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.

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The balance sheet classifications of the derivative financial instruments are summarized below at December 31, 2010 and 2009:

	Derivative Assets
	December 31, 2010		December 31, 2009
	Balance Sheet Classification	Fair Value	Balance Sheet Classification	Fair Value
	(in thousands)
Derivatives designated as hedging instruments:
Fixed and floating price swaps	Hedging asset	$          81,797	Hedging asset	$        117,553
Costless-collars	Hedging asset	48,582	Hedging asset	45,516
Fixed and floating price swaps	Other assets	5,086	Other assets	11,756
Costless-collars	Other assets	72,827	Other assets	―
Total derivatives designated as hedging instruments		$        208,292		$        174,825
Derivatives not designated as hedging instruments:
Basis swaps	Hedging asset	$                 33	Hedging asset	$                 ―
Total derivatives not designated as hedging instruments		$                 33		$                 ―
Total derivative assets		$        208,325		$        174,825
	Derivative Liabilities
	December 31, 2010		December 31, 2009
	Balance Sheet Classification	Fair Value	Balance Sheet Classification	Fair Value
	(in thousands)
Derivatives designated as hedging instruments:
Fixed and floating price swaps	Hedging liability	$            1,774	Hedging liability	$               940
Costless-collars	Hedging liability	3,903	Hedging liability	7,387
Fixed and floating price swaps	Long-term hedging liability	22,334	Long-term hedging liability	1,373
Costless-collars	Long-term hedging liability	17,854	Long-term hedging liability	―
Total derivatives designated as hedging instruments		$          45,865		$            9,700
Derivatives not designated as hedging instruments:
Basis swaps	Hedging liability	$            2,008	Hedging liability	$          11,725
Basis swaps	Long-term hedging liability	―	Long-term hedging liability	1,684
Total derivatives not designated as hedging instruments		$            2,008		$          13,409
Total derivative liabilities		$          47,873		$          23,109

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 these gains and losses are recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of these gains and losses is recognized in earnings immediately.

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As of December 31, 2010, the Company had cash flow hedges on the following volumes of natural gas production and gas-in-storage (in Bcf):

Year	Fixed price swaps	Costless-collars
2011	66.8	62.1
2012	68.1	80.5
2013	36.5	―

As of December 31, 2010, the Company recorded a net gain in accumulated other comprehensive income related to its hedging activities of $96.5 million. This amount is net of a deferred income tax liability recorded as of December 31, 2010 of $61.7 million. The amount recorded in accumulated other comprehensive income will be relieved over time and recognized in earnings as the physical transactions being hedged occur. Assuming the market prices of natural gas futures as of December 31, 2010 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of approximately $72.7 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 gas sales in the consolidated statements of operations. Gas sales included a realized gain from settled contracts of $301.5 million for the year ended December 31, 2010 compared to a realized gain of $610.4 million for the year ended December 31, 2009. Volatility in earnings and other comprehensive income may occur in the future as a result of the application of the Company’s derivative activities.

The following tables summarize the before tax effect of all cash flow hedges on the condensed consolidated financial statements for the years ended December 31, 2010 and 2009.

		Gain Recognized in Other Comprehensive Income (Effective Portion)
		For the years ended
		December 31,
Derivative Instrument		2010	2009
		(in thousands)
Fixed price swaps		$     166,722	$     234,775
Costless-collars		$     132,438	$     121,597
	Classification of Gain Reclassified from Accumulated Other	Gain Reclassified from Accumulated Other Comprehensive Income into Earnings (Effective Portion)
	Comprehensive Income	For the years ended
	into Earnings	December 31,
Derivative Instrument	(Effective Portion)	2010	2009
		(in thousands)
Fixed price swaps	Gas Sales	$     230,707	$     345,839
Costless-collars	Gas Sales	$       70,775	$     264,528
		Gain (Loss) Recognized in Earnings (Ineffective Portion)
	Classification of Gain (Loss)	For the years ended
	Recognized in Earnings	December 31,
Derivative Instrument	(Ineffective Portion)	2010	2009
		(in thousands)
Fixed price swaps	Gas Sales	$       (4,769)	$         8,424
Costless-collars	Gas Sales	$       (1,999)	$         1,437

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, 2010 and December 31, 2009, the Company had no material fair value hedges.

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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. Basis swap 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 and hedging liabilities, and all realized and unrealized gains and losses related to these contracts are recognized immediately in the condensed consolidated statements of operations as a component of gas sales.

As of December 31, 2010, the Company had basis swaps that did not qualify for hedge accounting treatment on 12.0 Bcf of 2011 natural gas production.

The following tables summarize the before tax effect of basis swaps that did not qualify for hedge accounting on the condensed consolidated statements of operations for the years ended December 31, 2010 and 2009.

		Unrealized Gain (Loss) Recognized in Earnings
	Income Statement	For the years ended
	Classification	December 31,
Derivative Instrument	of Unrealized Gain (Loss)	2010	2009
		(in thousands)
Basis swaps	Gas Sales	$       11,434	$      (15,133)
		Realized Gain (Loss) Recognized in Earnings
	Income Statement	For the years ended
	Classification	December 31,
Derivative Instrument	of Realized Gain (Loss)	2010	2009
		(in thousands)
Basis swaps	Gas Sales	$      (12,098)	$        (9,339)

 (6) FAIR VALUE MEASUREMENTS

The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2010 and 2009 were as follows:

	December 31, 2010		December 31, 2009
	Carrying	Fair	Carrying	Fair
	Amount	Value	Amount	Value
	(in thousands)
Cash and cash equivalents	$          16,055	$          16,055	$          13,184	$          13,184
Unsecured revolving credit facility	$        421,200	$        421,200	$        324,500	$        324,500
Senior notes	$        673,000	$        761,372	$        674,200	$        707,326
Derivative instruments	$        160,452	$        160,452	$        151,716	$        151,716

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 5.2% at December 31, 2010 and 6.7% at December 31, 2009. The carrying values of the borrowings under the Company’s unsecured revolving credit facility at December 31, 2010 and 2009 approximate fair value.

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.

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:

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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 and basis swaps. The Company’s costless-collars 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.  

Assets and liabilities measured at fair value on a recurring basis are summarized below (in thousands):

	December 31, 2010
	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	$                        —	$                     86,883	$                     121,442	$               208,325
Derivative liabilities	—	(24,108)	(23,765)	(47,873)
Total	$                        —	$                     62,775	$                       97,677	$               160,452
	December 31, 2009
	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	$                        —	$                   129,309	$                       45,516	$               174,825
Derivative liabilities	—	(2,313)	(20,796)	(23,109)
Total	$                        —	$                   126,996	$                       24,720	$               151,716

The table below presents reconciliations for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2010 and 2009. The fair values of Level 3 derivative instruments are estimated using 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 the assumptions a marketplace participant would have used at December 31, 2010 and at December 31, 2009.

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Total net gains and losses for Level 3 derivatives for the years ended December 31, 2010 and 2009 are provided below:

	For the years ended December 31,
	2010	2009
	(in thousands)
Balance at beginning of period	$             24,720	$             182,823
Total gains or losses (realized/unrealized):
Included in earnings	68,111	243,806
Included in other comprehensive income (loss)	63,522	(144,368)
Purchases, issuances and settlements	(58,676)	(257,541)
Transfers into/out of Level 3	—	—
Balance at end of period	$             97,677	$               24,720
Change in unrealized gains (losses) included in earnings relating to derivatives still held as of December 31	$               9,435	$             (13,735)

(7) DEBT

The components of debt as of December 31, 2010 and 2009 consisted of the following:

	2010			2009
	(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 (0.887% at December 31, 2010 and 1.106% at December 31, 2009) unsecured revolving credit facility, expires February 2012	421,200	(1)	324,500
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	31,800		33,000
Total long-term debt	1,093,000		997,500
Total debt	$         1,094,200		$               998,700

(1)

In February 2011, the Company amended and restated its unsecured revolving credit facility extending the maturity date to February 2016.

The following is a summary of scheduled long-term debt maturities by year as of December 31, 2010 (in thousands):

2011	$                1,200
2012	422,400
2013	1,200
2014	1,200
2015	1,200
Thereafter	667,000
	$         1,094,200

Issuance of 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. Payment obligations with respect to the 7.5% Senior Notes were guaranteed at issuance by the Company’s subsidiaries, SEECO, Inc. (“SEECO”), Southwestern Energy Production Company (“SEPCO”) and Southwestern Energy Services Company (“SES”), which guarantees may be unconditionally released in certain circumstances.

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As a result of the issuance of the guarantees of the 7.5% Senior Notes, and in order for all of the Company’s senior notes to rank equally, in May 2008, the Company and its subsidiaries, SEECO, SEPCO and SES, entered into supplemental indenture agreements with the trustees under the indentures relating to the Company’s 7.625% Senior Notes, 7.125% Senior Notes, 7.35% Senior Notes and 7.15% Senior Notes, pursuant to which SEECO, SEPCO and SES became guarantors of such notes to the same extent to which such subsidiaries have guaranteed the Company’s 7.5% Senior Notes. All of these guarantees are currently in place. Please refer to Note 16, “Condensed Consolidating Financial Information” in this Form 10-K for additional information.

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 sale and leaseback transactions and to merge, consolidate or sell assets.

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.  The amount available under the revolving credit facility may be increased to $2.0 billion at any time upon the Company’s agreement with its existing or additional lenders. The Company had $421.2 and $324.5 million outstanding under its revolving credit facility at December 31, 2010 and December 31, 2009, respectively. The interest rate on the amended 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 62.5 basis points over LIBOR at December 31, 2010. The Credit Facility is guaranteed by the Company’s subsidiary, SEECO.  The Credit Facility requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied.  The revolving credit 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 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.  At December 31, 2010, the Company’s capital structure consisted of 27% debt and 73% equity and it was in compliance with the covenants of its debt agreements.  The weighted average interest rate related to outstanding borrowings under the Credit Facility was 0.887% and 1.106% at December 31, 2010 and December 31, 2009, respectively.  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.

Interest Payments

Total cash interest payments made by the Company were $57.0 million in 2010, $56.7 million in 2009 and $42.5 million in 2008.

(8) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

The Company has commitments to third parties for demand transportation charges. At December 31, 2010, future payments under non-cancelable demand charges are approximately $163.8 million in 2011, $195.4 million in 2012, $195.1 million in 2013, $194.5 million in 2014, $191.6 million in 2015 and $851.2 million thereafter.

Southwestern 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 leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases expiring through 2019.  At December 31, 2010, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $64.1 million in 2011, $61.2 million in 2012, $56.6 million in 2013, $50.5 million in 2014, $28.2 million in 2015 and $30.8 million thereafter. The Company also has commitments for compression services related to its Midstream Services and E&P segments. At December 31, 2010, future minimum payments under these non-cancelable agreements are approximately $28.2 million in 2011, $20.3 million in 2012, $10.7 million in 2013, $5.0 million in 2014 and $1.1 million in 2015.

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At December 31, 2010, the Company had purchase obligations consisting of outstanding purchase orders under existing agreements for approximately $48.8 million.  Included in this amount is $38.1 million of purchase obligations relating to compression units for the Company’s Midstream Services segment.

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 CAD $47 million in the aggregate over the next three years. 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 CAD $44.5 million. 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, 2010, no liability has been recognized in connection with the promissory notes.

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.

Litigation

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 273 ^rd District Court in Shelby County, Texas (collectively, the “Sixth Petition”) the plaintiffs 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 plaintiffs, subsequently acquired leases based upon such proprietary data and profited therefrom.  Among other things, the plaintiffs’ 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, plaintiffs sought actual damages of over $55 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, plaintiffs were permitted, over the Company’s objections, to file a Seventh Amended Petition claiming actual damages of approximately $46 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 plaintiffs with respect to all of the statutory and common law claims and awarded approximately $11.4 million in compensatory damages. The jury did not, however, award plaintiffs 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 plaintiffs’ 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 plaintiffs.  On December 31, 2010, the plaintiff and intervenor 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.  A hearing on the post-verdict motions has been scheduled for March 14, 2011, subject to any postponements or adjournments thereof.

The Company has not accrued any amounts with respect to this lawsuit and cannot reasonably estimate the amount of any potential liability based on the Company's understanding and judgment of the facts and merits of this case, including appellate remedies, and the advice of counsel.  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 could be material to the Company's results of operations, financial position or cash flows.

In March 2010, the Company’s subsidiary, SEECO, Inc., 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

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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. The Company cannot reasonably estimate the amount of any potential liability from this matter and does not believe that this matter will have a material adverse effect on its results of operations, financial position or cash flows, however, 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.

The Company is subject to other litigation and claims that have arisen in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such litigation and claims currently pending will not have a material effect on the results of operations, financial position or cash flows.

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.  

(9) INCOME TAXES

The provision (benefit) for income taxes included the following components:

	2010	2009	2008
	(in thousands)
Current:
Federal	$        10,421	$        (65,309)	$        122,000
State	1,518	340	—
	11,939	(64,969)	122,000
Deferred:
Federal	319,279	48,308	183,601
State	59,982	298	45,445
Foreign	459	—	—
Investment tax credit amortization	—	—	(47)
	379,720	48,606	228,999
Provision (benefit) for income taxes	$      391,659	$        (16,363)	$        350,999

The provision for income taxes was an effective rate of 39.3% in 2010, 31.5% in 2009 and 38.2% in 2008. 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:  

	2010	2009	2008
	(in thousands)
Expected provision (benefit) at federal statutory rate	$      348,632	$        (18,205)	$        321,631
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect	39,975	415	29,539
Non-deductible expenses	660	1,497	1,211
Other	2,392	(70)	(1,382)
Provision (benefit) for income taxes	$      391,659	$        (16,363)	$        350,999

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The components of the Company’s net deferred tax liability as of December 31, 2010 and 2009 were as follows:

	2010	2009
	(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property	$     1,411,240	$        1,031,879
Cash flow hedges	61,394	56,441
Other	14,122	12,255
	1,486,756	1,100,575
Deferred tax assets:
Accrued compensation	16,279	12,573
Alternative minimum tax credit carryforward	70,138	59,717
Stored natural gas	7,145	6,988
Accrued pension costs	6,227	4,356
Book over tax basis in partnerships	—	1,695
Asset retirement obligations	10,848	8,516
Net operating loss carryforward	192,086	207,857
Other	9,652	6,198
	312,375	307,900
Net deferred tax liability	$     1,174,381	$           792,675

The net deferred tax liability at December 31, 2010 was comprised of net long-term deferred income tax liabilities of $1,130.3 million in addition to a net current deferred income tax liability of $44.1 million.  The net deferred tax liability at December 31, 2009 was comprised of net long-term deferred income tax liabilities of $811.9 million, partially offset by a net current deferred income tax asset of $19.2 million.  In 2010, the Company paid $0.4 million in state income taxes and paid $14.0 million in alternative minimum taxes. In the third quarter of 2010, the Company elected to carry back the 2009 alternative minimum tax loss which resulted in a $28.6 million alternative minimum tax refund, of which $9.0 million was accrued in 2009.  In 2009, the Company paid $0.3 million in state income taxes and received a $41.8 million alternative minimum tax refund. In 2008, the Company paid $107.5 million in alternative minimum taxes. The Company’s net operating loss carryforward at December 31, 2010 was $627.2 million and has expiration dates of 2027 through 2030. The Company also had an alternative minimum tax credit carryforward of $70.1 million and a statutory depletion carryforward of $11.6 million at December 31, 2010.

Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises in 2010. 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 2010 due to net operating loss carryforwards, these “windfall” tax benefits are not reflected in our net operating losses in deferred tax assets for 2010. Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2010 were $124.3 million.

As of December 31, 2010, the Company has no unrecognized tax benefits. The income tax years 2007-2009 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 $0.5 million, which has an expiration date of 2030. 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 recorded a valuation allowance of $0.5 million, as of December 31, 2010, 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.

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(10) ASSET RETIREMENT OBLIGATIONS

The following table summarizes the Company’s 2010 and 2009 activity related to asset retirement obligations:

	2010	2009
	(in thousands)
Asset retirement obligation at January 1	$          22,972	$            12,907
Accretion of discount	1,095	524
Obligations incurred	6,926	6,899
Obligations settled/removed	(477)	(810)
Revisions of estimates	(2,730)	3,452
Asset retirement obligation at December 31	$          27,786	$            22,972
Current liability	1,829	854
Long-term liability	25,957	22,118
Asset retirement obligation at December 31	$          27,786	$            22,972

(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 $0.9 million, $0.8 million and $1.1 million of contribution expense in 2010, 2009 and 2008, respectively. Additionally, the Company capitalized $4.2 million, $3.3 million and $2.4 million of contributions in 2010, 2009 and 2008, respectively, 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.

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.

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The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets, and funded status as of December 31, 2010 and 2009:

			Other Postretirement
	Pension Benefits		Benefits
	2010	2009	2010	2009
	(in thousands)
Change in benefit obligations:
Benefit obligation at January 1	$        56,736	$          47,963	$          3,271	$            2,339
Service cost	7,096	5,148	1,089	696
Interest cost	3,249	2,874	195	136
Participant contributions	—	—	15	9
Actuarial loss	6,311	3,829	462	48
Benefits paid	(5,029)	(3,078)	(77)	(45)
Plan amendments	168	—	—	88
Settlements	(598)	—	—	—
Benefit obligation at December 31	$        67,933	$          56,736	$          4,955	$            3,271
			Other Postretirement
	Pension Benefits		Benefits
	2010	2009	2010	2009
	(in thousands)
Change in plan assets:
Fair value of plan assets at January 1	$        46,689	$          34,866	$                 —	$                  —
Actual return/(loss) on plan assets	6,276	5,888	—	—
Employer contributions	9,667	9,013	62	36
Participant contributions	—	—	15	9
Benefits paid	(5,029)	(3,078)	(77)	(45)
Settlements	(654)	—	—	—
Fair value of plan assets at December 31	$        56,949	$          46,689	$                 —	$                  —
Funded status of plans at December 31	$      (10,984)	$        (10,047)	$         (4,955)	$           (3,271)

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 $2.4 million ($1.2 million after tax) for the year ended December 31, 2010 and a gain of $0.4 million ($0.2 million after tax) for the year ended December 31, 2009. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a loss of  $0.4 million ($0.2 million after tax) for the year ended December 31, 2010 and was a loss of less than $0.1 million for the year ended December 31, 2009. Included in accumulated other comprehensive income at December 31, 2010 and 2009 was a $20.5 million loss ($12.5 million net of tax) and a $17.8 million loss ($11.0 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 2011 are $0.4 million for prior service costs, $0.8 million net loss and $0.1 million for transition obligation costs.

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The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2010 and 2009 are as follows:

	2010	2009
	(in thousands)
Projected benefit obligation	$           67,933	$             56,736
Accumulated benefit obligation	$           63,665	$             52,909
Fair value of plan assets	$           56,949	$             46,689

Pension and other postretirement benefit costs include the following components for 2010, 2009 and 2008:

				Other Postretirement
	Pension Benefits			Benefits
	2010	2009	2008	2010	2009	2008
	(in thousands)
Service cost	$      7,096	$       5,148	$       4,883	$      1,089	$           696	$          581
Interest cost	3,249	2,874	3,808	195	136	217
Expected return on plan assets	(3,503)	(2,809)	(3,894)	—	—	(48)
Amortization of transition obligation	—	—	—	65	65	76
Amortization of prior service cost	346	334	412	14	14	10
Amortization of net loss	806	846	430	21	7	34
Net periodic benefit cost	7,994	6,393	5,639	1,384	918	870
Settlements and curtailments	223	—	4,630	—	—	(216)
Total benefit cost	$      8,217	$       6,393	$     10,269	$      1,384	$           918	$          654

Amounts recognized in other comprehensive income for the year ended December 31, 2010 were as follows:

	Pension Benefits	Other Postretirement Benefits
	(in thousands)
Net actuarial loss arising during the year	$               (3,538)	$                    (462)
Amortization of transition obligation	—	65
Amortization of prior service cost	346	14
Amortization of net loss	806	21
Plan amendments	(168)	—
Settlements	167	—
Tax effect	1,138	153
	$               (1,249)	$                    (209)

The weighted average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2010 and 2009 are as follows:

			Other Postretirement
	Pension Benefits		Benefits
	2010	2009	2010	2009
Discount rate	5.50%	5.75%	5.50%	5.75%
Rate of compensation increase	4.50%	4.50%	n/a	n/a

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The weighted average assumptions used in the measurement of the Company’s net periodic benefit cost for 2010, 2009 and 2008 are as follows:

				Other Postretirement
	Pension Benefits			Benefits
	2010	2009	2008	2010	2009	2008
Discount rate	5.75%	6.00%	6.00%	5.75%	6.00%	6.00%
Expected return on plan assets	7.50%	7.50%	7.75%	n/a	n/a	5.00%
Rate of compensation increase	4.50%	4.50%	4.00%	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 2010 and 2009:

	2010	2009
Health care cost trend assumed for next year	9%	9%
Rate to which the cost trend is assumed to decline	5%	5%
Year that the rate reaches the ultimate trend rate	2030	2029

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	$          182	$        (153)
Effect on postretirement benefit obligation	$          646	$        (547)

Pension Payments and Asset Management

In 2010, the Company contributed $9.7 million to its pension plans and less than $0.1 million to its other postretirement benefit plan. The Company expects to contribute $11.3 million to its pension plans and $0.1 million to its other postretirement benefit plan in 2011. No plan assets are expected to be returned to the Company during the next twelve months.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits	Other Postretirement Benefits
	(in thousands)
2011	$                  3,992	$                     132
2012	$                  3,870	$                     170
2013	$                  5,165	$                     224
2014	$                  6,632	$                     331
2015	$                  6,241	$                     453
Years 2016-2020	$                52,003	$                  4,551

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

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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 at December 31, 2010, 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:
Large cap growth equity	10%	10%
Large cap value equity	10%	10%
Large cap core equity	14%	14%
Small cap equity	11%	12%
International equity	15%	15%
Fixed income and cash and cash equivalents	40%	39%
Total	100%	100%

Utilizing GAAP’s fair value hierarchy, the Company’s fair value measurement of pension plan assets at December 31, 2010 are as follows:

		Quoted Prices in Active Markets for Identical Assets	Significant Observable Inputs	Significant Unobservable Inputs
Asset category:	Total	(Level 1)	(Level 2)	(Level 3)
	(in thousands)
Equity securities:
Large cap growth equity (1)	$               5,937	$                5,937	$                     —	$                    —
Large cap value equity (2)	5,838	5,838	—	—
Large cap core equity (3)	8,062	8,062	—	—
Small cap equity (4)	6,662	6,662	—	—
International equity (5)	8,333	8,333	—	—
Fixed income (6)	18,539	18,539	—	—
Cash and cash equivalents	3,578	3,578	—	—
Total	$             56,949	$              56,949	$                     —	$                    —

(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)

Mutual fund that seeks to replicate the Standards & Poor’s 500 index by investing at least 80% of assets in S&P 500 stocks.

(4)

Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.

(5)

Mutual fund that seeks to invest in a diversified portfolio of stocks and fixed income securities with at least 80% of its investments in securities issued in Europe or the Pacific Basin.

(6)

Mutual fund that seeks to invest in a diversified portfolio of bonds with investment grade quality United States (“U.S.”) dollar-denominated securities of U.S. issuers.

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Utilizing GAAP’s fair value hierarchy, the Company’s fair value measurement of pension plan assets at December 31, 2009 are as follows:

		Quoted Prices in Active Markets for Identical Assets	Significant Observable Inputs	Significant Unobservable Inputs
Asset category:	Total	(Level 1)	(Level 2)	(Level 3)
	(in thousands)
Equity securities:
Large cap growth equity (1)	$               5,119	$                5,119	$                     —	$                    —
Large cap value equity (2)	4,974	4,974	—	—
Large cap core equity (3)	6,703	6,703	—	—
Small cap equity (4)	5,267	5,267	—	—
International equity (5)	6,970	6,970	—	—
Fixed income (6)	14,856	14,856	—	—
Cash and cash equivalents	2,800	2,800	—	—
Total	$             46,689	$              46,689	$                     —	$                    —

(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)

Mutual fund that seeks to replicate the Standards & Poor’s 500 index by investing at least 80% of assets in S&P 500 stocks.

(4)

Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.

(5)

Mutual fund that seeks to invest in a diversified portfolio of stocks and fixed income securities with at least 80% of its investments in securities issued in Europe or the Pacific Basin.

(6)

Mutual fund that seeks to invest in a diversified portfolio of bonds with investment grade quality United States (“U.S.”) dollar-denominated securities of U.S. issuers.

The Company’s pension plan assets are classified as Level 1 due to the fact that all of the pension plan’s investments are comprised of 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. 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) EQUITY

Common Stock Purchase Rights

On April 8, 2009, the Company’s Board of Directors approved and the Company entered into, a Second Amended and Restated Rights Agreement (“Rights Agreement”), dated as of April 9, 2009, between the Company and Computershare Trust Company, N.A., which amended, restated, superseded and replaced the Amended and Restated Rights Agreement dated as of April 12, 1999, as amended. The Rights Agreement extended the term of the agreement until April 8, 2019 and amended each Right (which initially represented the right to purchase one share of the Common Stock) to represent the right to purchase, when exercisable, a unit consisting of one one-thousandth of a share (“Unit”) of Series A Junior Participating Preferred Stock, par value $0.01 per share (“Series A Preferred Stock”) at a purchase price of $150.00 per Unit (“Purchase Price”), subject to adjustment.

On February 24, 2010, the Company's Board of Directors approved, and the Company and Computershare Trust Company, N.A., as rights agent, entered into, an amendment to the Rights Agreement pursuant to which the final expiration date of the rights (each as defined in the Rights Agreement) was advanced from April 8, 2019 to February 26, 2010. As a result of the amendment, the rights are no longer outstanding or exercisable.

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, 2010, 156,636 shares were accounted for as treasury stock, compared to 203,830 shares at December 31, 2009.

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 (13) 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, 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, 2010, 2009 and 2008:

	2010	2009	2008
	(in thousands)
Stock-based compensation cost related to stock options – general and administrative expense	$                4,706	$                5,108	$                3,627
Stock-based compensation cost related to stock options – capitalized	$                2,679	$                2,124	$                1,061

The Company also recorded a deferred tax benefit of $1.7 million related to stock options in 2010, compared to deferred tax benefits of $1.4 million in 2009 and $1.2 million in 2008. A total of $14.0 million of unrecognized compensation costs related to stock options not yet vested is expected to be recognized over future periods. That cost is expected to be recognized over a weighted-average period of 2.2 years.

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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	2010	2009	2008
Risk-free interest rate	2.0%	2.2%	2.0%
Expected dividend yield	—	—	—
Expected volatility	60.1%	61.6%	57.0%
Expected term	5 years	5 years	5 years

The following tables summarize stock option activity for the years 2010, 2009 and 2008 and provide information for options outstanding at December 31 of such years. The number of options and exercise prices at January 1, 2008 have been restated to reflect the two-for-one stock split effected on March 25, 2008:

	2010		2009		2008
		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	5,649,233	$     11.59	7,396,537	$         7.44	8,552,874	$         4.81
Granted	446,895	37.05	412,515	39.83	594,870	31.67
Exercised	(1,293,046)	3.01	(2,152,819)	2.67	(1,690,446)	2.07
Forfeited or expired	(33,960)	35.26	(7,000)	31.21	(60,761)	24.72
Options outstanding at December 31	4,769,122	$     16.13	5,649,233	$       11.59	7,396,537	$         7.44

	Options Outstanding				Options Exercisable
			Weighted				Weighted
			Average				Average
		Weighted	Remaining	Aggregate		Weighted	Remaining	Aggregate
	Options	Average	Contractual	Intrinsic	Options	Average	Contractual	Intrinsic
Range of	Outstanding at	Exercise	Life	Value	Exercisable at	Exercise	Life	Value
Exercise Prices	December 31, 2010	Price	(Years)	(in thousands)	December 31, 2010	Price	(Years)	(in thousands)
$1.20 - $3.10	1,997,811	$     1.99	2.3		1,997,811	$     1.99	2.3
$3.11 - $15.00	461,536	6.23	0.9		461,536	6.23	0.9
$15.01 - $30.00	938,934	22.25	3.1		924,045	22.15	3.0
$30.01 - $51.47	1,370,841	35.88	5.8		513,610	33.71	5.1
	4,769,122	$   16.13	3.3	$   101,578	3,897,002	$   11.45	2.7	$   101,231

The weighted-average grant-date fair value of options granted during the years 2010, 2009 and 2008 was $19.40, $21.35 and $15.82, respectively. The total intrinsic value of options exercised during 2010, 2009 and 2008 was $41.4 million, $87.6 million and $60.0 million, respectively. Associated with the exercise of stock options for 2008, the Company recorded a tax benefit of $43.1 million as an increase to additional paid-in capital.

Restricted Stock

The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2010, 2009 and 2008:

	2010	2009	2008
	(in thousands)
Stock-based compensation cost related to restricted stock grants – general and administrative expense	$                5,114	$                5,069	$                4,036
Stock-based compensation cost related to restricted stock grants – capitalized	$                4,107	$                3,767	$                2,823

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The Company also recorded a deferred tax liability of $1.4 million related to restricted stock for the year ended December 31, 2010, compared to deferred tax liabilities of $0.7 million for 2009 and $3.5 million for 2008. As of December 31, 2010, there was $27.3 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 2.8 years.

The following table summarizes the restricted stock activity for the years 2010, 2009 and 2008 and provides information for restricted stock outstanding at December 31 of such years. The number of shares and the grant date fair values at January 1, 2008 have been restated to reflect the two-for-one stock split effected on March 25, 2008:

	2010		2009		2008
		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	794,529	$     33.70	843,430	$       27.66	791,030	$       19.89
Granted	390,415	36.46	319,950	39.03	417,320	33.50
Vested	(319,894)	30.45	(359,247)	24.37	(299,141)	15.65
Forfeited	(30,992)	33.54	(9,604)	29.47	(65,779)	25.93
Unvested shares at December 31	834,058	$     36.24	794,529	$       33.70	843,430	$       27.66

The fair values of the grants were $14.2 million for 2010, $12.5 million for 2009 and $14.0 million for 2008. The total fair value of shares vested were $9.7 million for 2010, $14.9 million for 2009 and $9.3 million for 2008.

(14) 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 crude oil. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced gas volumes and through gathering fees associated with the transportation of natural gas to market. The Company’s Natural Gas Distribution segment, which generated revenue from the transportation and sale of natural gas at retail, ceased with the July 1, 2008, sale of the utility.

Summarized financial information for the Company’s reportable segments is shown in the following table. The financial information is for the respective year ended except Assets which is as of the respective year-end.  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 (loss) amount shown below to consolidated income (loss) before income taxes, is the sum of operating income (loss), 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.

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	Exploration			Natural
	And		Midstream	Gas
	Production		Services	Distribution	Other		Total
	(in thousands)
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(1)	235		179	—	13		427
Depreciation, depletion and amortization expense	561,018		28,765	—	549		590,332
Interest expense(1)	7,888		18,275	—	—		26,163
Provision for income taxes(1)	323,748		67,834	—	77		391,659
Assets	4,849,478	(2)	1,016,563	—	151,422		6,017,463
Capital investments(3)	1,775,518		271,316	—	73,231		2,120,065
2009
Revenues from external customers	$    1,582,596		$       562,944	$               —	$              239		$    2,145,779
Intersegment revenues	10,635		1,040,388	—	448		1,051,471
Operating income (loss)	(157,725)		122,620	—	139		(34,966)
Other income, net(1)	1,406		34	—	9		1,449
Depreciation, depletion and amortization expense	474,014		19,213	—	431		493,658
Impairment of natural gas and oil properties	907,812		—	—	—		907,812
Interest expense(1)	15,237		3,401	—	—		18,638
Provision (benefit) for income taxes(1)	(61,725)		45,303	—	59		(16,363)
Assets	3,904,739	(2)	767,346	—	98,165		4,770,250
Capital investments(3)	1,565,450		214,208	—	29,459		1,809,117
2008
Revenues from external customers	$    1,434,201		$       762,153	$       114,957	$              241		$    2,311,552
Intersegment revenues	57,101		1,411,818	2,753	448		1,472,120
Operating income	813,504		62,349	10,733	182		886,768
Other income (loss), net(1)	4,531		132	(270)	11		4,404
Gain on sale of utility assets	—		—	—	57,264		57,264
Depreciation, depletion and amortization expense	399,159		11,402	3,431	416		414,408
Interest expense(1)	20,528		6,059	2,317	—		28,904
Provision for income taxes(1)	304,636		21,278	3,095	21,990		350,999
Assets	3,950,013	(2)	519,258	—	290,887	(4)	4,760,158
Capital investments(3)	1,595,828		183,021	3,574	13,745		1,796,168

(1)

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 are incurred at the corporate level.

(2)

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.

(3)

Capital investments include an increase of $14.4 million for 2010, an increase of $12.2 million for 2009 and an increase of $36.2 million for 2008 related to the change in accrued expenditures between years.

(4)

Includes $195.1 million of the remaining cash proceeds generated from the Company’s 2008 asset sales, as described in Note 2.

Included in intersegment revenues of the Midstream Services segment are $1.5 billion, $0.9 billion and $1.3 billion for 2010, 2009 and 2008, respectively, for marketing of the Company’s E&P sales.  Prior to the sale of the utility, intersegment sales by the E&P segment and Midstream Services segment to the Natural Gas Distribution segment were priced in accordance with terms of the existing contracts and market conditions. Corporate assets include cash and cash equivalents, furniture and fixtures, prepaid debt and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to segments. All of the Company’s operations were located within the United States in 2009 and 2008.  In 2010, assets and capital investments within the E&P segment include $10.7 million related to the Company’s activities in Canada.

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(15) QUARTERLY RESULTS (UNAUDITED)

The following is a summary of the quarterly results of operations for the years ended December 31, 2010 and 2009:

	1st Quarter		2nd Quarter	3rd Quarter	4th Quarter
	(in thousands, except per share amounts)
	2010
Operating revenues	$      668,117		$     589,943	$     682,172	$     670,431
Operating income	288,090		206,317	270,136	256,685
Net income	171,768		122,009	160,638	149,418
Net income attributable to Southwestern Energy	171,797		122,069	160,741	149,511
Earnings per share attributable to Southwestern Energy stockholders – Basic	0.50		0.35	0.47	0.43
Earnings per share attributable to Southwestern Energy stockholders – Diluted	0.49		0.35	0.46	0.43
	2009
Operating revenues	$        540,817		$        477,520	$        502,949	$        624,493
Operating income (loss)	(700,492)	(1)	202,227	197,038	266,261
Net income (loss)	(432,852)	(2)	121,058	118,210	157,792
Net income (loss) attributable to Southwestern Energy	(432,830)	(2)	121,100	118,254	157,826
Earnings per share attributable to Southwestern Energy stockholders – Basic	(1.26)	(2)	0.35	0.34	0.46
Earnings per share attributable to Southwestern Energy stockholders – Diluted	(1.26)	(2)	0.35	0.34	0.45

(1)

Includes a non-cash ceiling test impairment of our natural gas and oil properties of $907.8 million, before taxes.

(2)

Includes a non-cash ceiling test impairment of our natural gas and oil properties of $558.3 million, net of taxes, or $1.62 per basic and diluted earnings per share.

(16) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Company is providing condensed consolidating financial information for SEECO, SEPCO and SES, its subsidiaries that are 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 jointly and severally, fully and unconditionally guaranteed the Company’s 7.35% Senior Notes and 7.125% Senior Notes, which are still outstanding, and its 7.625% Senior Notes, which were redeemed on May 1, 2009 at the option of the holders. 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.

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.

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CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	Parent	Guarantors	Non-Guarantors	Eliminations	Consolidated
	(in thousands)
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
Year ended December 31, 2009:
Operating revenues	$                        —	$          2,071,746	$             207,672	$           (133,639)	$          2,145,779
Operating costs and expenses:
Gas purchases	—	483,922	—	(1,086)	482,836
Operating expenses	—	201,964	66,682	(132,105)	136,541
General and administrative expenses	—	109,870	13,196	(448)	122,618
Depreciation, depletion and amortization	—	472,757	20,901	—	493,658
Impairment of natural gas & oil properties	—	907,812	—	—	907,812
Taxes, other than income taxes	—	33,935	3,345	—	37,280
Total operating costs and expenses	—	2,210,260	104,124	(133,639)	2,180,745
Operating income (loss)	—	(138,514)	103,548	—	(34,966)
Other income, net	—	1,388	61	—	1,449
Equity in earnings of subsidiaries	(35,650)	—	—	35,650	—
Interest expense	—	12,760	5,878	—	18,638
Income (loss) before income taxes	(35,650)	(149,886)	97,731	35,650	(52,155)
Provision (benefit) for income taxes	—	(53,549)	37,186	—	(16,363)
Net income (loss)	(35,650)	(96,337)	60,545	35,650	(35,792)
Less: Net loss attributable to noncontrolling interest	—	(142)	—	—	(142)
Net income (loss) attributable to Southwestern Energy	$             (35,650)	$             (96,195)	$               60,545	$               35,650	$              (35,650)
Year ended December 31, 2008:
Operating revenues	$                        —	$         2,185,171	$             241,371	$           (114,990)	$          2,311,552
Operating costs and expenses:
Gas purchases	—	735,404	79,120	(42,956)	771,568
Operating expenses	—	122,578	56,520	(71,521)	107,577
General and administrative expenses	—	84,437	18,035	(513)	101,959
Depreciation, depletion and amortization	—	397,660	16,748	—	414,408
Taxes, other than income taxes	—	24,556	4,716	—	29,272
Total operating costs and expenses	—	1,364,635	175,139	(114,990)	1,424,784
Operating income	—	820,536	66,232	—	886,768
Other income (loss), net	57,264	4,511	(107)	—	61,668
Equity in earnings of subsidiaries	532,572	—	—	(532,572)	—
Interest expense	—	18,259	10,645	—	28,904
Income (loss) before income taxes	589,836	806,788	55,480	(532,572)	919,532
Provision for income taxes	21,890	308,127	20,982	—	350,999
Net income (loss)	567,946	498,661	34,498	(532,572)	568,533
Less: Net income attributable to noncontrolling interest	—	587	—	—	587
Net income (loss) attributable to Southwestern Energy	$             567,946	$             498,074	$               34,498	$           (532,572)	$             567,946

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CONDENSED CONSOLIDATING BALANCE SHEETS
	Parent	Guarantors	Non- Guarantors	Eliminations	Consolidated
	(in thousands)
December 31, 2010:
ASSETS
Cash and cash equivalents	$             8,381	$             7,631	$                  43	$                  ―	$            16,055
Accounts receivable	382	331,154	20,037	―	351,573
Inventories	―	34,263	835	―	35,098
Other current assets	5,015	171,060	2,092	―	178,167
Total current assets	13,778	544,108	23,007	―	580,893
Intercompany receivables	1,820,857	131	18,724	(1,839,712)	―
Investments	―	11,103	(11,102)	(1)	―
Property and equipment	124,823	7,871,279	984,783	―	8,980,885
Less: Accumulated depreciation, depletion and amortization	52,256	3,526,010	104,422	―	3,682,688
	72,567	4,345,269	880,361	―	5,298,197
Investments in subsidiaries (equity method)	2,253,871	―	―	(2,253,871)	―
Other assets	18,918	92,747	26,708	―	138,373
Total assets	$       4,179,991	$       4,993,358	$          937,698	$      (4,093,584)	$       6,017,463
LIABILITIES AND EQUITY
Accounts and notes payable	$          175,476	$          336,411	$            33,208	$                  ―	$          545,095
Other current liabilities	3,288	142,839	2,761	―	148,888
Total current liabilities	178,764	479,250	35,969	―	693,983
Intercompany payables	―	1,317,696	522,017	(1,839,713)	―
Long-term debt	1,093,000	―	―	―	1,093,000
Deferred income taxes	(98,206)	1,066,166	162,332	―	1,130,292
Other liabilities	41,557	89,986	3,769	―	135,312
Total liabilities	1,215,115	2,953,098	724,087	(1,839,713)	3,052,587
Commitments and contingencies
Total equity	2,964,876	2,040,260	213,611	(2,253,871)	2,964,876
Total liabilities and equity	$       4,179,991	$       4,993,358	$          937,698	$      (4,093,584)	$       6,017,463

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CONDENSED CONSOLIDATING BALANCE SHEETS
	Parent	Guarantors	Non- Guarantors	Eliminations	Consolidated
	(in thousands)
December 31, 2009:
ASSETS
Cash and cash equivalents	$             7,378	$             5,776	$                  30	$                  ―	$            13,184
Accounts receivable	1,158	247,139	14,779	―	263,076
Inventories	―	29,156	853	―	30,009
Other current assets	11,510	204,131	42,591	―	258,232
Total current assets	20,046	486,202	58,253	―	564,501
Intercompany receivables	1,751,363	131	15,724	(1,767,218)	―
Investments	―	10,746	(10,745)	(1)	―
Property and equipment	78,733	6,429,294	673,757	―	7,181,784
Less: Accumulated depreciation, depletion and amortization	41,658	2,947,166	65,707	―	3,054,531
	37,075	3,482,128	608,050	―	4,127,253
Investments in subsidiaries (equity method)	1,625,645	―	―	(1,625,645)	―
Other assets	20,161	20,043	38,292	―	78,496
Total assets	$       3,454,290	$       3,999,250	$          709,574	$      (3,392,864)	$       4,770,250
LIABILITIES AND EQUITY
Accounts and notes payable	$          149,450	$          277,319	$            24,401	$                  ―	$          451,170
Other current liabilities	2,937	80,462	1,847	―	85,246
Total current liabilities	152,387	357,781	26,248	―	536,416
Intercompany payables	―	1,276,920	490,299	(1,767,219)	―
Long-term debt	997,500	―	―	―	997,500
Deferred income taxes	(75,222)	796,640	90,484	―	811,902
Other liabilities	38,644	40,265	4,542	―	83,451
Total liabilities	1,113,309	2,471,606	611,573	(1,767,219)	2,429,269
Commitments and contingencies
Total equity	2,340,981	1,527,644	98,001	(1,625,645)	2,340,981
Total liabilities and equity	$       3,454,290	$       3,999,250	$          709,574	$      (3,392,864)	$       4,770,250

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	Parent	Guarantors	Non-Guarantors		Eliminations	Consolidated
	(in thousands)
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 year	$           8,381	$           7,631	$               43		$               —	$         16,055
Year ended December 31, 2009:
Net cash provided by operating activities	$         58,212	$     1,198,995	$        102,169		$               —	$     1,359,376
Investing activities:
Capital investments	(17,075)	(1,517,990)	(245,100)		—	(1,780,165)
Proceeds from sale of property and equipment	—	763	55		—	818
Other	10,980	(29,238)	17,001		—	(1,257)
Net cash used in investing activities	(6,095)	(1,546,465)	(228,044)		—	(1,780,604)
Financing activities:
Intercompany activities	(478,843)	353,246	125,597		—	—
Payments on current portion of long-term debt	(61,200)	—	—		—	(61,200)
Payments on revolving long-term debt	(1,371,700)	—	—		—	(1,371,700)
Borrowings under revolving long-term debt	1,696,200	—	—		—	1,696,200
Other	(25,165)	—	—		—	(25,165)
Net cash provided by (used in) financing activities	(240,708)	353,246	125,597		—	238,135
Increase (decrease) in cash and cash equivalents	(188,591)	5,776	(278)		—	(183,093)
Cash and cash equivalents at beginning of year	195,969	—	308		—	196,277
Cash and cash equivalents at end of year	$           7,378	$           5,776	$               30		$               —	$         13,184
Year ended December 31, 2008:
Net cash provided by (used in) operating activities	$       (106,167)	$     1,215,962	$         51,014		$               —	$    1,160,809
Investing activities:
Capital investments	(8,401)	(1,523,071)	(224,416)		—	(1,755,888)
Proceeds from sale of property, equipment and utility assets	213,721	700,289	50,021		—	964,031
Other	6,907	34,310	(41,438)		—	(221)
Net cash provided by (used in) investing activities	212,227	(788,472)	(215,833)		—	(792,078)
Financing activities:
Intercompany activities	263,762	(427,490)	163,728		—	—
Payments on current portion of long-term debt	(1,200)	—	—		—	(1,200)
Payments on revolving long-term debt	(1,843,600)	—	—		—	(1,843,600)
Borrowings under revolving long-term debt	1,001,400	—	—		—	1,001,400
Proceeds from issuance of long-term debt	600,000	—	—		—	600,000
Other	69,114	—	—		—	69,114
Net cash provided by (used in) financing activities	89,476	(427,490)	163,728		—	(174,286)
Increase (decrease) in cash and cash equivalents	195,536	—	(1,091)		—	194,445
Cash and cash equivalents at beginning of year	433	—	1,399	(1)	—	1,832	(1)
Cash and cash equivalents at end of year	$        195,969	$               —	$              308		$               —	$        196,277

(1)

Cash and cash equivalents at the beginning of 2008 include amounts classified as “held for sale.”  See Note 2 for additional information.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. 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 (the Exchange Act).  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 evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2010.  There were no changes in our internal control over financial reporting during the three months ended December 31, 2010, that 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.

ITEM 9B. OTHER INFORMATION

There was no information required to be disclosed in a current report on Form 8-K during the fourth quarter of the fiscal year ended December 31, 2010, that was not reported on such form.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

EXECUTIVE OFFICERS OF THE REGISTRANT

Name	Officer Position	Age	Years Served as Officer
Steven L. Mueller	President and Chief Executive Officer	57	2
Greg D. Kerley	Executive Vice President and Chief Financial Officer	55	21
Mark K. Boling	Executive Vice President, General Counsel and Secretary	53	9
Gene A. Hammons*	President, Southwestern Midstream Services Company	65	6
John D. Thaeler*	Senior Vice President, New Ventures and R2	57	12

__________________________________________________

*Position held with one or more subsidiaries of the Company

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

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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 the Company’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 the Company’s subsidiaries, SEECO, Inc., Southwestern Energy Production Company, DeSoto Drilling, Inc., Diamond “M” Production Company, SWN Resources Canada, Inc., Southwestern Midstream Services Company, Southwestern Energy Services Company, Certified Title Company and A.W. Realty Company.  

Mr. Kerley was appointed to his present position in December 1999.  He was elected to the Board of Directors in August 2010.  Previously, he served as Senior Vice President and Chief Financial Officer from 1998 to 1999, Senior Vice President-Treasurer and Secretary from 1997 to 1998, Vice President-Treasurer and Secretary from 1992 to 1997, and Controller from 1990 to 1992.  Mr. Kerley also served as the Chief Accounting Officer from 1990 to 1998. Prior to joining us, Mr. Kerley held senior financial and accounting positions at Agate Petroleum, Inc. and was a manager for Arthur Andersen, L.L.P. specializing in the energy sector.  Mr. Kerley is the executive vice president of the Company’s subsidiaries, Southwestern Field Services, LLC, DeSoto Sand, LLC, SWN International, LLC, SWN Resources Canada, Inc., Southwestern NGV Services, LLC and A.W. Realty Company.  Mr. Kerley is also a director of the Company’s subsidiaries, SEECO, Inc., Southwestern Energy Production Company, DeSoto Drilling, Inc., Diamond “M” Production Company, SWN Resources Canada, Inc., Southwestern Midstream Services Company, Southwestern Energy Services Company, Certified Title Company and A.W. Realty Company.  

Mr. Boling was appointed to his present position in December 2002.  He joined us as Senior Vice President, General Counsel and Secretary in January 2002.  He is also the secretary of all of the Company’s subsidiaries and a director of the Company’s subsidiaries, SEECO, Inc., Southwestern Energy Production Company, DeSoto Drilling Inc., Southwestern Midstream Services Company, Southwestern Energy Services Company, Diamond “M” Production 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. Hammons was appointed President of Southwestern Midstream Services Company, and its subsidiaries, Desoto Gathering Company, LLC, Angelina Gathering Company, LLC, Southwestern Energy Services Company in December 2005.  He joined the company in July 2005 as Vice President of Southwestern Midstream Services Company.  He is also President of SWN Producer Services, LLC and a director of Southwestern Midstream Services Company and Southwestern Energy Services Company.  Prior to joining us, he provided consulting services to clients in the natural gas industry.  Previously, Mr. Hammons was employed by El Paso Natural Gas Company and Burlington Resources and held managerial positions in facility design and installation, gathering management and marketing over the course of his combined 28-year tenure.  

Mr. Thaeler was appointed Senior Vice President-New Ventures and R2 of the Company’s subsidiaries, SEECO, Inc. and Southwestern Energy Production Company in 2009.  In 2010, he was also appointed Senior Vice President-New Ventures and R2 of the Company’s subsidiary, SWN Resources Canada, Inc.  Prior to these appointments, he served as Senior Vice President of SEECO, Inc. from 2004 to 2008.  He joined Southwestern Energy Company in 1999 as the asset manager of SEECO and held the position until 2001 when he was promoted to Vice President. Prior to joining the Company, Mr. Thaeler held various technical and managerial positions during a 25-year career at Occidental Petroleum Company where he worked in Africa, the Middle East, Central and South America, and the continental U.S.  He has a master’s degree in geology from the University of Cincinnati and an MBA in finance from the University of Houston. He is a member of the American Association of Petroleum Geologists, the Society of Petroleum Engineers and the Independent Petroleum Association of America.

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 17, 2011 (“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 2011 Proxy Statement for information concerning our directors. We refer you to the section “Corporate Governance – Committees of the Board of Directors” in

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the 2011 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 2011 Proxy Statement for information relating to compliance with Section 16(a) of the Exchange Act.

The Company has adopted a code of ethics that applies to the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer.  The full text of such code of ethics has been posted on the Company’s 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 2011 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 2011 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The 2011 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 2011 Proxy Statement. Refer to the sections “Security Ownership of Certain Beneficial Owners” and “Share Ownership of Management, Directors and Nominees” in our 2011 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 2011 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.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The 2011 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 2011 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 Company 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.

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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 25, 2011

BY:

    /s/ GREG D. KERLEY                     

                                                                                                                       Greg D. Kerley

                                                                                                                       Executive 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 24, 2011.

/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/ GREG D. KERLEY	Director, Executive Vice President and Chief Financial Officer
Greg D. Kerley
/s/ ROBERT C. OWEN	Controller and Chief Accounting Officer
Robert C. Owen
/s/ LEWIS E. EPLEY, JR	Director
Lewis E. Epley, Jr
/s/ ROBERT L. HOWARD	Director
Robert L. Howard
/s/ VELLO A. KUUSKRAA	Director
Vello A. Kuuskraa
/s/ KENNETH R. MOURTON	Director
Kenneth R. Mourton
/s/ CHARLES E. SCHARLAU	Director
Charles E. Scharlau
/s/ ALAN H. STEVENS	Director
Alan H. Stevens

107 SWN

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, effective October 26, 2010 (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed October 29, 2010.
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	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)

108 SWN

4.13	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. (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	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)
10.5	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)
10.6	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)
10.7	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)
10.8	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)
10.9	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).
10.10	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)
10.11	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)
10.12	Southwestern Energy Company 2002 Performance Unit Plan, as amended, effective December 31, 2008. (Incorporated by reference to Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.13	Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)
10.14	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)

109 SWN

10.15	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)
10.16	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)
10.17	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)
10.18	Form of Non-Qualified Stock Option 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	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)
10.20	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)
10.21	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)
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.
99.1*	Reserve Audit Report of Netherland, Sewell & Associates, Inc., dated January 26, 2011.
101+	Interactive Data File

____________

*Filed herewith

+IN ACCORDANCE WITH THE TEMPORARY HARDSHIP EXEMPTION PROVIDED BY RULE 201 OF REGULATION S-T, THE DATE BY WHICH THE INTERACTIVE DATA FILE IS REQUIRED TO BE SUBMITTED HAS BEEN EXTENDED BY SIX BUSINESS DAYS. 

110 SWN

EX-21

EXHIBIT 21
LIST OF SUBSIDIARIES
Subsidiary Name	Location of Incorporation or Organization
SEECO, Inc.	Arkansas
Southwestern Energy Production Company	Arkansas
Diamond “M” Production Company	Delaware
DeSoto Drilling, Inc.	Arkansas
DeSoto Sand, L.L.C.	Arkansas
Southwestern Midstream Services Company	Arkansas
Southwestern Energy Services Company	Arkansas
DeSoto Gathering Company, L.L.C.	Arkansas
A. W. Realty Company	Arkansas
Overton Partners, L.P.	Texas
Angelina Gathering Company, L.L.C.	Texas
Southwestern Field Services, L.L.C.	Arkansas
SWN International, L.L.C.	Delaware
SWN Producer Services, L.L.C.	Arkansas
SWN Resources Canada, Inc.	New Brunswick, Canada

EX-23

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 333-03787, 333-03789, 333-64961, 333-96161, 333-42494, 333-69720, 333-100702, 333-101160, 333-110140, 333-125714 and 333-121720) of Southwestern Energy Company of our report dated February 24, 2011 relating to the financial statementsand the effectiveness of internal control over financial reporting, which appears in this Form 10K.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 24, 2011

EX-23

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to (a) the use of our audit letter relating to the proved reserves of gas and oil of Southwestern Energy Company, (b) the references to us as experts in Southwestern Energy Company’s Annual Report on Form 10-K for the year ended December 31, 2010 and (c) the incorporation by reference of our name and our audit letter into Southwestern Energy Company’s previously filed Registration Statements on Form S-8 (File Nos. 333-03787, 333-03789, 333-64961, 333-96161, 333-42494, 333-69720, 333-100702, 333-101160, 333-110140, 333-125714 and 333-121720), that incorporate by reference such Form 10-K.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By	/s/ DANNY D. SIMMONS
	Danny D. Simmons, P.E.
	President and Chief Operating Officer

Houston, Texas
February 24, 2011

EX-31

Exhibit 31.1

CERTIFICATION

I, Steven L. Mueller, certify that:

1. I have reviewed this annual report on Form 10-K of Southwestern Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 25, 2011	/s/ STEVEN L. MUELLER
			Steven L. Mueller
			Chief Executive Officer

EX-31

Exhibit 31.2

CERTIFICATION

I, Greg D. Kerley, certify that:

1. I have reviewed this annual report on Form 10-K of Southwestern Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 25, 2011	/s/ GREG D. KERLEY
			Greg D. Kerley
			Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

          Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), each of the undersigned officers of Southwestern Energy Company, a Delaware corporation (the "Company"), does hereby certify that:

          The Annual Report on Form 10-K for the year ended December 31, 2010 (the "Form 10-K") of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:  February 25, 2011	/s/ STEVEN L. MUELLER
	Steven L. Mueller
	Chief Executive Officer
Dated:  February 25, 2011	/s/ GREG D. KERLEY
	Greg D. Kerley
	Chief Financial Officer

EX-99

Netherland, Sewell & Associates, Inc.	Chairman & CEO	Executive Committee
Worldwide Petroleum Consultants	C.H. (Scott) Rees III	P. Scott Frost - Dallas
	President & COO	J. Carter Henson, Jr. - Houston
	Danny D. Simmons	Dan Paul Smith - Dallas
	Executive VP	Joseph J. Spellman - Dallas
	G. Lance Binder	Thomas J. Tella II – Dallas

January 27, 2011

Mr. Jack Bergeron

Southwestern Energy Company

Suite 125

2350 North Sam Houston Parkway East

Houston, Texas 77032

Dear Mr. Bergeron:

In accordance with your request, we have audited the estimates prepared by Southwestern Energy Company (Southwestern), as of December 31, 2010, of the proved reserves and future revenue to the Southwestern interest in certain oil and gas properties located in Arkansas, Louisiana, Oklahoma, Pennsylvania, and Texas.  It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Southwestern.  We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a).  The estimates of reserves and future revenue have been prepared in accordance with the definitions and guidelines of the SEC and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, except that per-well overhead expenses are excluded for the operated properties and future income taxes are excluded for all properties.  We completed our audit on January 26, 2011.  This report has been prepared for Southwestern's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Southwestern's estimates of the net reserves and future net revenue, as of December 31, 2010, for the audited properties:

	Net Reserves		Future Net Revenue (M$)
	Oil	Gas		Present Worth
Category	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	1,022	2,645,232	6,728,172	3,595,776
Proved Developed Non-Producing	151	42,007	105,332	47,231
Proved Undeveloped	47	2,242,741	2,934,404	619,447
Total Proved	1,220	4,929,980	9,767,907	4,262,454

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate.  Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.  Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a lease-by-lease basis, some of the estimates of Southwestern are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI).  However, in our opinion the estimates of Southwestern's proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards).  Additionally, the aggregate percentage difference in the estimates of NSAI and Southwestern is within the recommended

10 percent tolerance threshold set forth in the SPE Standards.  We are satisfied with the methods and procedures used by Southwestern in preparing the December 31, 2010, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Southwestern.

The estimates shown herein are for proved reserves.  Southwestern's estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.  Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.  The estimates of reserves and future revenue included herein have not been adjusted for risk.

Prices used by Southwestern are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2010.  For oil volumes, the average West Texas Intermediate posted price of $75.96 per barrel is adjusted by field for quality, transportation fees, and regional price differentials.  For gas volumes, the average Henry Hub spot price of $4.376 per MMBTU is adjusted by field for energy content, transportation fees, and regional price differentials.  All prices are held constant throughout the lives of the properties.  The average adjusted product prices weighted by production over the remaining lives of the properties are $75.46 per barrel of oil and $3.961 per MCF of gas.

Lease and well operating costs used by Southwestern are based on historical operating expense records.  For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels.  Lease and well operating costs for the operated properties include only direct lease- and field-level costs.  For all properties, headquarters general and administrative overhead expenses of Southwestern are not included.  Lease and well operating costs are held constant throughout the lives of the properties.  Southwestern's estimates of capital costs are included as required for workovers, new development wells, and production equipment.  The future capital costs are held constant to the date of expenditure.

The reserves shown in this report are estimates only and should not be construed as exact quantities.  Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible.  Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.  In addition to the primary economic assumptions discussed herein, estimates of Southwestern and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of Southwestern to recover the reserves, and that projections of future production will prove consistent with actual performance.  If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.  

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties.  Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of major properties making up approximately 88 percent of Southwestern's total proved reserves and accounting for approximately 85 percent of the present worth for those reserves.  In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Southwestern with respect to ownership interests, oil and 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.  However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or

data.  Our audit did not include a review of Southwestern's overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Southwestern, are on file in our office.  The technical persons responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-002699

/s/ C.H. (Scott) Rees III

By:

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

/s/ Lee E. George

/s/ William J. Knights

By:

By:

Lee E. George, P.E. 95018

William J. Knights, P.G. 1532

Vice President

Vice President

Date Signed:  January 27, 2011

Date Signed:  January 27, 2011

CBR:MRL