Edgar Filing: SOUTHWESTERN ENERGY CO

SWN Form 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, 2008
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
(including associated stock purchase rights)

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. x
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 $15,977,830,730 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2008, of $47.61. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.
As of February 23, 2009, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 343,632,766.
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 19, 2009 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, 2008

TABLE OF CONTENTS

Page

PART I

Item 1. Business

Glossary of Certain Industry Terms

Item 1A. Risk Factors

Item 1B. Unresolved Staff Comments

Item 2. Properties

Item 3. Legal Proceedings

Item 4. Submission of Matters to a Vote of Security Holders

Executive Officers of the Registrant

PART II

Item 5.

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

Equity Securities

Stock Performance Graph

Item 6. Selected Financial Data

Item 7.

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

Overview

Results of Operations

Liquidity and Capital Resources

Critical Accounting Policies

Cautionary Statement about Forward-Looking Statements

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Item 8. Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Item 9A. Controls and Procedures

Item 9B. Other Information

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accounting Fees and Services

PART IV

Item 15. Exhibits, Financial Statement Schedules

EXHIBIT INDEX

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 the 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 primarily engaged in natural gas and crude oil exploration, development and production (E&P) within the United States. 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 within the United States, with our current operations being principally focused on development of the 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 Oklahoma, Texas and Pennsylvania. We primarily conduct our exploration and production operations through our wholly-owned subsidiaries, SEECO, Inc. and Southwestern Energy Production Company, or SEPCO. SEECO has historically operated exclusively in Arkansas. It holds a large base of both developed and undeveloped gas reserves in Arkansas and conducts the drilling programs for the Fayetteville Shale play and the conventional drilling program in the Arkansas part of the Arkoma Basin. SEPCO conducts development drilling and exploration programs in the Oklahoma portion of the Arkoma Basin, Texas and Pennsylvania. DeSoto Drilling, Inc., or DDI, a wholly-owned subsidiary of SEPCO, operates drilling rigs in the Fayetteville Shale play and in East Texas.

Midstream Services - Our Midstream Services segment primarily supports our E&P operations and is currently concentrated on the Fayetteville Shale play. Midstream Services generates revenue from gathering fees associated with the transportation of natural gas to market and through the marketing of our own gas production and some third-party natural gas. We engage in gas gathering activities in Arkansas and Texas through our gathering subsidiaries, DeSoto Gathering Company, L.L.C. and Angelina Gathering Company, L.L.C. Our gas marketing subsidiary, Southwestern Energy Services Company, or SES, captures downstream opportunities which arise through marketing and transportation activity.

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 2008, 92% of our operating income and 89% of our EBITDA were generated from our E&P business , compared to 94% of our operating income and 95% of our EBITDA in 2007 and 96% of our operating income and 93% of our EBITDA in 2006. In 2008, 7% of our operating income and 5% of our EBITDA were generated from Midstream Services, compared to 3% of our operating income and 3% of our EBITDA in 2007 and 2% of our operating income and 1% of our EBITDA in 2006. In 2008, 1% of our operating income and 1% of our EBITDA were generated from our Gas Distribution business which was sold effective July 1, 2008, compared to 3% of our operating income and 2% of our EBITDA in 2007 and 2% of our operating income and 3% of our EBITDA in 2006. 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 with our net income.

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. We seek to maximize the value of our significant acreage position in the Fayetteville Shale play, which we believe provides us with significant production and reserve growth potential. We intend to continue to develop our acreage position and improve our well results through the use of advanced technologies and detailed technical analysis of our properties.

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. 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 timing and plans for future enhancement and exploitation efforts, the costs of enhancing, drilling, completing and producing the wells, and the marketing negotiations for our gas production to maximize both production volumes and realized price.

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Enhancing Our Overall Returns through Expanding Our Midstream Operations. We seek to maximize profitability by exercising control over the delivery of natural gas from the areas where we have production. We seek to achieve this by continuing to improve upon and add to our gas gathering infrastructure, which we believe allows us to better manage the physical movement of our production and the costs of our operations. As of December 31, 2008, we have invested approximately $342.3 million in building a gas gathering system in the Fayetteville Shale play which was gathering approximately 802 MMcf per day through 843 miles of gathering lines. We intend to invest $220 million in our Midstream operations in 2009 to continue the expansion of our infrastructure. We have also been pro-active in encouraging the construction of interstate pipelines to provide access to additional markets for our production. Our marketing subsidiary is a “foundation shipper” on two pipeline projects being developed for the Fayetteville Shale play. These projects will provide access to the eastern United States which will provide new opportunities for us to maximize the realized price for our production.

Grow through New Exploration and Development Activities. We actively seek to find and develop new oil and 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 began as a New Venture project in 2002. As of December 31, 2008, we held 138,638 net undeveloped acres in New Ventures projects, which includes approximately 114,738 net undeveloped acres targeting the Devonian-aged Marcellus Shale in Pennsylvania. In addition to New Ventures prospects, we also seek to enter into and develop oil and gas resources through strategic opportunities to expand existing operations including joint ventures, farm-ins or farm-outs.

Recent Developments

Marcellus Shale Acreage Acquisition. In the first quarter of 2009, we purchased approximately 21,715 net acres in Lycoming County, Pennsylvania, for approximately $8.2 million. Including this acreage acquisition, we currently have approximately 137,000 net undeveloped acres in Pennsylvania as of February 23, 2009, under which we believe the Marcellus Shale is prospective.

2009 Planned Capital Investments and Production Guidance. Our planned capital investment program for 2009 is $1.9 billion, which includes approximately $1.6 billion for our E&P segment, $220 million for our Midstream Services segment, and $40 million for other corporate purposes. Our 2009 capital program is expected to be primarily funded by net cash flow, cash on hand and borrowings under our $1 billion revolving credit facility. The planned capital program for 2009 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. Based on our capital program, we also announced our targeted 2009 gas and oil production of approximately 280 to 284 Bcfe, an increase of approximately 45% over our 2008 production.

Pipeline Precedent Agreement. On October 1, 2008, our marketing subsidiary, SES, signed a precedent agreement pursuant to which it will contract as a “foundation shipper” for firm transportation services on a proposed new natural gas pipeline of Fayetteville Express Pipeline LLC, which is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P. SES will use the new pipeline primarily to deliver gas volumes produced from our operations in the Fayetteville Shale play. Pending regulatory approvals, the pipeline is expected to be in-service by late 2010 or early 2011.

Exploration and Production

Our operations are primarily focused on the Fayetteville Shale, an unconventional reservoir located in the Arkoma Basin in Arkansas. In addition to our significant position in the Fayetteville Shale, we conduct conventional operations in the Arkoma Basin where we target Atokan-age gas reservoirs and in East Texas where we primarily target the James Lime formation. We also hold a significant acreage position in northeastern Pennsylvania, under which we believe the Marcellus Shale is prospective. We will continue to actively seek to develop conventional and unconventional natural gas and oil resource plays with significant exploration and exploitation potential.

Operating income from our E&P segment was $813.5 million in 2008, compared to $358.1 million in 2007 and $237.3 million in 2006. EBITDA from our E&P segment was $1.2 billion in 2008, compared to $640.5 million in 2007 and $386.4 million in 2006. The increases in both our operating income and EBITDA in 2008 and 2007 were due to increased production volumes and higher realized prices, partially offset by increases in operating costs and expenditures. 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 with our net income.

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Our estimated proved natural gas and oil reserves were 2,185 Bcfe at year-end 2008, compared to 1,450 Bcfe at year-end 2007 and 1,026 Bcfe at year-end 2006. The overall increase in total estimated proved reserves in the past three years is primarily due to the discovery and development of the Fayetteville Shale play in Arkansas. The after-tax PV-10, or standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities, was $2.1 billion at year-end 2008, compared to $2.0 billion at year-end 2007 and $1.0 billion at year-end 2006. The reconciling difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2008 Summary Operating Data table below) is the discounted value of future income taxes on the estimated cash flows. Our year-end 2008 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pre-tax PV-10, of $3.0 billion, compared to $2.6 billion at year-end 2007 and $1.3 billion at year-end 2006. 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. At year-end 2008, the market prices for natural gas and crude oil that were used to calculate our PV-10 value were $5.71 per Mcf and $41.00 per barrel, respectively, compared to $6.80 per Mcf and $92.50 per barrel at year-end 2007 and $5.64 per Mcf and $57.25 per barrel at year-end 2006. We refer you to Note 8 in the consolidated financial statements for a discussion of our standardized measure of discounted future cash flows related to our proved natural gas and oil reserves, to the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-K, and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.

Approximately 100% of our year-end 2008 estimated proved reserves were natural gas and 62% were classified as proved developed, compared to 96% and 64%, respectively, in 2007 and 95% and 65%, respectively, in 2006. We operate approximately 95% of our reserves, based on our pre-tax PV-10 value, and our average reserve life approximated 11.2 years at year-end 2008. Sales of natural gas production accounted for 97% of total operating revenues for this segment in 2008, 94% in 2007 and 91% in 2006.

The reserve replacement ratio 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 cost of adding the reserves or indicate the potential value of the reserve additions. Our reserve replacement ratio has averaged over 400% during the last three years, primarily driven by increases in the reserves associated with our Fayetteville Shale play. In 2008, we replaced 523% of our production volumes with an increase of 920.2 Bcfe of proved natural gas and oil reserves as a result of our drilling program and net upward revisions of 98.1 Bcfe. Of the reserve additions, 568.2 Bcfe were proved developed and 352.0 Bcfe were proved undeveloped. The upward reserve revisions during 2008 were primarily due to improved performance of wells in our Fayetteville Shale play, 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 gas leases and wells in 2008.

In 2007, our reserve replacement ratio was 474% (from reserve additions of 507.9 Bcfe primarily driven by our drilling program in the Fayetteville Shale play), including net upward revisions of 31.0 Bcfe. Of the 2007 reserve additions, 281.2 Bcfe were proved developed and 226.7 Bcfe were proved undeveloped. The upward reserve revisions during 2007 were primarily due to improved performance of wells in our Fayetteville Shale play.

In 2006, our reserve replacement ratio was 386% (from reserve additions of 365.5 Bcfe primarily driven by our drilling programs in the Fayetteville Shale play, East Texas and conventional Arkoma), including net downward reserve revisions of 86.6 Bcfe. Of the 2006 reserve additions, 153.6 Bcfe were proved developed and 211.9 Bcfe were proved undeveloped. The downward reserve revisions during 2006 were primarily due to a comparative decrease in year-end gas prices, combined with performance revisions in our East Texas and conventional Arkoma Basin properties, which were partially offset by an upward performance revision in our Fayetteville Shale properties.

For the period ending December 31, 2008, our three-year average reserve replacement ratio, including revisions, was 483%. Our reserve replacement ratio for 2008, excluding the effect of reserve revisions, was 473%, compared to 447% in 2007 and 505% in 2006. Excluding reserve revisions, our three-year average reserve replacement ratio is 471%.

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 to continue to be the primary source of our reserve additions in the future; however, our ability to add reserves is dependent upon a number of factors that are beyond our control. We refer you to the risk factors “Our drilling plans for the Fayetteville Shale play are subject to

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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.

The development of our proved undeveloped reserves will require us to make significant additional investments. We expect that our proved undeveloped reserves of 840 Bcfe as of December 31, 2008, will require us to invest an additional $1.5 billion in order for those reserves to be brought to production. Our 2008 proved undeveloped reserve additions are expected to be developed and to begin to generate cash inflows over the next five years. 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.

The following table provides information as of December 31, 2008, related to proved reserves, well count, net acreage and PV-10, and 2008 annual information related to production and capital investments for each of our operating areas:

2008 SUMMARY OPERATING DATA


			U.S. Exploitation
	Fayetteville		Arkoma		East		Permian/	New
	Shale Play		Basin		Texas		Gulf Coast ⁽¹⁾	Ventures⁽²⁾	Total
Estimated Proved Reserves:
Total Reserves (Bcfe)	1,545		281		351		-	8	2,185
Percent of Total	71%		13%		16%		-	-	100%
Percent Natural Gas	100%		100%		97%		-	100%	100%
Percent Proved Developed	52%		81%		89%		-	100%	62%

Production (Bcfe)	134.5		24.4		31.6		3.1	1.0	194.6
Capital Investments (millions)⁽³⁾	$ 1,191		$ 133		$ 160		$ 3	$ 73	$ 1,560
Total Gross Producing Wells	882		1,163		531		-	14	2,590
Total Net Producing Wells	639		584		428		-	10	1,661

Total Net Acreage	749,735	⁽⁴⁾	551,471	⁽⁵⁾	134,403	⁽⁶⁾	-	149,909	1,585,518
Net Undeveloped Acreage	552,254	⁽⁴⁾	357,792	⁽⁵⁾	98,529	⁽⁶⁾	-	138,638	1,147,213

PV-10:
Pre-tax (millions)⁽⁷⁾	$ 2,138		$ 392		$ 485		$ -	$ 9	$ 3,024
PV of taxes (millions)⁽⁷⁾	647		118		147		-	3	915
After-tax (millions)⁽⁷⁾	$ 1,491		$ 274		$ 338		$ -	$ 6	$ 2,109
Percent of Total	71%		13%		16%		-	-	100%
Percent Operated⁽⁸⁾	96%		86%		97%		-	84%	95%

(1) Our Permian Basin and onshore Texas Gulf Coast properties were sold during 2008.

(2) Includes New Ventures opportunities such as the Marcellus Shale play in Pennsylvania and our Riverton coalbed methane play in Louisiana.

(3) Our Total and Fayetteville Shale play capital investments exclude $36 million related to the purchase of drilling rig related and ancillary equipment.

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(4) Assuming successful wells are not drilled and leases are not extended, leasehold expiring over the next three years will be 94,473 net acres in 2009, 119,398 net acres in 2010 and 16,008 net acres in 2011.

(5) Includes 123,442 net developed acres and 1,930 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 and leases are not extended, leasehold expiring over the next three years will be 46,427 net acres in 2009, 32,648 net acres in 2010 and 35,963 net acres in 2011.

(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 38,973 net acres in 2009, 21,932 net acres in 2010 and 14,898 net acres in 2011.

(7) 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 gas reserves.

(8) Based upon pre-tax PV-10.

We refer you to Note 8 in our consolidated financial statements for a more detailed discussion of our proved natural gas and oil reserves as well as our standardized measure of discounted future cash flows related to our proved natural 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.

Fayetteville Shale Play

Our Fayetteville Shale play is now the primary focus of our E&P business. The Fayetteville Shale is an 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 shale is a Mississippian-age shale that is the geologic equivalent of the Caney Shale found on the Oklahoma side of the Arkoma Basin and the Barnett Shale found in north Texas. At December 31, 2008, we held leases for approximately 875,000 net acres in the play area (552,254 net undeveloped acres, 197,481 net developed acres held by Fayetteville Shale production, 123,442 net developed acres held by conventional production and an additional 1,930 net undeveloped acres in the traditional Fairway portion of the Arkoma Basin) down slightly from approximately 906,700 net acres at year-end 2007 due to the sale of 55,631 acres to XTO Energy, Inc. Approximately 1,545 Bcf of our reserves at year-end 2008 were attributable to our Fayetteville Shale play, compared to approximately 716 Bcf at year-end 2007 and 300 Bcf at year-end 2006. Gross production from our operated wells in the Fayetteville Shale play increased from approximately 325 MMcf per day at the beginning of 2008 to approximately 720 MMcf per day by year-end. Approximately 8 MMcf per day of our production at December 31, 2008 was from 22 wells producing from conventional reservoirs located in five counties. Our net production from the Fayetteville Shale play was 134.5 Bcf in 2008, compared to 53.5 Bcf in 2007 and 11.8 Bcf in 2006. In 2009, our estimated production from the Fayetteville Shale play is expected to range between 229 and 232 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 expiring upon the expiration date. At year-end 2008, approximately 26 % of our 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 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 undeveloped acreage position as of December 31, 2008 had an average lease term of 5 years, an average royalty interest of 15% and was obtained at an average cost of $140 per acre. 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, 2008, we had spud a total of 1,230 wells in the play, 1,015 of which were operated by us and 215 of which were outside-operated wells. Of the wells spud, 604 were in 2008, 415 were in 2007 and 196 were in 2006. Of the wells spud in 2008, 586 were designated as horizontal wells. At year-end 2008, 804 wells had been drilled and completed, including 726 horizontal wells. Of the 726 horizontal wells, 678 wells were fracture stimulated using either slickwater or crosslinked gel stimulation treatments, or a combination thereof.

During 2008, we continued to improve our drilling practices in the Fayetteville Shale play. Our horizontal wells had an average completed well cost of $3.0 million per well, 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. This compares to an average completed well cost of $2.9 million per well, average horizontal lateral length of 2,657 feet and average time to drill to total depth of 17 days from re-entry to re-entry during 2007. In 2006, our average completed well cost was $2.8 million per well with an average horizontal lateral length of 2,298 feet and average time to drill to total depth of 18 days from re-entry to re-entry. We also continued to improve our completion practices, as wells placed on production during 2008 averaged initial production rates

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of 2,777 Mcf per day, compared to average initial production rates of 1,687 Mcf per day and 1,510 Mcf per day in 2007 and 2006, respectively. During 2008, we began to test closer perforation cluster spacing in our horizontal wells with positive results. We tested this technique on approximately 200 of our wells which resulted in a 20% to 25% improvement in early production over average initial production of wells on which we did not utilize this technique. We estimate that ultimate recovery on these wells could be improved by a corresponding 20% to 25% over wells on which we did not utilize this technique and we are currently planning to utilize this technique on all planned wells in 2009. As part of our 2009 drilling program, we will also focus on optimizing the well spacing for the play.

Our total proved net gas reserves booked in the play at year-end 2008 were 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. Of the 1,508 locations, 1,446 were horizontal. The average gross proved reserves for the undeveloped wells included in our year-end reserves was approximately 1.9 Bcf, up from 1.5 Bcf per well at year-end 2007 and 1.15 Bcf per well at year-end 2006. Our gross proved reserves for wells that were placed on production in the second half of 2008 averaged 2.2 Bcf per well. Total proved gas reserves booked in the play in 2007 totaled approximately 716 Bcf from a total of 935 locations, of which 497 were proved developed producing, 14 were proved developed non-producing and 424 were proved undeveloped. Total proved gas reserves booked in the play in 2006 totaled approximately 300 Bcf from a total of 434 locations, of which 162 were proved developed producing, 9 were proved developed non-producing and 263 were proved undeveloped. If the Fayetteville Shale play continues to be successfully developed, over the next few years, we expect a continued significant level of proved undeveloped reserves in the Fayetteville Shale play.

In 2008, we invested approximately $1.2 billion in our Fayetteville Shale play, which included approximately $1.0 billion to spud 604 wells, and increased our reserves by 984 Bcf, which included upward reserve revisions of 159 Bcf due primarily to improved well performance in our Fayetteville Shale play. Included in this total was $23 million for leasehold acquisition, $61 million for seismic, and $83 million in capitalized costs and other expenses. In 2007, we invested approximately $960 million in our Fayetteville Shale play, which included $789 million to spud 415 wells, $25 million for leasehold acquisition, $97 million for 3-D seismic, and $49 million in capitalized costs and other expenses. In 2006, we invested approximately $388 million, which included $316 million to spud 196 wells, $29 million for leasehold acquisition, $14 million for seismic and $29 million in capitalized costs and other expenses.

In 2009, we plan to invest approximately $1.3 billion in our Fayetteville Shale play, which includes participating in approximately 650 horizontal wells, 500 of which will be operated by us. At December 31, 2008, we had acquired approximately 961 square miles of 3-D seismic data and plan to acquire approximately 139 square miles of 3-D seismic data during 2009, the total of which will give us seismic data on approximately 41% of our net acreage position in the Fayetteville Shale, excluding our acreage in the traditional Fairway portion of the Arkoma Basin.

We believe that our Fayetteville Shale acreage holds significant development potential. Our strategy going forward is to increase our production through development drilling as well as increase the amount of acreage we hold by production while determining 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

Conventional Arkoma Program. 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 and west into the Oklahoma portion of the basin. We refer to our drilling program targeting stratigraphic Atokan-age objectives in Oklahoma and Arkansas as the “conventional Arkoma” drilling program.

At December 31, 2008, we had approximately 281 Bcf of reserves which were attributable to our conventional Arkoma properties, representing approximately 13% of our total reserves, compared to 304 Bcf at year-end 2007 and 277 Bcf at year-end 2006. In 2008, we invested approximately $133 million and participated in 81 wells in our conventional Arkoma drilling program, of which 67 were successful and 8 were in progress at year-end, resulting in a 92% success rate and adding new reserves of 37 Bcf. This area recorded net downward revisions of approximately 36 Bcf primarily due to a comparative decrease in year-end gas prices and negative performance revisions. Net production from our conventional

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Arkoma properties was 24.4 Bcf in 2008, compared to 23.8 Bcf in 2007 and 20.1 Bcf in 2006. Production over the last few years from the basin has risen as new production stemming from our drilling program has more than offset the natural production decline from existing wells.

Our strategy in the Arkoma Basin is to identify trends using our extensive expertise in the area. In recent years, we have extended our development program into other areas of the basin that had previously been less explored, primarily the Ranger Anticline area and the Midway area, which was our primary focus in 2008.

We began drilling at our Midway prospect area located approximately 11 miles north of Ranger in 2005 and, through year-end 2008, we had drilled a total of 59 wells. Our wells at Midway have primarily targeted the Basham and Borum tight gas sands between 3,500 and 6,000 feet in depth, and net production from the area was 2.7 Bcf in 2008, compared to 0.8 Bcf in 2007 and 0.1 Bcf in 2006. At year-end 2008, we held approximately 31,000 gross acres in our Midway prospect area.

The Ranger Anticline is located at the southern edge of the Arkansas portion of the basin. From 1997 through year-end 2008, we had successfully drilled 215 wells at Ranger. Net production from the field was 9.5 Bcf in 2008, compared to 9.5 Bcf in 2007 and 5.7 Bcf in 2006. At December 31, 2008, we held approximately 96,640 gross acres at Ranger, of which 24,320 acres were developed.

In 2009, we plan to invest approximately $60 million in our conventional Arkoma program and will drill approximately 25 wells.

East Texas. Our East Texas operations are primarily located in the Overton Field in Smith County, Texas, and our Angelina River Trend area located in Angelina, Nacogdoches, San Augustine and Shelby Counties in Texas. At December 31, 2008, we had approximately 351 Bcfe of reserves in East Texas, compared to 353 Bcfe at year-end 2007 and 383 Bcfe at year-end 2006. In 2008, we invested approximately $160 million in East Texas and participated in 50 wells, of which 42 were successful and 8 were in progress at year-end, resulting in a 100% success rate and adding new reserves of 53 Bcfe. This area recorded net downward revisions of approximately 23 Bcfe primarily due to a comparative decrease in year-end gas prices and negative performance revisions. Net production from East Texas was 31.6 Bcfe in 2008, compared to 29.9 Bcfe in 2007 and 32.0 Bcfe in 2006. Production during 2008 grew primarily due to our successful drilling program in the James Lime formation in the Angelina River Trend area which more than offset the natural production decline in our Overton Field.

Our original interest in the Overton Field (which was approximately 10,800 gross acres) was acquired in April 2000 for $6 million. Our wells in the Overton Field produce from four Taylor series sands in the Cotton Valley formation at approximately 12,000 feet. At December 31, 2008, we held approximately 24,400 gross acres in the Overton Field with an average working interest of 85% and an average net revenue interest of 68%. Our proved reserves in the Overton Field were 273 Bcfe at year-end 2008, compared to 315 Bcfe at year-end 2007 and 367 Bcfe at year-end 2006. In 2008, we invested approximately $16 million to drill nine wells at the Overton Field, all of which were successful. Net production from our Overton Field was 19.9 Bcfe in 2008, compared to 25.1 Bcfe in 2007 and 29.8 Bcfe in 2006. We expect our production from the Overton field to continue to decline in 2009 due to the continued lack of significant investment in the further development of the field 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, Pettet and James Lime formations. At December 31, 2008, we held approximately 86,400 gross undeveloped acres and 16,700 gross developed acres at Angelina with an average working interest of 67% and an average net revenue interest of 52%. In 2008, we invested approximately $112 million to drill 41 wells at Angelina, all of which were successful or in progress at December 31, 2008. Our 2008 drilling program was primarily focused on developing the James Lime formation in our Jebel prospect area located in Shelby County, Texas. During 2008, we participated in 32 James Lime horizontal wells (20 of which we operated) and placed 15 wells that we operated on production at an average gross initial production rate of 9.1 MMcfe per day. Our proved reserves in the Angelina area were 74 Bcfe at year-end 2008, compared to 33 Bcfe at year-end 2007 and 16 Bcfe at year-end 2006. Net production from our Angelina properties was 11.3 Bcfe in 2008, compared to 2.5 Bcfe in 2007 and 1.8 Bcfe in 2006.

In 2009, we plan to invest up to $110 million to drill approximately 40 wells in East Texas, 34 of which are planned to be horizontal wells targeting the James Lime formation at Angelina.

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Permian Basin and Gulf Coast. During 2008, we sold the oil and 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 46,200 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. Net production from these areas during 2008 was 3.1 Bcfe, compared to 6.1 Bcfe in 2007 and 8.4 Bcfe in 2006. The sale also included approximately 49,500 acres which were located in Culberson County, Texas, in the Barnett Shale play in the Permian Basin.

New Ventures

We actively seek to find and develop new oil and 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) 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 both inside and outside of the United States. At December 31, 2008, we held 138,638 net undeveloped acres in the United States outside of our core operating areas in connection with New Ventures prospects. This compares to 156,465 net undeveloped acres held at year-end 2007 and 89,592 net undeveloped acres held at year-end 2006.

In 2008, we invested approximately $73 million in our New Ventures program, including approximately $58 million in the Marcellus Shale play in Pennsylvania. At year-end 2008, we had approximately 114,738 net acres in Pennsylvania under which we believe the Marcellus Shale is prospective at a total cost of $530 per acre. During 2008, we 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 the first quarter of 2009, we purchased approximately 21,715 net acres in Lycoming County, Pennsylvania, for approximately $8.2 million. Including this acreage acquisition, we currently have approximately 137,000 net undeveloped acres in Pennsylvania where we are targeting the Marcellus Shale.

In 2007, we invested approximately $42 million in our New Ventures program, including $17.5 million to purchase acreage in the Marcellus Shale play. We also invested approximately $10.5 million in 2007 to spud 25 wells in our Riverton coalbed methane project in Caldwell Parish, Louisiana, of which all were successful. We have approximately 35,200 net acres in this project area targeting the Tertiary-age lower Wilcox coals at a depth of approximately 2,800 feet. Additionally in 2007, we invested $5.2 million to participate in 5 outside-operated Woodford Shale wells in Oklahoma. In 2006, we invested approximately $46 million as part of our New Ventures program to purchase acreage and drill 7 exploration wells, of which 5 were successful.

In 2009, we plan to invest approximately $80 million in various unconventional, exploration and New Ventures projects, including the Marcellus Shale play in Pennsylvania.

Acquisitions and Divestitures

During 2008, we sold the oil and 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 gas leases, wells and gathering equipment in our Fayetteville Shale play to XTO Energy, Inc. for approximately $518.3 million in cash. 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.

There were no significant acquisitions of gas and oil properties in 2008 or 2007.

In 2006, we sold our remaining South Louisiana properties to a private company for $12.7 million. These properties had proved reserves of 7.0 Bcfe and produced approximately 1.1 Bcfe annually. In 2006, we acquired additional working interests in our Overton Field for approximately $9 million and also acquired interests in our Riverton coalbed methane project located in Caldwell Parish, Louisiana, for approximately $9 million.

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Capital Investments

During 2008, we invested a total of $1.6 billion in our E&P business and participated in drilling 750 wells, 479 of which were successful, 11 were dry and 260 were in progress at year-end. Of the 260 wells in progress at year-end, 236 were located in our Fayetteville Shale play. Our investments focused primarily on our active drilling programs in the Fayetteville Shale play, East Texas and the conventional Arkoma Basin, which accounted for 76%, 10% and 8% of our E&P capital investments in 2008, respectively. We invested approximately $1.2 billion in our Fayetteville Shale play, $160 million in East Texas, $133 million in our conventional Arkoma Basin program and $73 million in New Ventures projects.

Of the $1.6 billion invested in 2008, approximately $1.3 billion was invested in exploratory and development drilling and workovers, $83 million for leasehold acquisition, $66 million for seismic expenditures and $118 million in capitalized interest and expenses and other technology-related expenditures. Additionally, we invested approximately $36 million in drilling rig related and ancillary equipment. In 2007, we invested approximately $1.4 billion in our primary E&P business activities and participated in drilling 653 wells. Of the $1.4 billion invested in 2007, approximately $1.1 billion was invested in exploratory and development drilling and workovers, $66 million for leasehold acquisitions, $100 million for seismic expenditures, $2 million for producing property acquisitions and $77 million in capitalized interest and expenses and other technology-related expenditures. In 2006, we invested approximately $767 million in our primary E&P business activities and participated in drilling 382 wells. Additionally, we invested $94 million for the purchase of drilling rigs and related equipment which were sold in December 2006 as part of a sale and leaseback transaction. Of the $767 million invested in 2006, approximately $196 million was invested in exploratory drilling, $421 million in development drilling and workovers, $49 million for leasehold acquisition, $21 million for seismic expenditures, $18 million for producing property acquisitions and $62 million in capitalized interest and expenses and other technology-related expenditures. The increases in capital investments and wells drilled over the last three years are primarily due to the acceleration of our drilling program in the Fayetteville Shale play.

In 2009, we plan to invest approximately $1.6 billion in our E&P program and participate in drilling 715 wells. The Fayetteville Shale play will be the primary focus of our capital investments, where we plan to invest approximately $1.3 billion. Our capital investments will also include up to $110 million in East Texas, approximately $60 million in our conventional drilling program in the Arkoma Basin, $80 million in unconventional, exploration and New Ventures projects and $40 million for other E&P projects.

Of the $1.6 billion allocated to our 2009 E&P capital budget, approximately $1.3 billion will be invested in development and exploratory drilling, $56 million in seismic and other geologic and geophysical expenditures, $58 million in leasehold, and $228 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 our planned capital investments in 2009.

Other Revenues

Other revenues and operating income for 2008, 2007 and 2006 included pre-tax gains of approximately $4.8 million, $6.4 million and $4.0 million, respectively, related to the sale of gas-in-storage inventory.

Sales and Major Customers

Our daily natural gas equivalent production averaged 533.1 MMcfe in 2008, compared to 311.1 MMcfe in 2007 and 198.1 MMcfe in 2006. Total natural gas equivalent production was 194.6 Bcfe in 2008, up from 113.6 Bcfe in 2007 and 72.3 Bcfe in 2006. Our natural gas production was 192.3 Bcf in 2008, compared to 109.9 Bcf in 2007 and 68.1 Bcf in 2006. The increase in production in 2008 resulted primarily from an 81.0 Bcf increase in production from the Fayetteville Shale play. Increases in our East Texas and Arkoma net production were offset by decreases resulting from sales of oil and gas properties that occurred during 2008. The increase in production in 2007 resulted primarily from a 41.7 Bcf increase in production from the Fayetteville Shale play and a 3.7 Bcf increase in production from our conventional Arkoma Basin activities, offset by a 2.3 Bcfe decrease in our Gulf Coast and Permian Basin production and a 2.1 Bcfe decrease in our East Texas production. The increase in 2006 production resulted primarily from a 10.0 Bcf increase in production related to our Fayetteville Shale play and a 4.0 Bcfe increase in production from East Texas, partially offset by a decrease in production from our Gulf Coast and Permian Basin properties. We also produced 385,000 barrels of oil in 2008, compared to 614,000 barrels of oil in 2007 and 698,000 barrels of oil in 2006. Our oil production decreased during 2008 due to the sale of our Permian and Gulf Coast properties in the second and third quarters of 2008. For 2008, we are targeting total

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natural gas and crude oil production of approximately 280 to 284 Bcfe, which equates to a growth rate of approximately 45% above our 2008 production volumes.

A portion of our gas production is sold to Arkansas Western Gas Company, or AWG, our former subsidiary which is now owned by SourceGas, LLC. SEECO’s sales to AWG were 4.3 Bcf in 2008, compared to 4.8 Bcf in 2007 and 4.7 Bcf in 2006. In connection with the sale of AWG to SourceGas effective on July 1, 2008, SEECO signed a five-year natural gas services agreement with AWG pursuant to which AWG, among other things, will transport SEECO’s production on its gathering system to industrial and commercial end-users on AWG’s system. SEECO’s sales to AWG are dependant upon its ability to successfully bid for AWG gas supply contracts in a competitive bidding process. SEECO also owns an unregulated natural gas storage facility connected to AWG’s distribution system that has historically been utilized to help meet its peak seasonal sales commitments and has in the past provided a competitive advantage in the bidding process. Future sales to AWG will be dependent upon SEECO’s success in obtaining gas supply contracts from them. Sales to AWG accounted for approximately 2% of total E&P revenues in 2008, 4% in 2007 and 7% in 2006.

Sales of gas and oil production are conducted under contracts that reflect current short-term 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, 2008, we had hedges in place on 135 Bcf, or approximately 48% of our targeted 2009 gas production, and 50 Bcf of our expected 2010 gas production. We intend to hedge additional future production volumes in the event that natural gas prices rise to levels that protect 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, 2008.

We realized an average wellhead price of $7.52 per Mcf for our natural gas production in 2008, compared to $6.80 per Mcf in 2007 and $6.55 per Mcf in 2006, including the effect of hedges. Our hedging activities decreased our average gas price $0.21 per Mcf in 2008 and increased our average price $0.64 per Mcf in 2007 and $0.18 per Mcf in 2006. Our average oil price realized was $107.18 per barrel in 2008, compared to $69.12 per barrel in 2007 and $58.36 per barrel in 2006, including the effect of hedges. None of our crude oil production was hedged during 2008 or 2007. Our hedging activities lowered our average oil price $4.81 per barrel in 2006.

Disregarding the impact of hedges, the average price received for our gas production has historically been approximately $0.30 to $0.50 per Mcf lower than average NYMEX spot market prices. However, during 2008, 2007 and 2006, widening market differentials caused the difference in our average price received for our gas production to be approximately $0.70 to $1.30 per Mcf lower than spot market prices. The discount was at its widest point in late 2008 due to the impact that the delay in the completion of Boardwalk Pipeline had upon the Centerpoint East differential. Assuming a NYMEX commodity price of $6.00 per Mcf of gas for 2009, the average price received for our gas production is expected to be approximately $0.75 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges.

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 recently 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 natural gas distribution business.

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Sales of crude oil, condensate and gas liquids are not regulated and are made at negotiated prices. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil that allowed for an increase in the cost of transporting oil to the purchaser. The implementation of these regulations has not had a material adverse effect on our results of operations.

Competition

All phases of the oil and 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 gas companies, other independent oil and 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 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 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 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. Our midstream assets support our E&P operations and are currently concentrated in our Fayetteville Shale play. We generate revenue from gathering fees associated with the transportation of natural gas to market and through the marketing of our own gas production and some third-party natural gas.

Our operating income from this segment was $62.3 million on revenues of $2.2 billion in 2008, compared to $13.2 million on revenues of $962.0 million in 2007 and $4.1 million on revenues of $475.2 million in 2006. The increases in revenues are largely attributable to increased gathering revenues, increased volumes marketed and higher purchased gas costs. EBITDA generated by our midstream services segment was $73.9 million in 2008, compared to $18.8 million in 2007 and $5.3 million in 2006. The increase in 2008 and 2007 operating income and EBITDA was 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 with our net income.

Gas Gathering

We engage in gas gathering activities through our gathering subsidiaries, DeSoto Gathering Company, L.L.C. and Angelina Gathering Company, L.L.C., which we refer to as DGC and AGC, respectively. DGC engages in gathering activities in Arkansas primarily related to the development of our Fayetteville Shale play. In 2008, we invested

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approximately $183.0 million related to these activities and had gathering revenues of $114.9 million, compared to $107.4 million invested and revenues of $37.7 million in 2007 and $48.7 million invested and $7.9 million in revenues in 2006. DGC is rapidly expanding its network of gathering pipelines and facilities throughout the Fayetteville Shale region. During 2008, DGC gathered approximately 208.3 Bcf of gas volumes in the Fayetteville Shale play area, including 23.8 Bcf of third-party natural gas. In 2007, DGC gathered approximately 78.7 Bcf of gas volumes in the Fayetteville Shale play area, including 7.6 Bcf of third-party natural gas. In 2006, DGC gathered approximately 14.6 Bcf of gas. The increase in volumes gathered in 2008 and 2007 was primarily due to our growing production volumes from the Fayetteville Shale play. At the end of 2008, DGC had approximately 843 miles of pipe from the individual wellheads to the transmission lines and compression equipment had been installed at 37 central point gathering facilities in the field. AGC currently engages in gathering activities in East Texas in connection with our Angelina properties. AGC provides gathering support for all of our E&P operations outside of Arkansas. At year-end 2008, AGC had approximately 9 miles of pipeline in Texas. 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.

Gas Marketing

Our gas marketing subsidiary, SES, allows us to capture downstream opportunities which arise through marketing and transportation activity. SES not only purchases, sells and schedules natural gas to be delivered to certain end-users, but also is involved in basis management, marketing portfolio management and acquiring transportation rights on pipelines. Our current marketing operations primarily relate to the marketing of our own gas production and some third-party natural gas. During 2008, we marketed 258.0 Bcf of natural gas, compared to 145.7 Bcf in 2007 and 72.7 Bcf in 2006. Purchases from our E&P subsidiaries accounted for 96% of total volumes marketed in 2008, compared to 89% in 2007 and 85% in 2006.

On December 15, 2006, due to the significant growth of future production volumes from our operations in the Fayetteville Shale play, SES signed a precedent agreement with Texas Gas Transmission, LLC (Texas Gas), a subsidiary of Boardwalk Pipeline Partners, LP, for the construction of two pipeline laterals to serve the Fayetteville Shale play. Pursuant to the precedent agreement with Texas Gas, in the third quarter of 2008, SES entered into firm transportation agreements with Texas Gas relating to its commitments for the Fayetteville and Greenville Laterals. SES’ options to increase the volumes to be transported on each of the laterals were fully exercised in 2008 and 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.

During 2008, the majority of our 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.” On December 24, 2008, the Phase 1 facilities of the Fayetteville Lateral portion of the Texas Gas Pipeline began transporting gas to markets. We expect the Phase 2 facilities, which include the Greenville Lateral that originates at the Texas Gas mainline system near Greenville, Mississippi, and extends eastward to interconnect with various interstate pipelines, to be placed in-service during the second quarter of 2009. When the Phase 2 facilities of the Texas Gas Pipeline are placed in-service, our transportation agreements will give us access to additional markets east of the Mississippi river which could result in increasing our average wellhead price. The Fayetteville and Greenville laterals will transport our gas to markets in the eastern United States and will 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.

On September 30, 2008, again due to anticipated significant growth of future production volumes from our operations in the Fayetteville Shale play, SES entered into a precedent agreement pursuant to which it will contract for firm gas transportation services on a proposed new pipeline of Fayetteville Express Pipeline LLC, which is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P. SES will be a “Foundation Shipper” for the project and will use the new pipeline primarily to deliver gas volumes produced from our operations in the Fayetteville Shale play to eastern markets. Pending regulatory approvals, the pipeline is expected to be in-service by late 2010 or early 2011. The proposed pipeline will have an estimated ultimate capacity of up to 2.0 Bcf per day. Following the approval of the pipeline by the Federal Energy Regulatory Commission, or FERC, and subject to certain conditions, pursuant to the precedent agreement, SES will enter into a firm transportation agreement to transport up to 1,200,000 Dekatherms per day for an initial term of ten years.

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Competition

Our gas 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 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. We also experience competition for our gathering services from other producers and non-affiliated gathering companies and we expect this competition to continue in the future.

Regulation

On March 15, 2006, the Department of Transportation, or the 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 National Gas Act and delivers on average more than 50 million MMBtu of gas annually over a three year period. Our gathering system constitutes a “major non-interstate pipeline” under Order No. 720 and will be required to comply with the requirements of Order No. 720 once they become effective for major non-interstate pipelines. On December 11, 2008, the American Gas Association filed a Motion for an Extension of Time to Comply with Order No. 720 arguing that some major non-interstate pipelines will need additional time in which to determine which receipt and delivery points are subject to the posting requirements, obtain corporate approval for expenditures needed for compliance and develop internet posting systems. On January 15, 2009, FERC granted an extension of time for major non-interstate pipelines to comply with the requirements of Order No. 720 until 150 days following the issuance of an order addressing the pending requests for rehearing.

Natural Gas Distribution

Effective July 1, 2008, we sold all of the capital stock of Arkansas Western Gas Company (“AWG”) to SourceGas, L.L.C. 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 AWG 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.

AWG provided operating income for the first half of 2008 of $10.7 million, compared to $10.0 million for the entire year of 2007 and $4.5 million for the entire year of 2006.

Transportation and Other

On May 2, 2006, we sold our 25% interest in NOARK Pipeline System, Limited Partnership (NOARK), a partnership that owns a 723-mile integrated interstate pipeline system known as Ozark Gas Transmission System, to Atlas Pipeline Partners, L.P. for $69.0 million, resulting in a pre-tax gain of $10.9 million. In connection with the sale, we assumed $39.0 million of partnership debt that we had previously guaranteed. Our share of NOARK’s results of operations was a pre-tax gain of $0.9 million in 2006 prior to the sale.

Our other operations have primarily consisted of the activities of our wholly-owned subsidiary, A. W. Realty Company, a company with real estate development activities concentrated on tracts of land located in Arkansas. There were no sales of commercial real estate in 2008, 2007 or 2006. As of December 31, 2008, A. W. Realty Company owned our office complex in Fayetteville, Arkansas, an interest in approximately 15 acres of undeveloped real estate near the Fayetteville complex and 457 acres in or near Conway, Arkansas, related to our operations in the Fayetteville Shale play.

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Other Items

Reconciliation of Non-GAAP Measures

EBITDA is defined as net income 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, 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 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 is the financial measure calculated and presented in accordance with generally accepted accounting principles in the United States that is most directly comparable to EBITDA as defined. The following table reconciles EBITDA,as defined, with net income for the years-ended December 31, 2008, 2007 and 2006:


		Midstream	Natural Gas
	E&P	Services	Distribution	Other	Total
	(in thousands)
2008
Net income...................................................................	$ 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

2007
Net income (loss)........................................................	$ 211,876	$ 6,933	$ 2,746	$ (381)	$ 221,174
Depreciation, depletion and amortization...............	282,387	5,527	6,423	163	294,500
Net interest expense...................................................	16,926	2,006	4,941	—	23,873
Provision for income taxes........................................	129,315	4,294	1,672	574	135,855
EBITDA........................................................................	$ 640,504	$ 18,760	$ 15,782	$ 356	$ 675,402

2006
Net income...................................................................	$ 151,157	$ 2,976	$ 2,190	$ 6,313	$ 162,636
Depreciation, depletion and amortization...............	143,500	1,773	6,428	94	151,795
Net interest expense...................................................	508	—	171	—	679
Provision for income taxes........................................	91,276	554	1,698	5,871	99,399
EBITDA........................................................................	$ 386,441	$ 5,303	$ 10,487	$ 12,278	$ 414,509

Environmental Matters

Our operations are subject to numerous federal, state and local laws and regulations including the Comprehensive Environmental Response, Compensation and Liability Act, or 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 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

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regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this trend 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 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.

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We utilize hydraulic fracturing in connection with certain of our E&P operations. In hydraulic fracturing, large quantities of water, sand, and certain additives are 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 gas to flow out of the formation and into the wellbore. A 2004 study conducted by the EPA found that hydraulic fracturing posed no risk to drinking water and Congress exempted hydraulic fracturing from the Safe Drinking Water Act. 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 Safe Drinking Water Act or to enact legislation at the state and local government levels that would regulate the impact of hydraulic fracturing on drinking water supply. If the exemption for hydraulic fracturing is removed from the Safe Drinking Water Act, or if legislation is enacted at the state and local level, it could have a significant impact on the natural gas industry as a whole and on our financial condition and results of operation.

Employees

At December 31, 2008, we had 1,367 total employees. None of our employees were covered by a collective bargaining agreement at year-end 2008. We believe that our relationships with our employees are good.

GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below shall apply to the indicated terms as used in this Form 10-K. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“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 gas.

“Bcfe” One billion cubic feet of 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).

“Development drilling” The drilling of a well within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“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 attributable to common stock plus interest, income taxes, depreciation, depletion and amortization. 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 from our audited financial statements.

“Exploration prospects or locations” A location where a well is drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

“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 acreage or gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

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

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“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 acres or net wells” The sum of the fractional working interests owned in gross acres or gross wells.

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

“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 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 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.

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

“Proved developed reserves” Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. For additional information, see the SEC’s definition in Rule 4-10(a)(3) 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” The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. For additional information, see the SEC’s definition in Rule 4-10(a)(2)(i) through (iii) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Proved undeveloped reserves” Proved reserves 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. Reserves on undrilled acreage shall be limited to those drilling units that offset productive units and that are reasonably certain of production when drilled. For additional information, see the SEC’s definition in Rule 4-10(a)(4) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“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.

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“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.

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

“Tcf” One trillion cubic feet of gas.

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

“Unconventional play” A play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds, and (3) 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 stimulation treatments or other special recovery processes in order to produce economic flow rates.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

“Well spacing” The regulation of the number and location of wells over an oil or gas reservoir, as a conservation measure. Well spacing is normally accomplished by order of the regulatory conservation commission. 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.

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;

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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 may widen due to pipeline or other constraints. Price volatility makes it difficult to budget and 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. A continued or extended 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.

Lower natural gas and oil prices 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 hedges. They also require a write-down if the ceiling limit is exceeded, even if prices declined for only a relatively short period of time. Once a write-down is taken, it cannot be reversed in future periods even if natural gas and oil prices increase.

If natural gas and oil prices decline below levels at December 31, 2008, a write-down may occur. Write-downs required by these rules do not impact cash flow from operating activities but do reduce net income and stockholders' equity.

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 2009 are expected to significantly exceed the net cash generated by our operations. 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, 2008, 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

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untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our results and future operations.

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 be unable or unwilling to pay their share of well costs as they become due. These problems 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 NSA, an independent petroleum engineering firm. In conducting its audit, the engineers and geologists of NSA study our major properties in detail and independently develop reserve estimates. NSA’s audit consists primarily of substantive testing, which includes a detailed review of major properties that account for approximately 83% of the present worth of our total proved reserves. NSA’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 the lowest value properties and are not reviewed in the audit. The fields included in approximately the top 83% present value as of December 31, 2008 accounted for approximately 83% of our total proved reserves and approximately 92% of our proved undeveloped reserves. In the conduct of its audit, NSA did not independently verify the data that we provided to them with respect to ownership interests, oil and gas production, well test data, historical costs of operations and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. NSA 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, NSA 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. The estimates of Netherland, Sewell & Associates, Inc. may differ significantly on an individual property basis from our estimates. When, in the aggregate, such differences are within 10%, Netherland, Sewell & Associates, Inc. is generally satisfied that the estimates of proved reserves are reasonable.

Reserve estimates are 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 President and Chief Operating Officer. Finally, the estimates of our proved reserves together with the audit report of Netherland, Sewell & Associates, Inc. are reviewed by our Board of Directors. There are 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 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 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, operating and development costs and other factors. 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 gas prices combined with the performance revisions in some of our East Texas and conventional Arkoma Basin properties. In 2007, our reserves were revised upward by 31.0 Bcfe, primarily due to improved performance in our Fayetteville Shale properties, which was partially offset by a downward revision in our Overton properties. In 2006, our reserves were revised downward by 86.6 Bcfe, primarily due to lower prevailing oil and gas prices at year-end combined with performance revisions in some of our East Texas and conventional Arkoma Basin properties, which were partially

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offset by an upward performance revision in our Fayetteville Shale properties. These revisions represented no greater than 8% 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, 2008, approximately 840 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, 2008 and at February 23, 2009, we had total indebtedness of $735.4 million, with no amounts borrowed under our revolving credit facility. In January 2008, we issued $600 million of senior notes and used the net proceeds to repay outstanding amounts 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 2009. 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, 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;

redeeming stock or redeeming debt;

making investments;

creating liens on our assets; and

selling 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, and in the case of the master lease agreement, loss of use of our drilling rigs. 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 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

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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, through engineering studies, 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, 2008, we had drilled and completed 804 wells relating to our Fayetteville Shale play. At year-end 2008, approximately 26% 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 or complete 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 229,879 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. 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.

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

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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 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 gas uneconomic, which could have an adverse effect on our results of operations, financial condition and cash flows.

As of December 31, 2008, we had invested approximately $342.3 million in our gas gathering operations and we intend to invest approximately $220 million in 2009. Our gas gathering business will largely rely on gas sourced in our Fayetteville Shale play area in Arkansas. In addition, we have signed 10-year firm transportation agreements committing us to transportation on the Fayetteville and Greenville laterals being built by Texas Gas Transmission, LLC, a subsidiary of Boardwalk Pipeline Partners, LP, or Texas Gas, to service the Fayetteville Shale play area. We have also entered into a precedent agreement with Fayetteville Express Pipeline LLC, which is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P., with respect to another pipeline for the Fayetteville Shale play, pursuant to which we will have significant firm transportation commitments if the pipeline is built. Our marketing subsidiary has also entered into multiple other firm transportation agreements relating to gas volumes from our Fayetteville Shale play. 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 transportation fees on pipeline capacity 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 distribution and marketing operations are regulated extensively at the federal, state and local levels. We have made and will continue to make large expenditures in our efforts to comply with these regulations, including environmental regulation. The natural gas and oil regulatory environment could change in ways that might substantially increase these costs. Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights. These regulations affect our operations and limit the quantity of hydrocarbons we may produce and sell. In addition, at the U.S. federal level, the Federal Energy Regulatory Commission regulates interstate transportation of natural gas under the Natural Gas Act. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments.

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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. Effective January 1, 2003, companies were required to reflect abandonment costs as a liability on their balance sheets. We may incur significant abandonment costs in the future which could adversely affect our financial results.

Natural gas and oil drilling and producing operations involve various 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 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, 2008, approximately 5% of our gas and oil properties, based on PV-10 value, 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 are relying on third parties to construct additional interstate pipelines to increase our ability to bring our production to market. The Fayetteville and Greenville laterals being built by Texas Gas were supposed to be fully available in January 2009 but are experiencing delays. Delays in the commencement of operations of the new pipelines, the unavailability of the new 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.

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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. For example, during the last half of 2006, we had difficulty obtaining additional well completion services due to a shortage of completion crews in our Fayetteville Shale play area, which resulted in a higher inventory of wells that had been drilled but were awaiting completion. There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher natural gas and oil prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. 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 drilling rig operations and we have significant commitments with third-party drilling companies.

We have made significant investments in our drilling rig operations, including lease commitments for 14 drilling rigs and related equipment and have hired, as of December 31, 2008, 371 employees for our drilling subsidiary, DeSoto Drilling, Inc. We also own one drilling rig. In addition to the rigs we are leasing, we have contracts for third-party drilling companies for use of their rigs which may not be terminable without penalty. Our drilling rig operations may have an adverse effect on our relationships with our existing third-party rig providers or our ability to secure third-party rigs from other providers. We may also compete with third-party rig providers for qualified personnel, which could adversely affect our relationships with rig providers. If our existing third-party rig providers discontinue their relationships with us, we may not be able to secure alternative rigs on a timely basis, or at all. Even if we are able to secure alternative rigs, there can be no assurance that replacement rigs will be of equivalent quality or that pricing and other terms will be favorable to us. If we are unable to secure third-party rigs or if the terms are not favorable to us, our financial condition and results of operations could be adversely affected.

We have limited experience in operating drilling rigs.

We cannot assure you that we will be able to continue to attract and retain qualified field personnel to operate our drilling rigs or to otherwise effectively conduct our drilling operations. If we are unable to retain qualified personnel or to effectively conduct our drilling operations, our financial and operating results may 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.

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Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

To reduce our exposure to fluctuations in the prices of natural gas and oil, we enter into hedging arrangements with respect to a portion of our expected production. As of December 31, 2008, we had hedges on approximately 48% of our targeted 2009 natural gas production. Our price risk management activities decreased revenues by $40.5 million in 2008, and increased revenues by $70.7 million in 2007 and $8.7 million in 2006. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits 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 certificate of incorporation, bylaws, and stockholder rights plan contain provisions that could make it more difficult for someone to either acquire us or affect a change of control.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES

For additional information about our natural gas and oil operations, we refer you to Notes 7 and 8 to the consolidated financial statements. For information concerning capital investments, we refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Investments.” We also refer you to Item 6, “Selected Financial Data” in Part II of this Form 10-K for information concerning natural gas and oil produced.

The following information is provided to supplement the information that is presented in Item 8 of Part II of this Form 10-K. For a further description of our natural gas and oil properties, we refer you to “Business — Exploration and Production.”

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Leasehold acreage as of December 31, 2008:


	Undeveloped		Developed
	Gross	Net	Gross	Net
Fayetteville Shale Play⁽¹⁾.....................	897,200	552,254	283,520	197,481
U. S. Exploitation:
Conventional Arkoma⁽²⁾....................	462,898	357,792	299,578	193,679
East Texas⁽³⁾........................................	131,732	98,529	48,655	35,874
New Ventures⁽⁴⁾....................................	143,765	138,638	14,085	11,271
	1,635,595	1,147,213	645,838	438,305

(1) Assuming we do not drill successful wells to develop the acreage and do not extend the leases in our undeveloped acreage in the Fayetteville Shale play, leasehold expiring over the next three years will be 94,473 net acres in 2009, 119,398 net acres in 2010 and 16,008 net acres in 2011.

(2) Includes 123,442 net developed acres and 1,930 net undeveloped acres in our Conventional Arkoma Basin operating area that are also within our Fayetteville Shale focus area but not included in the Fayetteville Shale acreage above. Assuming we do not drill successful wells to develop the acreage and do not extend the leases in our undeveloped acreage in the Conventional Arkoma Basin, leasehold expiring over the next three years will be 46,427 net acres in 2009, 32,648 net acres in 2010 and 35,963 net acres in 2011.

(3) Assuming we do not drill successful wells to develop the acreage and do not extend the leases in our undeveloped acreage in East Texas, leasehold expiring over the next three years will be 38,973 net acres in 2009, 21,932 net acres in 2010 and 14,898 net acres in 2011.

(4) Includes New Ventures project acreage in the Marcellus Shale play in Pennsylvania and our Riverton coalbed methane play in Louisiana.

Producing wells as of December 31, 2008:


	Gas		Oil		Total		Gross Wells
	Gross	Net	Gross	Net	Gross	Net	Operated
Fayetteville Shale Play..............	882	639	—	—	882	639	731
U. S. Exploitation
Conventional Arkoma.............	1,163	584	—	—	1,163	584	558
East Texas….............................	528	425	3	3	531	428	489
New Ventures.............................	14	10	—	—	14	10	11
	2,587	1,658	3	3	2,590	1,661	1,789

Wells drilled during the year:


	Exploratory

	Productive Wells		Dry Holes		Total
Year	Gross	Net	Gross	Net	Gross	Net
2008..........................	34.0	22.4	2.0	2.0	36.0	24.4
2007..........................	97.0	69.4	5.0	3.7	102.0	73.1
2006..........................	48.0	40.0	4.0	2.3	52.0	42.3


	Development

	Productive Wells		Dry Holes		Total
Year	Gross	Net	Gross	Net	Gross	Net
2008..........................	445.0	270.2	9.0	6.8	454.0	277.0
2007..........................	342.0	225.2	12.0	8.5	354.0	233.7
2006..........................	182.0	138.8	5.0	3.4	187.0	142.2

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Wells in progress as of December 31, 2008:


	Gross	Net
Exploratory.......................................	18.0	11.1
Development...................................	242.0	165.4
Total..................................................	260.0	176.5

During 2008, 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 8 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, 2008, our Midstream Services segment had 882 miles and 9 miles of pipe in its gathering systems located in Arkansas and Texas, respectively.

Title to Properties

We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we perform a title investigation that is thorough but less vigorous than that conducted prior to drilling, which is consistent with standard practice in the oil and gas industry. Before we commence drilling operations on properties that we operate, we conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations. We have performed a thorough title examination with respect to substantially all of our active properties that we operate.

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 or reported results of operations.

We are subject to litigation and claims that have arisen in the ordinary course of business. Management believes, individually or in aggregate, such litigation and claims 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 and the results of operations for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

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EXECUTIVE OFFICERS OF THE REGISTRANT


Name	Officer Position	Age	Years Served as Officer
Harold M. Korell	Chief Executive Officer and Chairman of the Board	64	12
Steven L. Mueller	President and Chief Operating Officer	55	—
Greg D. Kerley	Executive Vice President and Chief Financial Officer	53	19
Mark K. Boling	Executive Vice President, General Counsel and Secretary	51	7
Gene A. Hammons	President, Southwestern Midstream Services Company	63	4

Mr. Korell was elected as Chairman of the Board in May 2002 and has served as Chief Executive Officer since January 1999. He also served as President from October 1998 to May 2008. He joined us in 1997 as Executive Vice President and Chief Operating Officer. From 1992 to 1997, he was employed by American Exploration Company where he was most recently Senior Vice President-Operations. From 1990 to 1992, he was Executive Vice President of McCormick Resources and from 1973 to 1989, he held various positions with Tenneco Oil Company, including Vice President-Production.

Mr. Mueller was appointed as President and Chief Operating Officer in June 2008 and is responsible for both our E&P business and our Midstream operations. 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 filed for bankruptcy. A graduate of the Colorado School of Mines, Mr. Mueller has over 30 years of experience in the oil and 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. Kerley was appointed to his present position in December 1999. 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. Boling was appointed to his present position in December 2002. He joined us as Senior Vice President, General Counsel and Secretary in January 2002. 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 promoted to President of Southwestern Midstream Services Company in December 2005. He joined the company in July 2005 as Vice President of Southwestern Midstream 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.

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.

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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 23, 2009, the closing price of our stock was $25.99 and we had 2,661 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	2008		2007		2006
March 31................	$ 34.07	$ 24.82	$ 20.64	$ 16.44	$ 21.71	$ 14.67
June 30...................	$ 48.69	$ 33.77	$ 25.09	$ 20.69	$ 19.99	$ 12.40
September 30.........	$ 48.53	$ 27.91	$ 22.85	$ 18.00	$ 18.74	$ 13.98
December 31..........	$ 37.22	$ 20.81	$ 28.27	$ 21.26	$ 21.30	$ 13.93

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

Issuer Purchases of Equity Securities

We did not repurchase any shares of our equity securities during 2008. The increase in common stock in treasury in 2008 is due to an increase in shares held on behalf of participants in a non-qualified defined contribution supplemented retirement savings plan. We refer you to Note 6 “Pension Plan and Other Postretirement Benefits” 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 2008.

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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 MidCap 400 Index, the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index (previously known as the Dow Jones Oil — Secondary Index). In June 2008, our common stock was removed from the S&P MidCap 400 Index and instead was added to the S&P 500 Index. Accordingly, that index has been added to the stock performance graph. The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2003, 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 MidCap 400 Index			S&P 500 Index


	12/31/03	12/31/04	12/31/05	12/31/06	12/31/07	12/31/08
Southwestern Energy Company	100	212	602	587	933	970
Dow Jones U.S. Exploration & Production	100	142	235	247	355	213
S&P MidCap 400 Index	100	116	131	145	156	100
S&P 500 Index	100	111	116	135	142	90

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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, 2008. 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.”


	2008	2007	2006	2005	2004
	(in thousands except share, per share, stockholder data and percentages)
Financial Review
Operating revenues
Exploration and production	$ 1,491,302	$ 795,944	$ 491,545	$ 403,234	$ 286,924
Midstream services	2,173,971	961,994	475,207	459,890	314,977
Gas distribution and other	118,399	174,914	172,655	179,375	158,698
Intersegment revenues	(1,472,120)	(677,721)	(376,295)	(366,170)	(283,462)
	2,311,552	1,255,131	763,112	676,329	477,137
Operating costs and expenses
Gas purchases – midstream services	710,129	306,336	128,387	124,730	60,804
Gas purchases – gas distribution	61,439	85,445	79,363	82,689	64,311
Operating and general	209,536	166,095	132,691	101,500	78,231
Depreciation, depletion and amortization	414,408	293,914	151,290	96,211	73,674
Taxes, other than income taxes	29,272	21,875	25,109	25,279	17,830
	1,424,784	873,665	516,840	430,409	294,850
Operating income	886,768	381,466	246,272	245,920	182,287

Interest expense, net	(28,904)	(23,873)	(679)	(15,040)	(16,992)
Other income (loss)	4,404	(219)	17,079	4,784	(362)
Gain on sale of utility assets	57,264	—	—	—	—
Minority interest in partnership	(587)	(345)	(637)	(1,473)	(1,579)
Income before income taxes	918,945	357,029	262,035	234,191	163,354
Income taxes
Current ⁽¹⁾	122,000	—	—	—	—
Deferred	228,999	135,855	99,399	86,431	59,778
	350,999	135,855	99,399	86,431	59,778
Net income	$ 567,946	$ 221,174	$ 162,636	$ 147,760	$ 103,576
Return on equity	22.6%	13.4%	11.3%	13.3%	23.1%
Net cash provided by operating activities	$1,160,809	$ 622,735	$ 429,937	$ 304,482	$ 237,897
Net cash used in investing activities	$ (792,078)	$ (1,513,497)	$ (630,006)	$ (452,918)	$ (285,448)
Net cash provided by (used in) financing activities	$ (174,286)	$ 849,667	$ 19,291	$ 370,906	$ 47,509

Common Stock Statistics ⁽²⁾
Earnings per share:
Basic	$ 1.66	$ 0.65	$ 0.49	$ 0.49	$ 0.36
Diluted	$ 1.64	$ 0.64	$ 0.47	$ 0.47	$ 0.35
Cash dividends declared and paid per share	$ —	$ —	$ —	$ —	$ —
Book value per average diluted share	$ 7.24	$ 4.74	$ 4.19	$ 3.55	$ 1.51
Market price at year-end	$ 28.97	$ 27.86	$ 17.52	$ 17.97	$ 6.34
Number of stockholders of record at year-end	2,497	2,275	2,412	2,126	2,022
Average diluted shares outstanding	346,245,938	347,442,660	342,575,500	312,618,078	295,702,176

(1) As a result of the gains from the E&P asset sales and the sale of the utility, we used all of our net operating loss carryforward in 2008 and were subject to current alternative minimum taxes of $122.0 million, of which $107.5 million was paid in 2008.

(2) 2007, 2006 and 2005 restated to reflect the two-for-one stock split effected in March 2008. 2004 restated to reflect two-for-one stock splits effected in June 2005, November 2005 and March 2008.

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	2008	2007	2006	2005	2004

Capitalization (in thousands)
Total debt	$ 735,400	$ 978,800	$ 137,800	$ 100,000	$ 325,000
Common stockholders’ equity	2,507,830	1,646,500	1,434,643	1,110,304	447,677
Total capitalization	$3,243,230	$ 2,625,300	$ 1,572,443	$ 1,210,304	$ 772,677
Total assets	$4,760,158	$ 3,622,716	$ 2,379,069	$ 1,868,524	$ 1,146,144
Capitalization ratios:
Debt	22.7%	37.3%	8.8%	8.3%	42.1%
Equity	77.3%	62.7%	91.2%	91.7%	57.9%

Capital Investments (in millions) ⁽¹⁾
Exploration and production
Exploration and development	$ 1,569.1	$ 1,375.2	$ 767.4	$ 416.2	$ 282.0
Drilling rigs and related equipment ⁽²⁾	26.7	4.5	93.6	35.1	—
	1,595.8	1,379.7	861.0	451.3	282.0
Midstream services	183.0	107.4	48.7	15.8	—
Gas distribution ⁽³⁾	3.6	11.4	11.2	10.9	7.3
Other	13.8	4.6	21.5	5.1	5.7
	$ 1,796.2	$ 1,503.1	$ 942.4	$ 483.1	$ 295.0

Exploration and Production
Natural gas:
Production, Bcf	192.3	109.9	68.1	56.8	50.4
Average price per Mcf, including hedges	$ 7.52	$ 6.80	$ 6.55	$ 6.51	$ 5.21
Average price per Mcf, excluding hedges	$ 7.73	$ 6.16	$ 6.37	$ 7.73	$ 5.80
Oil:
Production, MBbls	385	614	698	705	618
Average price per barrel, including hedges	$ 107.18	$ 69.12	$ 58.36	$ 42.62	$ 31.47
Average price per barrel, excluding hedges	$ 107.18	$ 69.12	$ 63.17	$ 54.37	$ 40.55
Total gas and oil production, Bcfe	194.6	113.6	72.3	61.0	54.1
Lease operating expenses per Mcfe	$ 0.89	$ 0.73	$ 0.66	$ 0.48	$ 0.38
General and administrative expenses per Mcfe	$ 0.41	$ 0.48	$ 0.58	$ 0.46	$ 0.36
Taxes, other than income taxes per Mcfe	$ 0.13	$ 0.16	$ 0.30	$ 0.37	$ 0.28
Proved reserves at year-end:
Natural gas, Bcf	2,175.5	1,396.9	978.9	772.3	594.5
Oil, MBbls	1,507	8,912	7,898	9,079	8,508
Total reserves, Bcfe	2,184.6	1,450.3	1,026.3	826.8	645.5

Midstream Services
Gas volumes marketed, Bcf	258.0	145.7	72.7	61.9	57.0
Gas volumes gathered, Bcf	224.1	78.7	14.6	2.3	—

Natural Gas Distribution ⁽³⁾
Sales and transportation volumes, Bcf	14.5	23.6	21.8	23.2	24.0
Off-system transportation, Bcf ⁽⁴⁾	—	0.3	0.1	—	1.0
Total volumes delivered	14.5	23.9	21.9	23.2	25.0
Customers at year-end
Residential	n/a	134,616	133,679	130,654	127,622
Commercial	n/a	17,180	17,151	16,996	16,815
Industrial	n/a	192	173	170	175
	n/a	151,988	151,003	147,820	144,612
Annual degree days	n/a	3,699	3,413	3,744	3,678
Percent of normal	n/a	91%	83%	91%	90%

(1) Capital investments include an increase of $36.2 million for 2008, a reduction of $20.6 million for 2007 and increases of $88.9 million, $28.1 million and $3.9 million for 2006, 2005 and 2004, respectively, related to the change in accrued expenditures between years.

(2) The 2006 and 2005 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.

(4) 2008 and 2005 off-system transportation volumes 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 “Selected Financial Data” and our consolidated financial statements and the related notes included in this Form 10-K.

OVERVIEW

Southwestern Energy Company is an independent energy company primarily focused on the exploration and production of natural gas within the United States. Our operations primarily are located in Arkansas, Oklahoma, Pennsylvania and Texas. We are also focused on creating and capturing additional value at and beyond the wellhead through our established natural gas gathering and marketing businesses, which we refer to collectively as our Midstream Services. We have historically operated principally in three segments: Exploration and Production (E&P), Midstream Services and Natural Gas Distribution. Effective July 1, 2008, we sold our utility subsidiary, Arkansas Western Gas Company (“AWG”) and, as a result, we no longer have any natural gas distribution operations. The assets and liabilities of AWG were classified as “held for sale” in our December 31, 2007 balance sheet, however, the results of operations for AWG are appropriately consolidated in the statements of operations and are not presented as “discontinued operations.” We refer you to Note 2 to the consolidated financial statements for additional information.

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 prepare economic analyses for each of the investment opportunities in our E&P business and rank them based upon the expected present value added for each dollar invested, which we refer to as PVI. The PVI of the future expected cash flows for each project is determined using a 10% discount rate. Our actual PVI results are utilized to help determine the allocation of our future capital investments.

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. Our ability to increase our natural gas production is dependent upon our ability to economically find and produce natural gas, our ability to control costs and our ability to market natural gas on economically attractive terms to our customers. In recent years, there has been significant price volatility in natural gas and crude oil prices due to a variety of factors we cannot control or predict. These factors, which include 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, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices. We are subject to credit risk relating to the risk of loss as a result of non-performance by counterparties in our hedging activities. The counterparties are primarily major investment and commercial banks which management believes minimizes 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. We have not incurred any counterparty losses in 2006, 2007 and 2008 related to non-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.

In 2008, our gas and oil production increased 71% to 194.6 Bcfe from 113.6 Bcfe in 2007. The 81.0 Bcfe increase in 2008 production was due to an 81.0 Bcf increase in net production from our Fayetteville Shale play. Increases in our East Texas and Arkoma net production were offset by decreases resulting from sales of oil and gas properties that occurred during 2008. In 2007, our production increased 57% to 113.6 Bcfe. The 41.2 Bcfe increase in 2007 production was due to a 41.7 Bcf increase in net production from our Fayetteville Shale play which was slightly offset by a net decrease in our other operating areas. We are targeting 2009 gas and oil production of 280.0 to 284.0 Bcfe, an increase of approximately 45% over our 2008 production. Our year-end reserves grew 51% in 2008 to 2,184.6 Bcfe, up from 1,450.3 Bcfe at the end of 2007. These increases were also primarily fueled by the continued development of our Fayetteville Shale play.

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We reported net income of $567.9 million in 2008, or $1.64 per share on a fully diluted basis, up 157% from the prior year. Net income in 2008 included a $35.4 million net of tax gain, or $0.10 per diluted share, related to the sale of our utility subsidiary that closed July 1, 2008. Excluding the $35.4 million gain on the sale of the utility, the increase in net income in 2008 was a result of increased revenues of $1.1 billion, partially offset by an increase in operating costs and expenses of $551.1 million and an increase in interest expense of $5.0 million. Net income in 2007 increased approximately 36% to $221.2 million, or $0.64 per share, compared to 2006. The increase in net income in 2007 was a result of increased revenues of $492.0 million, partially offset by an increase in operating costs and expenses of $356.8 million and an increase in interest expense of $23.2 million. Our cash flow from operating activities increased 86% to $1,160.8 million in 2008 and 45% to $622.7 million in 2007, due to increases in net income and adjustments for non-cash expenses.

Operating income for our E&P segment was $813.5 million in 2008, $358.1 million in 2007 and $237.3 million in 2006. Operating income for our E&P segment increased in 2008 due to an increase in revenues of $695.4 million from an 82.4 Bcf increase in gas production volumes and a $0.72 increase in product prices, partially offset by an increase in operating costs and expenses of $239.9 million. Operating income for our E&P segment increased in 2007 due to an increase in revenues of $304.4 million from higher gas production volumes and increased product prices, partially offset by an increase in operating costs and expenses of $183.6 million. Operating income for our Midstream Services segment was $62.3 million in 2008, compared to $13.2 million in 2007 and $4.1 million in 2006. Operating income for our Midstream Services segment increased in 2008 due to an increase of $77.2 million in gathering revenues and an increase of $6.4 million in the margin generated from our natural gas marketing activities, which were partially offset by a $34.5 million increase in operating costs and expenses, exclusive of purchased gas costs. Operating income for our Midstream Services segment increased in 2007 due to an increase of $29.7 million in gathering revenues and an increase of $0.9 million in the margin generated from our natural gas marketing activities, which were partially offset by a $21.6 million increase in operating costs and expenses, exclusive of purchased gas costs. Operating income for our Natural Gas Distribution segment was $10.7 million for the six months in 2008 prior to the utility sale, compared to $10.0 million in 2007 and $4.5 million in 2006. The increase in operating income for our Natural Gas Distribution segment in 2007 resulted from a rate increase implemented in August, from colder weather and a decrease in operating costs and expenses.

Our capital investments totaled approximately $1.8 billion in 2008, up 19% from $1.5 billion in the prior year. We invested $1.6 billion in our E&P segment in 2008, compared to $1.4 billion in 2007 and $861.0 million in 2006 (including $93.6 million invested in drilling rigs). Funds for our 2008 capital investments were provided by cash flow from operations and net proceeds of $964.0 million from our sales of E&P assets and our utility segment. As a result of our increased cash flow from operations and the proceeds received from asset sales, we were able to lower our total debt-to-capitalization ratio to 23% at December 31, 2008, down from 37% at December 31, 2007.

For 2009, our planned capital investments are $1.9 billion, compared to our 2008 capital investments of approximately $1.8 billion, and include approximately $1.6 billion for our E&P segment, $220 million for our Midstream Services segment and $40 million for other corporate purposes. The $1.6 billion of E&P investments includes approximately $1.3 billion for the development of our Fayetteville Shale play and approximately 80% of our 2009 E&P capital is allocated to drilling. In addition to the planned investments in the Fayetteville Shale play, our E&P investments in 2009 will also focus on our active drilling programs in East Texas and other conventional drilling in the Arkoma Basin. We expect our capital investments in 2009 to be funded from operating cash flow, cash on hand and borrowings under our revolving credit facility. The planned capital program for 2009 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.

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RESULTS OF OPERATIONS

Exploration and Production


	Year Ended December 31,
	2008	2007	2006

Revenues (in thousands)	$ 1,491,302	$ 795,944	$ 491,545
Operating income (in thousands)	$ 813,504	$ 358,079	$ 237,307

Gas production (Bcf)	192.3	109.9	68.1
Oil production (MBbls)	385	614	698
Total production (Bcfe)	194.6	113.6	72.3

Average gas price per Mcf, including hedges	$ 7.52	$ 6.80	$ 6.55
Average gas price per Mcf, excluding hedges	$ 7.73	$ 6.16	$ 6.37
Average oil price per Bbl, including hedges	$ 107.18	$ 69.12	$ 58.36
Average oil price per Bbl, excluding hedges	$ 107.18	$ 69.12	$ 63.17

Average unit costs per Mcfe:
Lease operating expenses	$ 0.89	$ 0.73	$ 0.66
General and administrative expenses	$ 0.41	$ 0.48	$ 0.58
Taxes, other than income taxes	$ 0.13	$ 0.16	$ 0.30
Full cost pool amortization	$ 1.99	$ 2.41	$ 1.90

Revenues, Operating Income and Production

Revenues. Revenues for our E&P segment were up $695.4 million, or 87%, in 2008, compared to the prior year. Approximately $544.3 million, or 78%, of the increase was attributable to an increase in production volumes and $152.4 million, or 22%, was attributable to higher gas and oil prices realized. E&P revenues were up $304.4 million, or 62%, in 2007, compared to 2006, of which approximately $268.7 million, or 88%, of the increase, was attributable to an increase in production volumes and $33.6 million, or 11%, was attributable to higher gas and oil prices realized. We expect our production volumes to continue to increase due to the development of our Fayetteville Shale play in Arkansas. We are unable to predict gas and oil prices which are subject to wide price fluctuations. As of February 23, 2009, we had hedged 135.0 Bcf of 2009 gas production and 50.0 Bcf of 2010 gas production to limit our exposure to price fluctuations. We refer you to Note 10 to the consolidated financial statements included in this Form 10-K and to “Commodity Prices” below for additional information. Revenues for 2008, 2007 and 2006 also include pre-tax gains of $4.8 million, $6.4 million and $4.0 million, respectively, related to the sale of gas-in-storage inventory.

Operating Income. Operating income from our E&P segment was $813.5 million in 2008, an increase of 127% from 2007, as the 87% increase in revenues was partially offset by a 55% increase in operating costs and expenses. In 2007, operating income increased 51% to $358.1 million from $237.3 million in 2006, as the 62% increase in revenues was partially offset by a 72% increase in operating costs and expenses.

Production. Gas and oil production was up approximately 71% to 194.6 Bcfe in 2008, as compared to the prior year, due to an 81.0 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 which were offset by decreases in net production resulting from the sale of all of our producing properties in the Permian and Gulf Coast. Gas and oil production in 2007 was up approximately 57% to 113.6 Bcfe, due to a 41.7 Bcf increase in net production from our Fayetteville Shale play and a 0.4 Bcfe decrease in our other operating areas. Our net production from the Fayetteville Shale play was 134.5 Bcf in 2008, up from 53.5 Bcf in 2007 and 11.8 Bcf in 2006. In the second quarter of 2008, we completed the sale of 55,631 net acres, or approximately 6% of our December 31, 2007 total net acres in the Fayetteville Shale play, and related facilities for $518.3 million. Production from the acreage sold was approximately 10.5 MMcf per day at the time of the sale. Additionally, we sold our Gulf Coast and Permian Basin properties in the second and third quarters of 2008. Production from these properties contributed approximately 3.1 Bcfe, 6.1 Bcfe and 8.4 Bcfe to total production in 2008, 2007 and 2006, respectively.

Gas sales to unaffiliated purchasers were up 79% to 188.0 Bcf in 2008 and up 66% to 105.1 Bcf in 2007, compared to the prior years. Sales to unaffiliated purchasers are primarily made under contracts that reflect current short-term prices and are subject to seasonal price swings. Intersegment sales to AWG for the six-month period prior to the sale of the utility were 4.3 Bcf compared to 4.8 Bcf for the full year of 2007. We expect to continue to sell natural gas to the utility through an annual competitive bidding process. Future increases in demand for our gas production are expected to

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come from sales to unaffiliated purchasers. We are unable to predict changes in the market demand and price for natural gas, including weather-related changes affecting demand for our production.

We are targeting 2009 gas and oil production of 280.0 to 284.0 Bcfe, an increase of approximately 45% over our 2008 production. Based on early production histories and modeling, and assuming continued positive exploration and development results, approximately 229.0 to 232.0 Bcf of our 2009 targeted gas production is projected to come from our activities in the Fayetteville Shale play. Although we expect production volumes in 2009 to increase, we cannot guarantee our success in discovering, developing, and producing reserves, including with respect to our Fayetteville Shale 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 to 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

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 and Note 10 to the consolidated financial statements for additional discussion). The average price realized for our gas production, including the effects of hedges, increased 11% to $7.52 per Mcf in 2008 and increased 4% to $6.80 per Mcf in 2007. The change in the average price realized reflects changes in average spot market prices and the effects of our price hedging activities. Our hedging activities decreased the average gas price $0.21 per Mcf in 2008, compared to increases of $0.64 per Mcf in 2007 and $0.18 per Mcf in 2006. In recent years, locational differences in market prices for natural gas have been wider than historically experienced. Disregarding the impact of hedges, historically the average price received for our gas production was approximately $0.30 to $0.50 per Mcf lower than average NYMEX spot market prices due to the locational market differentials. However, during 2008, 2007 and 2006, widening market differentials caused the difference in our average price received for our gas production to be approximately $0.70 to $1.30 per Mcf lower than spot market prices. The discount was at its widest point in late 2008 due to the impact that the delay in the completion of Boardwalk Pipeline had upon the Centerpoint East differential. Assuming a NYMEX commodity price for 2009 of $6.00 per Mcf of gas, the average price received for our gas production is expected to be approximately $0.75 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges. We hedged approximately 73% of our production in 2008 from the impact of widening basis differentials through our hedging activities and sales arrangements. Additionally, at December 31, 2008, we had basis protected on approximately 132.6 Bcf of our 2009 expected gas production through financial hedging activities and physical sales arrangements at a differential to NYMEX gas prices of approximately $0.30 per Mcf.

In addition to the basis hedges discussed above, at December 31, 2008, we had NYMEX commodity price hedges in place on 135.0 Bcf of our 2009 expected future gas production and 50.0 Bcf of our 2010 expected future gas production.

We realized an average price of $107.18 per barrel for our oil production for the year ended December 31, 2008, up approximately 55% from the prior year. The 2007 realized average price of $69.12 per barrel was up 18% from 2006. We did not hedge any of our 2008 or 2007 oil production. The average price we received for our oil production in 2006 was reduced by $4.81 per barrel due to the effects of our hedging activities. Assuming a NYMEX commodity price of $50.00 per barrel of oil for 2009, we expect the average price received for our oil production during 2009 to be approximately $1.50 per barrel lower than average spot market prices as market differentials reduce the average prices received.

Operating Costs and Expenses

Lease operating expenses per Mcfe for the E&P segment were $0.89 in 2008, compared to $0.73 in 2007 and $0.66 in 2006. Lease operating expenses per unit of production increased in 2008 and 2007 due primarily to higher per unit operating costs associated with our Fayetteville Shale operations, including the impact that higher natural gas prices had on the cost of compressor fuel in 2008. Our Fayetteville Shale production is growing rapidly and is expected to continue to provide upward pressure on our per unit operating costs. We expect our per unit operating cost for this segment to range between $0.87 and $0.92 per Mcfe in 2009.

General and administrative expenses for the E&P segment were $0.41 per Mcfe in 2008, down from $0.48 per Mcfe in 2007 and $0.58 per Mcfe in 2006. The decreases in general and administrative costs per Mcfe in 2008 and 2007 were due to the effects of our increased production volumes. In total, general and administrative expenses for the E&P

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segment were $80.2 million in 2008, $54.8 million in 2007 and $41.9 million in 2006. The increases in general and administrative expenses since 2006 were primarily due to increases in 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 $19.7 million, or 78%, of the 2008 increase and $9.4 million, or 73%, of the 2007 increase. We added 145 new E&P employees during 2008, compared to 176 employees added in 2007. In 2008 and 2007, increased expenses associated with leased aircraft and increases in information technology-related expenses accounted for most of the remaining increases in general and administrative expenses. We expect our cost per unit for general and administrative expenses in 2009 to range between $0.32 and $0.37 per Mcfe. The expected decrease in per unit costs in 2009 is due to anticipated increased production volumes from 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, stock-based compensation expensing under Statement on Financial Accounting Standards No. 123R “Share-Based Payment” (FAS 123R) 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. Additional discretionary awards may also be awarded under the incentive compensation plan. See “Critical Accounting Policies” below for further discussion of pension expense.

Our full cost pool amortization rate averaged $1.99 per Mcfe for 2008, $2.41 per Mcfe for 2007 and $1.90 per Mcfe for 2006. The decline in the average amortization rate for 2008 was primarily the result of the sales of oil and gas 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. Based on recent well performance in the Fayetteville Shale play, we expect the amount of reserves from future wells to continue to increase which would, if all other factors remained constant, decrease our full cost pool amortization rate going forward. Unevaluated costs excluded from amortization were $540.6 million at the end of 2008, compared to $372.4 million at the end of 2007 and $166.8 million at the end of 2006. The increases in unevaluated costs during these periods resulted primarily from the increased activity in our Fayetteville Shale play. See Note 7 to the consolidated financial statements for additional information regarding our unevaluated costs excluded from amortization.

Taxes other than income taxes per Mcfe were $0.13 in 2008, $0.16 in 2007 and $0.30 in 2006, and vary from year to year due to changes in severance and ad valorem taxes that result from the mix of our production volumes and fluctuations in commodity prices. Additionally, we accrued $5.0 million, or $0.03 per Mcfe, in 2008 for severance tax refunds related to our East Texas production, compared to $4.9 million, or $0.04 per Mcfe, in 2007. In April 2008, the State of Arkansas enacted legislation that will increase the severance tax on natural gas produced within the state to a base rate of 5%, effective January 1, 2009, subject to certain periods of reduced rates for high-cost gas wells, new discovery gas wells and gas wells that produce below a specified level. We have evaluated the impact of the increase in the severance taxes with respect to all of our production within the State of Arkansas, including our Fayetteville Shale operations, and expect that our wells will qualify for the reduced rate exceptions noted above. We do not expect it to materially affect our results of operations in 2009 or beyond.

The timing and amount of production and reserve additions attributed to our Fayetteville Shale play 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.

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 and amortized on an aggregate basis 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 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 prices in effect at the end of each accounting quarter, including the impact of derivatives qualifying as hedges, to calculate the ceiling value of their reserves. However, commodity price increases subsequent to the end of a reporting

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period but prior to the release of periodic reports may be utilized to calculate the ceiling value of reserves. At December 31, 2008, 2007 and 2006, our unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At December 31, 2008, the ceiling value of our reserves was calculated based upon quoted market prices of $5.71 per Mcf for Henry Hub gas and $41.00 per barrel for West Texas Intermediate oil, adjusted for market differentials. Cash flow hedges of gas production in place at December 31, 2008 increased the calculated ceiling value by approximately $338.7 million (net of tax). Excluding the benefit of the cash flow hedges at December 31, 2008, unamortized costs still did not exceed the ceiling value. At December 31, 2007, the ceiling value of our reserves was calculated based upon quoted market prices of $6.80 per Mcf for Henry Hub gas and $92.50 per barrel for West Texas Intermediate oil, and at December 31, 2006, the ceiling value of our reserves was calculated based upon quoted market prices of $5.64 per Mcf for Henry Hub gas and $57.25 per barrel for West Texas Intermediate oil. Decreases in market prices from December 31, 2008 levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs, and service costs could result in future ceiling test impairments.

Inflation impacts our E&P operations by generally increasing our operating costs and the costs of our capital additions. The effects of inflation on our operations prior to 2000 were minimal. However, since 2001, as commodity prices have generally increased, the impact of inflation has intensified in our E&P segment as shortages in drilling rigs, third-party services and qualified labor have risen due to increased activity levels in the natural gas and oil industry. We have endeavored to mitigate rising costs by obtaining vendor pricing commitments for multiple projects and by offering performance bonuses related to increased economic efficiencies. During 2007, our E&P operations began experiencing decreases in certain costs for third-party services primarily due to increased vendor competition in our Fayetteville Shale operating area. In late 2008, costs for third-party services further declined as competition increased due to decreased activity levels in the natural gas and oil industry as a result of the economic turmoil in the United States and abroad.

Midstream Services


	Year Ended December 31,
	2008	2007	2006
	(in millions, except volumes)

Revenues – marketing	$ 2,059.1	$ 924.3	$ 467.3
Revenues – gathering	$ 114.9	$ 37.7	$ 7.9
Gas purchases – marketing	$ 2,043.5	$ 915.1	$ 458.9
Operating costs and expenses	$ 68.2	$ 33.7	$ 12.2
Operating income	$ 62.3	$ 13.2	$ 4.1
Gas volumes marketed (Bcf)	258.0	145.7	72.7
Gas volumes gathered (Bcf)	224.1	78.7	14.6

Revenues and Operating Income

Revenues. Revenues from our Midstream Services segment were up 126% to $2.2 billion in 2008 and up 102% to $962.0 million in 2007, as compared to prior years. The increase in marketing revenues for 2008 resulted from a 112.3 Bcf increase in volumes marketed and a 26% increase in the price received for volumes marketed. Approximately 92% of the increase in gathering revenues for 2008 resulted from increases in volumes gathered related to the Fayetteville Shale play. The increase in marketing revenues for 2007 resulted from a 73.0 Bcf increase in volumes marketed largely resulting from increased production from the Fayetteville Shale play, partially offset by a 1% decrease in the price received for volumes marketed. Of the total volumes marketed, production from our E&P operated wells accounted for 96% in 2008, 89% in 2007 and 85% in 2006. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expenses. Gathering volumes, revenues and expenses for this segment are expected to continue to grow as reserves related to our Fayetteville Shale play are developed and production increases.

Operating Income. Operating income from our Midstream Services segment increased 371% to $62.3 million in 2008 and 222% to $13.2 million in 2007 as a result of the increases in gathering revenues from the Fayetteville Shale play and increases in the margin generated by gas marketing activities, partially offset by increased operating costs and expenses. The margin generated from natural gas marketing activities was $15.6 million for 2008, compared to $9.2 million for 2007 and $8.4 million for 2006. Margins may fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities. The increases in volumes marketed in 2008 and 2007, as compared to prior years, resulted 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. We refer you to “Quantitative and Qualitative Disclosures about Market Risk” and Note 10 to the consolidated financial statements for additional information. As noted above, gathering revenues and expenses are expected to continue to grow as a result of our Fayetteville Shale activities.

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Our Midstream Services segment has significant commitments for transportation services related to its marketing activities and compression for its gathering activities. See “Contractual Obligations and Contingent Liabilities and Commitments” below for further discussion.

Natural Gas Distribution


	Year Ended December 31,
	2008⁽¹⁾	2007	2006
	($ in thousands, except for per Mcf amounts)

Revenues	$ 117,710	$ 174,466	$ 172,207
Gas purchases	$ 79,120	$ 111,338	$ 112,922
Operating costs and expenses	$ 27,857	$ 53,168	$ 54,811
Operating income	$ 10,733	$ 9,960	$ 4,474

Sales and end-use transportation deliveries (Bcf)	14.5	23.6	21.8

Sales customers at year-end	n/a	151,988	151,003
Average sales rate per Mcf	$ 11.61	$ 11.07	$ 12.30

Annual heating weather – degree days	n/a	3,699	3,413
Percent of normal	n/a	91%	83%

⁽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 AWG 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 AWG 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 AWG, 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 AWG in 2008.

Transportation

In 2006, we sold our 25% partnership interest in NOARK Pipeline System, Limited Partnership (NOARK) to Atlas Pipeline Partners, L.P. for $69.0 million and recognized a pre-tax gain of approximately $10.9 million ($6.7 million after-tax) relating to the transaction. We recorded pre-tax income from operations related to our investment in NOARK of $0.9 million in 2006. Income from operations and the gain on the sale in the second quarter of 2006 were recorded in other income in our statements of operations.

Other Revenues

In 2008, 2007 and 2006, other revenues included pre-tax gains of $4.8 million, $6.4 million and $4.0 million, respectively, related to the sale of gas-in-storage inventory.

Interest Expense and Interest Income

Interest costs, net of capitalization, increased to $28.9 million in 2008 and to $23.9 million in 2007 due to our increased average levels of borrowings outstanding that resulted from our increased level of capital investments. Our debt level had decreased $243.4 million to $735.4 million by year end 2008 due to cash flow in excess of capital investments generated by the $964.0 million of proceeds received for our asset sales. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Financing Requirements” and Note 3 to the consolidated financial statements for further discussion of our debt. Interest capitalized increased to $34.5 million in 2008, up from $13.8 million in 2007 and $11.8 million in 2006, as our costs excluded from amortization in the E&P segment have continued to increase along with the overall increased level of our capital investments. Costs excluded from amortization in the E&P segment increased to $540.6 million at December 31, 2008, compared to $372.4 million at December 31, 2007. Total capital investments for our E&P segment were $1.6 billion in 2008, up from $1.4 billion in 2007.

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During 2008, 2007 and 2006, we earned interest income of $4.4 million, $0.1 million and $6.3 million, respectively, related to our cash investments. These amounts are recorded in other income on the Statements of Operations.

Income Taxes

Our provision for income taxes was an effective rate of 38.2% for 2008, compared to 38.1% in 2007 and 37.9% in 2006. Any changes in the provision for income taxes recorded each period result primarily from the level of income before income taxes, adjusted for permanent differences. As a result of the gains from the E&P asset sales and the sale of the utility, we used all of our net operating loss carryforward in 2008 and were subject to current taxes of $122.0 million, of which $107.5 million was paid in 2008. We also generated an alternative minimum tax credit in 2008 of $121.5 million which will be utilized to reduce future taxes. We do not expect to be subject to current taxes in 2009.

Pension Expense

We incurred pension costs of $6.5 million in 2008 for our pension and other postretirement benefit plans, compared to $5.3 million in 2007 and $4.0 million in 2006. As a result of the sale of AWG, we transferred pension and other postretirement plan assets and liabilities related to the employees of AWG to the purchaser. Although our net periodic benefit costs for our pension and other postretirement plans were approximately 30% lower in the second half of 2008 compared to the first half of 2008, our pension costs for the year were higher due to the deterioration of the markets in the second half of 2008.

The amount of pension expense recorded is determined by actuarial calculations and is also impacted by the funded status of our plans. During 2008, we contributed $9.8 million to our pension plans and $0.3 million to our other postretirement plans, compared to $6.5 million and $0.4 million, respectively, in 2007. The recent decline in the financial markets may require changes in management’s assumptions relative to expected return on plan assets which could, in turn, adversely impact the funded status of our pension plans and increase the amount of future contribution requirements. For further discussion of our pension plans, we refer you to Note 6 to the consolidated financial statements and “Critical Accounting Policies” below.

Stock-Based Compensation Expense

We recognized expense of $7.6 million and capitalized $3.9 million to gas and oil properties for stock-based compensation in 2008, compared to $5.4 million expensed and $2.6 million capitalized to gas and oil properties in 2007 and $5.2 million expensed and $1.7 million capitalized to gas and oil properties in 2006. We refer you to Note 12 to the consolidated financial statements for additional discussion of our equity based compensation plans. Additionally in 2008, we recorded expense of $0.3 million related to the valuation of company shares held in our non-qualified deferred compensation plan, compared to $0.9 million expensed and $0.6 million capitalized to gas and oil properties in 2007.

Adoption of Accounting Principles

During the first quarter of 2008, we adopted Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This statement applies to other accounting pronouncements that require or permit fair value measurements, and is effective for financial statements issued for fiscal years beginning after November 15, 2007. In addition to required disclosures, FAS 157 also requires companies to evaluate current measurement techniques. The adoption of FAS 157 had no material impact on our results of operations and financial condition.

During the first quarter of 2008, we adopted Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (FAS 159). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value and applies to other accounting pronouncements that require or permit fair value measurements. FAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of FAS 159 had no impact on our results of operations and financial condition.

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In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51” (FAS 160). FAS 160 will change the financial accounting and reporting of noncontrolling (or minority) interests in consolidated financial statements, and is effective for financial statements issued for fiscal years beginning after December 15, 2008. FAS 160 will impact the presentation of our balance sheet line item “Minority Interest” related to our Overton partnership, a partnership formed by SEPCO with an investor to drill and complete 14 wells in the Overton Field in East Texas, but is expected to have no material impact on our results of operations and financial condition.

In February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”). FSP FAS 157-2 delays the effective date of FAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). FSP FAS 157-2 is effective for our fiscal year beginning January 1, 2009. The adoption of FSP FAS 157-2 is not expected to have a material impact on our results of operations and financial condition.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (FAS 161). FAS 161 requires enhanced disclosures for derivative instruments and hedging activities that include explanations of how and why an entity uses derivatives, how instruments and the related hedged items are accounted for under FAS 133 and related interpretations, and how derivative instruments and related hedged items affect the entity’s financial position, results of operations and cash flows. FAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of FAS 161 is not expected to have a material impact on our results of operations and financial condition.

In October 2008, the FASB issued FASB Staff Position FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (FSP FAS 157-3). FSP FAS 157-3 clarifies the application of FAS 157, “Fair Value Measurements,” when a market for that financial asset is inactive. FSP FAS 157-3 became effective for financial statements upon issuance and its adoption did not have a material impact on our results of operations and financial condition.

Late in 2008, the SEC adopted major revisions to its required oil and gas reporting disclosures which become effective as of January 1, 2010. Among other things, the amendments provide for the use of the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period for purposes of both the disclosure and full-cost accounting rules. With respect to accounting pronouncements that currently make reference to a single-day pricing regime with respect to oil and gas reserves, the SEC indicated that it was communicating with the FASB staff to align the standards used in the FASB’s pronouncements with the new 12-month average price and that it will consider whether to delay the compliance date based on its discussions with the FASB. The SEC expressed the view that the change from using single-day year-end price to an average price should be treated as a change in accounting principle, or a change in the method of applying an accounting principle, that is inseparable from a change in accounting estimate and that the change would be considered a change in accounting estimate pursuant to Statement of Financial Accounting Standard No. 154 “Accounting Changes and Error Corrections” (SFAS 154) and accounted for prospectively. The SEC further expressed that the view that any accounting change resulting from the changes in definitions and required pricing assumptions in Rule 4-10 of Regulation S-X should be treated as a change in accounting principle that is inseparable from a change in accounting estimate, not requiring retroactive revision but requiring recognition in the independent auditor’s report through the addition of an explanatory paragraph. We will not be able to determine the impact of these amendments on our results of operation or financial condition until the FASB issues its pronouncements.

LIQUIDITY AND CAPITAL RESOURCES

We depend primarily on internally-generated funds, our unsecured revolving credit facility, funds accessed through debt and equity markets and periodic asset sales as our primary sources of liquidity. We may borrow up to $1.0 billion under our revolving credit facility from time to time. The amount available under our revolving credit facility may be increased up to $1.25 billion at any time upon our agreement with our existing or additional lenders. As of December 31, 2008, we had no indebtedness outstanding under our revolving credit facility and at December 31, 2007, we had $842.2 million outstanding under the facility. During 2009, we expect to draw on a portion of the funds available under the facility to fund our planned capital investments (discussed below under “Capital Investments”), which are expected to exceed the net cash generated by our operations and the remaining net proceeds from our asset sales in 2008.

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On January 16, 2008, we completed a private placement of $600 million of 7.5% Senior Notes due 2018 (discussed below under “Financing Requirements”). Net proceeds of approximately $591 million from the offering were used to pay outstanding indebtedness under our revolving credit facility.

In the second quarter of 2008, we completed the sale of 55,631 net acres, or approximately 6% of our total net acres in the Fayetteville Shale play, for approximately $518.3 million. Additionally in 2008, we sold various oil and gas properties in the Gulf Coast and the Permian Basin for approximately $240.0 million in the aggregate. Effective July 1, 2008, we closed the previously announced sale of our utility, AWG, to SourceGas, LLC. We received $223.5 million (net of expenses related to the sale) and, in order to receive regulatory approval for the sale and certain related transactions, paid $9.8 million to AWG for the benefit of its customers. We recorded a pre-tax gain on the sale of AWG of $57.3 million in the third quarter of 2008. In total, we received $964.0 million in proceeds from asset sales during 2008 which were utilized to pay down borrowings under our revolving credit facility and fund a portion of our 2008 capital investment program. The remaining proceeds were invested in cash equivalents and will be used to help fund our 2009 capital investments program.

Net cash provided by operating activities increased 86% to $1.2 billion in 2008, due to a $516.3 million increase in net income and adjustments for non-cash expenses. Net cash provided by operating activities increased 45% to $622.7 million in 2007, due to a $237.7 million increase in net income and adjustments for non-cash expenses. For 2008, requirements for our capital investments were funded from our revolving credit facility, cash generated by operating activities and the net proceeds from our asset sales. Net cash from operating activities provided 65% of our cash requirements for capital investments in 2008, 41% in 2007 and 46% in 2006.

At December 31, 2008, our capital structure consisted of 23% debt and 77% equity, and we had $196.3 million in cash and cash equivalents. We believe that our operating cash flow, the remaining proceeds from our asset sales and available funds under our revolving credit facility will be adequate to meet our capital and operating requirements for 2009. The credit status of the financial institutions participating in our revolving credit facility could adversely impact our ability to borrow funds under the 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 under the facility. Current economic conditions make it difficult to access debt and equity markets for funding. Given the unused capacity on our revolving credit facility and our expectations of cash flow from our future operations, we do not plan on accessing those markets in the near term.

Our cash flow from operating activities is highly dependent upon the market prices that we receive for our 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 10 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-collectible 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 increased 19% to approximately $1.8 billion in 2008 and increased 59% in 2007 to approximately $1.5 billion. Capital investments include an increase of $36.2 million in 2008, a reduction of $20.6 million in 2007 and an increase of $88.9 million for 2006 related to the change in accrued expenditures between years. Our E&P segment investments in 2008 were $1.6 billion, up from $1.4 billion in 2007 and $861.0 million in 2006. Capital investments for 2006 included $93.6 million for drilling rigs and related equipment which were subsequently sold and leased back in December 2006.


	2008		2007	2006
	(in thousands)
Exploration and production
Exploration and development	$ 1,569,089		$ 1,375,204	$ 767,400
Drilling rigs and related equipment	26,739		4,453	93,641
	1,595,828		1,379,657	861,041
Midstream services	183,021		107,363	48,660
Natural gas distribution	3,574	⁽¹⁾	11,375	11,232
Other	13,745		4,743	21,474
	$ 1,796,168		$ 1,503,138	$ 942,407

⁽¹⁾

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

Our capital investments for 2009 are planned to be $1.9 billion, consisting of $1.6 billion for E&P, $220 million for Midstream Services and $40 million for other corporate purposes. We expect to allocate approximately $1.3 billion of our 2009 E&P capital to our Fayetteville Shale play, up from approximately $1.2 billion in 2008. Our planned level of capital investments in 2009 is expected to allow us to accelerate our drilling activity in the Fayetteville Shale, continue the development of our properties in East Texas, continue our conventional drilling in the Arkoma Basin, maintain our present markets, explore and develop other existing gas and oil properties and generate new drilling prospects. As discussed above, our 2009 capital investment program is expected to be funded through cash flow from operations, borrowings under our credit facility and the remaining net proceeds from our 2008 asset sales. The planned capital program for 2009 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.

Financing Requirements

Our total debt outstanding was $735.4 million at December 31, 2008, including $61.2 million classified as short-term debt on our balance sheet, compared to $978.8 million at December 31, 2007. Our 7.625% Senior Notes due 2027 are putable by the note holders on May 1, 2009, and as a result, the $60 million principal balance of these notes has been reclassified to short-term debt in our balance sheet. If the put option is exercised in 2009, we would use cash available to pay the notes, or alternatively, we would borrow the required funds under our revolving credit facility. Our unsecured revolving credit facility has a borrowing capacity of $1.0 billion, which may be increased to $1.25 billion at any time upon our agreement with our existing or additional lenders. As of December 31, 2008, we had no indebtedness outstanding under our revolving credit facility compared to $842.2 million outstanding as of December 31, 2007. As discussed more fully below, in January 2008, we issued $600 million of 7.5% Senior Notes due 2018, the net proceeds of which were used to repay amounts outstanding under our revolving credit facility. The interest rate on the credit facility is calculated based upon our public debt rating and is currently 87.5 basis points over LIBOR. The revolving credit facility is currently guaranteed by our subsidiaries, SEECO, Inc. (SEECO), Southwestern Energy Production Company (SEPCO) and Southwestern Energy Services Company (SES) and requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied. Our publicly traded notes are rated BB+ by Standard and Poor’s and we have a Corporate Family Rating of Ba2 by Moody’s. Any downgrades in our public debt ratings could increase our cost of funds under the credit facility.

Our revolving credit facility contains covenants which impose certain restrictions on us. Under the credit agreement, we may not issue total debt in excess of 60% of our total capital, must maintain a certain level of stockholders’ equity and must maintain a ratio of EBITDA to interest expense of 3.5 or above. Additionally, there are certain limitations on the amount of indebtedness that may be incurred by our subsidiaries. We were in compliance with all of the covenants of our credit agreement at December 31, 2008. 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.

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On January 16, 2008, we issued $600 million of 7.5% Senior Notes due 2018 in a private placement, which are rated BB+ by Standard and Poor’s and Ba2 by Moody’s. If we undergo a “change of control,” as defined in the indenture, holders of the 7.5% Senior Notes will have the option to require us to purchase all or any portion of the notes at a purchase price equal to 101% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the change of control date. Payment obligations with respect to the 7.5% Senior Notes are currently guaranteed by SEECO, SEPCO and SES, which guarantees may be unconditionally released in certain circumstances. As a result of the issuance of the guarantees of the 7.5% Senior Notes, and in order for all of our senior notes to rank equally, on May 2, 2008, we and our subsidiaries, SEECO, SEPCO and SES, entered into supplemental indenture agreements with the trustees under the indentures relating to our 7.625% Medium-Term Notes due 2027, 7.125% Fixed Rate Notes due October 10, 2017, 7.35% Fixed Rate Notes due October 2, 2017 and 7.15% Notes due 2018, pursuant to which SEECO, SEPCO and SES became guarantors of such notes to the same extent to which such subsidiaries have guaranteed our 7.5% Senior Notes. We refer you to Note 4, "Condensed Consolidating Financial Information" in this Form 10-K for additional information. The indentures governing our senior notes contain covenants that, among other things, restrict our ability and/or our subsidiaries’ ability to incur liens, to engage in sale and leaseback transactions and to merge, consolidate or sell assets.

At December 31, 2008, our capital structure consisted of 23% debt and 77% equity, and we had available $196.3 million in cash and cash equivalents. Our debt as a percentage of total capital declined throughout 2008, primarily due to our operating results and the use of a portion of the proceeds received from our asset sales to reduce debt. Stockholders’ equity at December 31, 2008, includes a net gain of $258.9 million in accumulated other comprehensive income related to our hedging activities that is required to be recorded under the provisions of Statement on Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (FAS 133), and a loss of $10.9 million related to changes in our pension and other postretirement liabilities recorded under the provisions of Statement on Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (FAS 158). The amount recorded for FAS 133 is based on current fair values of our hedges at December 31, 2008, 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 credit facility’s financial covenants with respect to capitalization percentages exclude the effects of non-cash entries that result from FAS 133 and FAS 158 and the non-cash impact of any full cost ceiling write-downs. Our capital structure at December 31, 2008 would have been 25% debt and 75% equity without consideration of accumulated other comprehensive income in stockholders’ equity related to our commodity hedge position and our pension and other postretirement liabilities.

As part of our strategy to ensure a certain level of cash flow to fund our operations, we have hedged 135.0 Bcf of our expected 2009 gas production and 50.0 Bcf of our expected 2010 gas production. The amount of long-term debt we incur will be dependent upon commodity prices and our capital investment plans. If commodity prices significantly decrease, we may decrease and/or reallocate our planned capital investments.

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 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.

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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, 2008, 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⁾	$ 892,429	$ 72,878	$ 192,557	$ 168,338	$ 458,656
Debt⁽²⁾	735,400	61,200	2,400	2,400	669,400
Interest on senior notes⁽³⁾	455,908	51,931	100,530	100,187	203,260
Rig leases⁽⁴⁾	116,261	19,377	38,754	38,754	19,376
Purchase obligations⁽⁵⁾	101,443	101,443	—	—	—
Compression services⁽⁶⁾	92,075	26,413	46,272	19,390	—
Operating leases⁽⁷⁾	71,642	15,398	24,286	17,356	14,602
Operating agreements⁽⁸⁾	41,968	38,716	3,252	—	—
Other obligations⁽⁹⁾	31,817	27,037	4,780	—	—
	$2,538,943	$ 414,393	$ 412,831	$ 346,425	$ 1,365,294

⁽¹⁾Our Midstream Services segment has commitments for demand transportation charges of approximately $888.1 million related to the Fayetteville Shale play and approximately $3.0 million related to East Texas. Our E&P segment has commitments for approximately $1.3 million of demand transportation charges.

⁽²⁾Debt includes $60.0 million of our 7.625% Senior Notes that are putable at the holders’ option in May 2009 and $35.4 million of our 7.15% Notes due 2018 which requires semi-annual principal payments of $0.6 million.

⁽³⁾ Interest on the senior notes includes interest through May 2009 on the $60 million notes that are due in 2027 and putable at the holders’ option.

⁽⁴⁾ We have commitments related to the leasing of 14 drilling rigs and related equipment through 2014.

⁽⁵⁾Purchase obligations consist of outstanding purchase orders under existing agreements. Our Midstream Services segment has outstanding purchase obligations of $81.5 million relating to compression units, $61.7 million of which have been assigned to financial institutions in connection with anticipated lease arrangements. At December 31, 2008, the financial institutions had advanced approximately $20.7 million for payments of these purchase obligations and we pay interest on the advanced amounts.

⁽⁶⁾Our Midstream Services segment has commitments of approximately $84.6 million and our E&P segment has commitments of approximately $7.4 million for compression services associated primarily with our Fayetteville Shale play and our Overton operations.

⁽⁷⁾Operating leases include costs for compressors, aircraft, office space and equipment under non-cancelable operating leases expiring through 2018.

⁽⁸⁾Our E&P segment has commitments for up to $36.3 million in termination fees related to rig operator agreements. Additionally, our E&P segment has secured rig moving services by committing monthly take-or-pay amounts of $469,000, expiring in December 2009.

⁽⁹⁾Our other significant contractual obligations include approximately $16.0 million related to seismic services, approximately $6.1 million for funding of benefit plans and approximately $2.8 million for various information technology support and data subscription agreements. Additionally, our E&P segment has committed up to $3.0 million in termination fees to a gravel company.

We refer you to Note 3 to the consolidated financial statements for a discussion of the terms of our debt.

Contingent Liabilities and Commitments

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. Based on actuarial data and taking into account the transfer of pension assets and obligations related to the sale of AWG, we recorded expenses of approximately $6.5 million in 2008 for these plans. At December 31, 2008, we recognized a liability of $15.4 million as a result of the underfunded status of our pension and other postretirement benefit plans, compared to a liability of $14.6 million at December 31, 2007. As a result of actuarial data, we expect to record expenses of $7.1 million for these plans in 2009. For further information regarding our pension and other postretirement benefit plans, we refer you to Note 6 to the consolidated financial statements and “Critical Accounting Policies” below for additional information.

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each of the laterals were fully exercised in 2008 and 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. SES’ obligations under these agreements are reflected in the “Contractual Obligations” table above. In addition, we have guaranteed a portion of SES’ obligations under the firm transportation agreements with Texas Gas. Our payment obligations under the guaranty are limited to the lesser of (i) 25% of SES’ negotiated demand charges for the full term of the agreement(s), less any payments made by us pursuant to the guaranty, or (ii) 25% of SES’ negotiated demand charges for the remaining initial terms of the agreement(s) as of the first day of the month of services under the agreements for which payment is claimed, which amount shall reflect any reductions in SES’ obligations under the agreements.

In September 2008, SES entered into a precedent agreement pursuant to which it will contract for firm gas transportation services on a proposed new pipeline of Fayetteville Express Pipeline LLC (FEP), which is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P. SES will be a “foundation shipper” for the project and will use the new pipeline primarily to deliver gas volumes produced from our operations in the Fayetteville Shale play in central Arkansas to eastern markets. Pending regulatory approvals, the pipeline is expected to have an estimated ultimate capacity of up to 2.0 Bcf per day and to be in-service by late 2010 or early 2011. Following the approval of the pipeline by the Federal Energy Regulatory Commission (FERC) and subject to certain conditions, pursuant to the precedent agreement, SES will enter into a firm transportation agreement to transport up to 1,200,000 Dekatherms per day for an initial term of ten years. In connection with the precedent agreement, we delivered to FEP a guaranty of SES’ obligations under the precedent agreement and the firm transportation agreements to be entered into thereunder. Initially, and during any period in which SES meets the creditworthiness requirements of the precedent agreement, our payment obligations under the guaranty are zero but will increase upon the occurrence of certain events.

In the fourth quarter of 2008, one of our gathering subsidiaries, DeSoto Gathering Company, L.L.C. (DGC), entered into agreements with financial institutions in contemplation of leasing up to 50 compression units pursuant to which those institutions were assigned $61.7 million of our purchase obligations for the units and provided advances for payment of those obligations. At December 31, 2008, the financial institutions had advanced $20.7 million with respect to the purchase obligations and we will pay interest on the advanced amounts until the leases commence. The commencement of the leases is contingent upon certain criteria including, but not limited to, the delivery of the compressors. If the leases do not commence, we must repay all advances and the purchase obligations for the compression units revert back to us. Purchase obligations and interim interest obligations relating to compression units are reflected in the “Contractual Obligations” table above. We expect to begin receiving the units in the first quarter of 2009, with all of the units expected to be delivered by the end of 2009. Aggregate rental payments, including interim interest, are expected to total approximately $60.1 million over the terms of the leases, which will vary between seven and eight years. In addition, we have guaranteed DGC’s obligations under the advances and the anticipated leases subject to an aggregate cap of $100 million.

We are subject to litigation and claims (including with respect to environmental matters) that arise in the ordinary course of business. Management believes, individually or in aggregate, such litigation and claims 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, at which time management may reserve amounts that are reasonably estimable.

Working Capital

We maintain access to funds that may be needed to meet capital requirements through our revolving credit facility described above. We had positive working capital of $96.4 million at December 31, 2008, and negative working capital of $67.6 million at December 31, 2007. Current assets increased $525.9 million at December 31, 2008, compared to current assets at December 31, 2007, due to a $278.8 million increase in our current hedging asset, a $195.6 million increase in cash and cash equivalents from proceeds remaining from the sale of our utility segment and certain oil and gas assets, and a $76.9 million increase in accounts receivable, which were partially offset by a decrease of $58.9 million in current assets held for sale related to our utility segment. Current liabilities increased $362.0 million as a result of an increase of $151.1 million in accounts payable, an increase of $101.5 million in our current deferred income taxes related to our hedging activities, a $60.0 million increase due to the reclassification of our 7.625% Senior Notes to short-term, a $38.6 million increase in advances from partners, a $26.9 million increase in current taxes payable and an increase of $18.6 million in interest payable.

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CRITICAL ACCOUNTING POLICIES

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 and amortized on an aggregate basis 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 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 prices in effect at the end of each accounting quarter, including the impact of derivatives qualifying as hedges, to calculate the ceiling value of their reserves. However, commodity price increases subsequent to the end of a reporting period but prior to the release of periodic reports may be utilized to calculate the ceiling value of reserves. At December 31, 2008, 2007 and 2006, our unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At December 31, 2008, the ceiling value of our reserves was calculated based upon quoted market prices of $5.71 per Mcf for Henry Hub gas and $41.00 per barrel for West Texas Intermediate oil, adjusted for market differentials. Cash flow hedges of gas production in place at December 31, 2008, increased the calculated ceiling value by approximately $338.7 million (net of tax). Excluding the benefit of the cash flow hedges at December 31, 2008, unamortized costs still did not exceed the ceiling value. We had approximately 185.0 Bcf of future gas production hedged at December 31, 2008. At December 31, 2007, the ceiling value of our reserves was calculated based upon quoted market prices of $6.80 per Mcf for Henry Hub gas and $92.50 per barrel for West Texas Intermediate oil, and at December 31, 2006, the ceiling value of our reserves was calculated based upon quoted market prices of $5.64 per Mcf for Henry Hub gas and $57.25 per barrel for West Texas Intermediate oil. Decreases in market prices from December 31, 2008 levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs, and service costs could result in future ceiling test impairments.

The risk that we will be required to write-down the carrying value of our natural gas and oil properties increases when natural gas and oil prices are depressed or if there are substantial downward revisions in estimated proved reserves. Under the SEC’s current full cost accounting rules, our reserves are required to be priced using prices in effect at the end of the reporting period. Application of these rules during periods of relatively low natural gas or oil prices due to seasonality or other reasons, even if temporary, increases the probability of a ceiling test write-down. Natural gas pricing has historically been unpredictable and any declines could result in a ceiling test write-down in subsequent quarterly or annual reporting periods. Under new rules recently issued by the SEC that will be effective January 1, 2010, reserves will be priced using the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period.

Natural gas and oil reserves used in the full cost method of accounting cannot be measured exactly. Our estimate of natural gas and oil reserves requires extensive judgments of reservoir engineering data 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. These estimates are reviewed by senior engineers who are not part of the asset management teams and our President and Chief Operating Officer. Final authority over the estimates of our proved reserves rests with our Board of Directors. In each of the past three years, performance revisions to our proved reserve estimates represented no greater than 8% 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 account for 62% of our total reserve base at December 31, 2008. 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.

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We engage the services of Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, or NSA, to audit our reserves as estimated by our reservoir engineers. NSA reports the results of the reserves audit to our Board of Directors. In conducting its audit, the engineers and geologists of NSA study our major properties in detail and independently develop reserve estimates. NSA’s audit consists primarily of substantive testing, which includes a detailed review of major properties that account for approximately 83% of present worth of the company's total proved reserves. NSA’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 83% present value as of December 31, 2008, accounted for approximately 83% of our total proved reserves and approximately 92% of our proved undeveloped reserves. In the conduct of its audit, NSA did not independently verify the data we provided to them 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. NSA 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, NSA 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, 2008, NSA 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 generally accepted petroleum engineering and evaluation principles.

A decline in 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 gas prices on cash flows and reported reserve quantities. Reported discounted cash flows and reserve quantities at December 31, 2008, were $2,109.3 million and 2,184.6 Bcfe, respectively. An assumed decrease of $1.00 per Mcf in the December 31, 2008 gas price used to price our reserves would have resulted in an approximate $503.1 million decline in our future net cash flows discounted at 10%, adjusted for the effects of commodity hedges, and an approximate decrease of 23 Bcfe of our reported reserves. The decline in reserve quantities, assuming this decrease in 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 and capitalized 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. In recent years, we have hedged 60% to 80% of our annual production. 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 gas or oil transaction that is hedged.

Our derivative instruments are accounted for under FAS 133, as amended, and are recorded at fair value in our financial statements. 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 or in gas purchases. 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, 2008, we recorded an unrealized gain of $2.5 million related to basis differential swaps that did not qualify for hedge accounting in addition to a $7.0 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 did not enter into any interest rate swaps in 2008, 2007 or 2006. 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 6 to the consolidated financial statements for further discussion and disclosures regarding these benefit plans). Two of

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the assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be effectively settled, and the expected return on plan assets, which reflects the average rate of earnings expected on the funds invested. For the December 31, 2008, benefit obligation and the periodic benefit cost to be recorded in 2009, the discount rate assumed is 6.0%. For the 2009 periodic benefit cost, the expected return assumed is 7.50%. This compares to a discount rate of 6.0% and an expected return of 7.75% used in 2008.

Using the assumed rates discussed above, we recorded pension expense of $6.5 million in 2008, $5.3 million in 2007 and $4.0 million in 2006 related to our pension and other postretirement benefit plans. As a result of the sale of AWG on July 1, 2008, we transferred pension and other postretirement assets and liabilities related to the employees of AWG to the purchaser. At December 31, 2008 we recognized a liability of $15.4 million, compared to $14.6 million at December 31, 2007, related to our pension and other postretirement benefit plans. During 2008, we also funded $10.1 million to our pension and other postretirement benefit plans. In 2009, we expect to fund $6.1 million to our pension and other postretirement benefit plans and recognize pension expense of $6.2 million and a postretirement benefit expense of $0.9 million. Assuming a 1% change in the 2008 rates (lower discount rate and lower rate of return), we would have recorded pension and other postretirement benefit expense of $7.9 million in 2008.

Gas in Underground Storage

We currently have one facility owned by our E&P segment that contains gas in underground storage. Gas in storage that is expected to be cycled within the next 12 months is recorded in current assets. This current portion of gas in storage is classified as inventory and is carried at the lower of cost or market. At December 31, 2008 and 2007, the current portion of gas in storage was $24.1 million and $25.0 million, respectively. The non-current portion of gas in storage is classified in property, plant 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 gas in inventory for the E&P segment is used primarily to supplement production in meeting the segment's contractual commitments, including delivery to customers of AWG, especially during periods of colder weather. As a result, demand fees paid by AWG to our E&P subsidiaries are a part of the realized price of the gas in storage. In determining the lower of cost or market for storage gas, we utilize the gas futures market in assessing the price we expect to be able to realize for our gas in inventory. A significant decline in the future market price of natural gas could result in a write-down of our gas in storage carrying cost.

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

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act 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 transport our production to the most favorable markets or at all;

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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;

our ability to fund our planned capital investments;

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

the impact of federal, state and local government regulation, including any increase in severance taxes;

the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services, including pressure pumping equipment and crews in the Arkoma basin;

our future property acquisition or divestiture activities;

the effects of weather;

increased competition;

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 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, 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, 2008, approximately 38% of our estimated proved reserves were proved undeveloped and 3% 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.

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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 prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the 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.

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 6% of accounts receivable at December 31, 2008. 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. At December 31, 2008, we had $735.4 million of total debt with a weighted average interest rate of 7.48% and we had no indebtedness outstanding under our revolving credit facility. Interest rate swaps may be used to adjust interest rate exposures when deemed appropriate. We do not have any interest rate swaps in effect currently. Our 7.625% Senior Notes due 2027 are putable by the note holders on May 1, 2009, and as a result, the $60 million principal balance of these notes is included in the 2009 expected maturity below.


								Fair
	Expected Maturity Date							Value
	2009	2010	2011	2012	2013	Thereafter	Total	12/31/08
	($ in millions)

Fixed Rate	$ 61.2	$ 1.2	$ 1.2	$ 1.2	$ 1.2	$ 669.4	$ 735.4	$ 648.6
Average Interest Rate	7.62%	7.15%	7.15%	7.15%	7.15%	7.47%	7.48%	—

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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 generally offset by the gain or loss recognized upon the related gas or oil transaction 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 investment and commercial banks 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 did not incur any losses in 2008 related to non-performance of these counterparties 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 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, 2008, the fair value of our financial instruments related to natural gas production and gas-in-storage was a $415.3 million asset and a $5.6 million asset, respectively.


		Weighted	Weighted	Weighted	Weighted
		Average	Average	Average	Average	Fair value at
		Price to be	Floor	Ceiling	Basis	December 31,
		Swapped	Price	Price	Differential	2008
	Volume	($/MMBtu)	($/MMBtu)	($/MMBtu)	($/MMBtu)	($ in millions)
Natural Gas (Bcf):

Fixed Price Swaps:
2009⁽¹⁾	77.3	8.33	—	—	—	172.3
2010	36.0	9.04	—	—	—	65.8

Costless Collars:
2009	59.0	—	8.71	11.69	—	160.0
2010	14.0	—	8.29	10.57	—	21.1

Basis Swaps:
2009	50.0	—	—	—	(0.51)	0.1
2010	32.0	—	—	—	(0.30)	1.4
2011	7.2	—	—	—	(0.28)	0.2

(1)

Includes fixed-price swaps for 1.3 Bcf relating to future sales from our underground storage facility that have a fair value asset of $5.6 million.

At December 31, 2008, we had outstanding fixed-price basis differential swaps on 50.0 Bcf of 2009, 32.0 Bcf of 2010 and 7.2 Bcf of 2011 gas production that did not qualify for hedge accounting treatment. Changes in the fair value of derivatives that do not qualify as cash flow hedges are recorded in gas and oil sales. For the year ended December 31, 2008, we recorded an unrealized gain of $2.5 million related to the differential swaps that did not qualify for hedge accounting treatment and a loss of $7.0 million gain 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.

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At December 31, 2007, we had outstanding natural gas price swaps on total notional volumes of 55.7 Bcf in 2008 and 56.0 Bcf in 2009 for which we will receive fixed prices ranging from $7.29 to $9.98 per MMBtu. At December 31, 2007, we had outstanding fixed price basis differential swaps on 8.0 Bcf of 2008 gas production that qualified for hedge treatment and outstanding fixed price basis differential swaps on 66.8 Bcf of 2008 and 2009 gas production that did not qualify for hedge treatment.

At December 31, 2007, we had collars in place on notional volumes of 48.0 Bcf in 2008 and 23.0 Bcf in 2009. The 48.0 Bcf in 2008 had an average floor and ceiling price of $7.92 and $11.60 per MMBtu, respectively. The 23.0 Bcf in 2009 had an average floor and ceiling price of $8.09 and $10.91 per MMBtu, respectively.

Subsequent to December 31, 2008 and prior to February 23, 2009, we have basis protected an additional 9.8 Bcf of 2009, 7.3 Bcf of 2010, and 1.8 Bcf of 2011 gas production with an average differential price of $0.48 below NYMEX spot rates for our respective basis locations.

Midstream Services

At December 31, 2008, our Midstream Services segment had outstanding fair value hedges in place on 0.7 Bcf and 0.2 Bcf of gas for 2009 and 2010, respectively. 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 2009 through December 2010 and have a net fair value asset of $0.5 million as of December 31, 2008.

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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	58
Report of Independent Registered Public Accounting Firm	58
Statements of Operations for the years ended December 31, 2008, 2007 and 2006	60
Balance Sheets as of December 31, 2008 and 2007	61

Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	62
Statements of Changes in Stockholders’ Equity and Comprehensive Income (Loss) for the years ended December 31, 2008, 2007 and 2006	63
Notes to Consolidated Financial Statements, December 31, 2008, 2007 and 2006	65

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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, 2008. 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, 2008, 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, 2008 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report below.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Southwestern Energy Company:

In our opinion, the 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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, 2008, 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 Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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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 26, 2009

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STATEMENTS OF OPERATIONS

Southwestern Energy Company and Subsidiaries


	For the years ended December 31,
	2008	2007	2006
	(in thousands, except share/per share amounts)
Operating Revenues:
Gas sales	$ 1,490,646	$ 870,047	$ 572,354
Gas marketing	729,671	316,912	136,698
Oil sales	41,240	42,434	40,742
Gas gathering	41,748	11,627	1,553
Transportation and other	8,247	14,111	11,765
	2,311,552	1,255,131	763,112
Operating Costs and Expenses:
Gas purchases – midstream services	710,129	306,336	128,387
Gas purchases – gas distribution	61,439	85,445	79,363
Operating expenses	107,577	85,826	66,579
General and administrative expenses	101,959	80,269	66,112
Depreciation, depletion and amortization	414,408	293,914	151,290
Taxes, other than income taxes	29,272	21,875	25,109
	1,424,784	873,665	516,840
Operating Income	886,768	381,466	246,272

Interest Expense:
Interest on debt	61,152	36,191	11,099
Other interest charges	2,284	1,474	1,402
Interest capitalized	(34,532)	(13,792)	(11,822)
	28,904	23,873	679
Other Income (Loss)	4,404	(219)	17,079
Gain on Sale of Utility Assets	57,264	—	—

Income Before Income Taxes and Minority Interest	919,532	357,374	262,672
Minority Interest in Partnership	(587)	(345)	(637)
Income Before Income Taxes	918,945	357,029	262,035
Provision for Income Taxes:
Current	122,000	—	—
Deferred	228,999	135,855	99,399
	350,999	135,855	99,399
Net Income	$ 567,946	$ 221,174	$ 162,636

Earnings Per Share: ⁽¹⁾
Basic	$ 1.66	$ 0.65	$ 0.49
Diluted	$ 1.64	$ 0.64	$ 0.47

Weighted Average Common Shares Outstanding:⁽¹⁾
Basic	341,621,814	338,953,446	334,606,282
Effect of:
Stock options	4,237,263	8,024,198	6,953,402
Restricted stock awards	386,861	465,016	1,015,816
Diluted	346,245,938	347,442,660	342,575,500

(1) 2007 and 2006 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.

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BALANCE SHEETS

Southwestern Energy Company and Subsidiaries


	December 31,
	2008	2007
ASSETS	(in thousands)
Current Assets
Cash and cash equivalents	$ 196,277	$ 727
Accounts receivable	254,557	177,680
Inventories, at average cost	50,377	33,034
Hedging asset – FAS 133	343,320	64,472
Current assets held for sale (see Note 2)	—	58,877
Other	44,734	28,551
Total current assets	889,265	363,341
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method, including $540.6 million in 2008 and $372.4 million in 2007 excluded from amortization	4,836,077	4,020,448
Gathering systems	341,474	158,604
Gas in underground storage	13,349	13,349
Other	138,014	85,983
	5,328,914	4,278,384
Less: Accumulated depreciation, depletion and amortization	1,615,307	1,200,754
	3,713,607	3,077,630
Assets Held For Sale (see Note 2)	—	143,234
Other Assets	157,286	38,511
	$ 4,760,158	$ 3,622,716
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Short-term debt	$ 61,200	$ 1,200
Accounts payable	464,145	313,070
Taxes payable	31,951	5,087
Interest payable	20,857	2,213
Advances from partners	70,603	32,005
Hedging liability – FAS 133	10,899	8,598
Current deferred income taxes	122,448	20,909
Current liabilities associated with assets held for sale (see Note 2)	—	39,118
Other	10,758	8,695
Total current liabilities	792,861	430,895
Long-Term Debt	674,200	977,600
Other Liabilities
Deferred income taxes	721,707	479,196
Long-term hedging liability	5,934	15,186
Pension and other postretirement liabilities	15,436	14,618
Liabilities associated with assets held for sale (see Note 2)	—	15,417
Other	32,057	32,734
	775,134	557,151
Commitments and Contingencies
Minority Interest in Partnership	10,133	10,570
Stockholders’ Equity
Common stock, $0.01 par value; authorized 540,000,000 shares, issued 343,624,956 shares in 2008 and 341,581,672 in 2007⁽¹⁾	3,436	3,416
Additional paid-in capital⁽¹⁾	811,492	752,369
Retained earnings	1,449,977	882,031
Accumulated other comprehensive income	247,665	13,348
Common stock in treasury, 225,050 shares in 2008 and 222,774 in 2007⁽¹⁾	(4,740)	(4,664)
	2,507,830	1,646,500
	$ 4,760,158	$ 3,622,716

(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.

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STATEMENTS OF CASH FLOWS

Southwestern Energy Company and Subsidiaries


	For the years ended December 31,
	2008	2007	2006
	(in thousands)
Cash Flows From Operating Activities
Net Income	$ 567,946	$ 221,174	$ 162,636
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	416,151	295,332	152,519
Deferred income taxes	228,999	135,855	99,399
Gain on sale of utility assets	(57,264)	—	—
Unrealized loss (gain) on derivatives	4,644	(7,103)	5,579
Stock-based compensation expense	7,952	6,377	5,164
Gain on sale of investment in partnership and other property	(497)	—	(10,285)
Minority interest in partnership	(437)	(465)	(579)
Equity in income of NOARK partnership	—	—	(925)
Change in assets and liabilities:
Accounts receivable	(60,117)	(76,136)	(2,422)
Inventories	(39,475)	(10,800)	(12,975)
Accounts payable	72,894	61,284	20,742
Taxes payable	20,855	(3,454)	1,568
Interest payable	18,522	198	(808)
Advances from partners and customer deposits	38,418	7,615	24,317
Excess tax benefit for stock-based compensation	(43,107)	—	(14,609)
Other assets and liabilities	(14,675)	(7,142)	616
Net cash provided by operating activities	1,160,809	622,735	429,937

Cash Flows From Investing Activities
Capital investments	(1,755,888)	(1,519,433)	(850,910)
Proceeds from sale of assets	964,031	5,791	219,753
Other items	(221)	145	1,151
Net cash used in investing activities	(792,078)	(1,513,497)	(630,006)

Cash Flows From Financing Activities
Debt retirement	(1,200)	(1,200)	(1,200)
Payments on revolving long-term debt	(1,843,600)	(916,550)	(267,700)
Borrowings under revolving long-term debt	1,001,400	1,758,750	267,700
Proceeds from issuance of long-term debt	600,000	—	—
Debt issuance costs and revolving credit facility costs	(8,895)	(2,000)	—
Excess tax benefit for stock-based compensation	43,107	—	14,609
Change in bank drafts outstanding	31,397	5,193	2,009
Proceeds from exercise of common stock options	3,505	5,474	3,873
Net cash provided by (used in) financing activities	(174,286)	849,667	19,291

Increase (decrease) in cash and cash equivalents	194,445	(41,095)	(180,778)
Cash and cash equivalents at beginning of year⁽¹⁾	1,832	42,927	223,705
Cash and cash equivalents at end of year⁽¹⁾	$ 196,277	$ 1,832	$ 42,927

(1) Cash and cash equivalents at the beginning of the year for 2008 and at the beginning and end of the year 2007 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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STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)

Southwestern Energy Company and Subsidiaries


					Accumulated		Unamortized
			Additional		Other		Restricted
			Paid-In	Retained	Comprehensive	Common Stock	Stock
	Common Stock ⁽¹⁾		Capital ⁽¹⁾	Earnings	Income (Loss)	in Treasury	Awards	Total
	Shares Issued	Amount
	(in thousands)

Balance at December 31, 2005	336,904	$ 33,690	$ 694,351	$ 498,221	$ (104,874)	$ (3,390)	$ (7,694)	$ 1,110,304

Comprehensive income:
Net income	—	—	—	162,636	—	—	—	162,636
Change in value of derivatives	—	—	—	—	141,230	—	—	141,230
Change in value of pension and other postretirement liabilities	—	—	—	—	2,372	—	—	2,372
Total comprehensive income								306,238

Adoption of FAS 158	—	—	—	—	(7,241)	—	—	(7,241)
Adoption of FAS 123 (R)	—	—	(7,694)	—	—	—	7,694	—
Tax benefit for stock-based compensation	—	—	14,609	—	—	—	—	14,609
Stock-based compensation – FAS 123 (R)	—	—	6,857	—	—	3	—	6,860
Common stock par value adjustment	—	(30,321)	30,321	—	—	—	—	—
Exercise of stock options	988	10	922	—	—	2,941	—	3,873
Issuance of restricted stock	16	—	(513)	—	—	513	—	—
Cancellation of restricted stock	—	—	67	—	—	(67)	—	—
Balance at December 31, 2006	337,908	$ 3,379	$ 738,920	$ 660,857	$ 31,487	$ —	$ —	$ 1,434,643

Comprehensive income:
Net income	—	—	—	221,174	—	—	—	221,174
Change in value of derivatives	—	—	—	—	(16,775)	—	—	(16,775)
Change in value of pension and other postretirement liabilities	—	—	—	—	(1,364)	—	—	(1,364)
Total comprehensive income								203,035

Stock-based compensation – FAS 123 (R)	—	—	8,012	—	—	—	—	8,012
Exercise of stock options	3,414	34	5,440	—	—	—	—	5,474
Issuance of restricted stock	306	3	(3)	—	—	—	—	—
Cancellation of restricted sock	(50)	—	—	—	—	—	—	—
Treasury stock – non qualified plan	—	—	—	—	—	(4,664)	—	(4,664)
Balance at December 31, 2007	341,578	$ 3,416	$ 752,369	$ 882,031	$ 13,348	$ (4,664)	$ —	$ 1,646,500

Comprehensive income:
Net income	—	—	—	567,946	—	—	—	567,946
Change in value of derivatives	—	—	—	—	234,259	—	—	234,259
Change in value of pension and other postretirement liabilities	—	—	—	—	58	—	—	58
Total comprehensive income								802,263

Tax benefit for stock-based compensation	—	—	43,107	—	—	—	—	43,107
Stock-based compensation – FAS 123 (R)	—	—	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 sock	(66)	(1)	1	—	—	—	—	—
Issuance of stock awards	6	—	116	—	—	—	—	116
Treasury stock – non qualified plan	—	—	—	—	—	(76)	—	(76)
Balance at December 31, 2008	343,625	$ 3,436	$ 811,492	$ 1,449,977	$ 247,665	$ (4,740)	$ —	$ 2,507,830

(1) 2005, 2006 and 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.

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STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

Southwestern Energy Company and Subsidiaries

STATEMENT OF COMPREHENSIVE INCOME (LOSS)


	For the years ended December 31,
	2008	2007	2006
	(in thousands)

Net income	$ 567,946	$ 221,174	$ 162,636
Change in value of derivatives
Current period reclassification to earnings	45,830	(42,956)	(2,326)
Current period ineffectiveness	4,319	(618)	(12,726)
Current period change in derivative instruments	184,110	26,799	156,282
Total change in value of derivatives	234,259	(16,775)	141,230

Change in value of pension and other postretirement liabilities
Sale of utility – divestiture, curtailment and settlement	9,040	—	—
Current period change in value of pension and other postretirement liabilities	(8,982)	(1,364)	2,372
Total change in value of pension and other postretirement liabilities	58	(1,364)	2,372
Comprehensive income, end of year	$ 802,263	$ 203,035	$ 306,238

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Southwestern Energy Company and Subsidiaries

December 31, 2008, 2007 and 2006

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and Consolidation

Southwestern Energy Company (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 and production (E&P) activities are currently concentrated in Arkansas, Oklahoma, Pennsylvania and Texas. Southwestern’s marketing and gas gathering business (Midstream Services) is concentrated in the core areas of its E&P operations. Historically, the Company has been engaged in natural gas distribution and transmission through its wholly-owned utility subsidiary, Arkansas Western Gas (“AWG”), which operated in northern Arkansas. Effective July 1, 2008, the Company sold all of AWG’s stock and, as a result, the Company no longer has any natural gas distribution operations.

The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries, including SEECO, Inc., Southwestern Energy Production Company (SEPCO), Southwestern Energy Services Company (SES), Southwestern Midstream Services Company (SMS), Diamond “M” Production Company and A.W. Realty Company. The consolidated financial statements also include the results for (i) Overton Partners, L.P., of which SEPCO is the sole general partner, (ii) DeSoto Drilling Inc., (iii) DeSoto Gathering Company, L.L.C, and (iv) Angelina Gathering Company, L.L.C. All significant intercompany accounts and transactions have been eliminated. Prior to the sale of its interest in 2006, the Company accounted for its general partnership interest in the NOARK Pipeline System, Limited Partnership (NOARK) using the equity method of accounting. In accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation,” the Company recognized profit on intercompany sales of gas delivered to storage by its utility subsidiary, AWG, prior to the sale of this segment.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.

In connection with the sale of AWG, the Company received $223.5 million (net of expenses related to the sale) and, in order to receive regulatory approval for the sale and certain related transactions, paid $9.8 million to AWG for the benefit of its customers. The Company recorded a pre-tax gain on the sale of $57.3 million in the third quarter of 2008. Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (FAS 144), requires that long-lived assets or disposal groups to be sold to be classified as “held for sale” in the period in which certain criteria are met. Accordingly, the assets and liabilities of AWG have been presented as “held for sale” in the December 31, 2007 balance sheet. The E&P segment sells natural gas to AWG and the cash flows from these sales are deemed “significant” under accounting rules. Therefore, the results of operations for AWG are consolidated in the statements of operations and are not presented as “discontinued operations.”

Certain reclassifications have been made to the prior years’ financial statements to conform to the 2008 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements. All share and per share amounts have been restated as necessary to reflect the two-for-one stock split effected in March 2008.

Minority Interest in Partnership

In 2001, SEPCO formed a limited partnership, Overton Partners, L.P., with an investor to drill and complete 14 development wells in SEPCO’s Overton Field located in Smith County, Texas. Because SEPCO is the sole general partner and owns a majority interest in the partnership, the operating and financial results are consolidated with the Company's exploration and production results and the investor’s share of the partnership activity is reported as a minority interest item in the financial statements. SEPCO contributed 50% of the capital required to drill the 14 wells. Revenues and expenses are allocated 65% to SEPCO prior to payout of the investor’s initial investment and 85% thereafter. Under the terms of the partnership agreement, the partnership has a maximum life of 50 years.

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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.

Inventory

Inventory recorded in current assets includes $24.1 million at December 31, 2008, and $25.0 million at December 31, 2007, for gas in underground storage owned by the Company’s E&P segment, and $26.3 million at December 31, 2008, and $8.1 million at December 31, 2007, for tubulars and other equipment used in the Company’s E&P segment. Additionally, the Natural Gas Distribution segment had current gas in underground storage of $21.6 million at December 31, 2007, that was classified in the balance sheet as “Current Assets Held for Sale.”

The Company has one facility containing gas in underground storage. The current portion of the gas is classified in inventory and carried at the lower of cost or market. The non-current portion of the gas is classified in property, plant 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 gas in underground storage are accounted for by a weighted average cost method whereby gas withdrawn from storage is relieved at the weighted average cost of current gas remaining in the facility.

Other assets includes $43.8 million at December 31, 2008, and $16.7 million at December 31, 2007, 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 used by the Company’s segments 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

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 and amortized on an aggregate basis 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 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 prices in effect at the end of each accounting quarter, including the impact of derivatives qualifying as hedges, to calculate the ceiling value of their reserves. However, commodity price increases subsequent to the end of a reporting period but prior to the release of periodic reports may be utilized to calculate the ceiling value of reserves. At December 31, 2008, 2007 and 2006, the Company’s unamortized costs of natural gas and oil properties did not exceed this ceiling amount. At December 31, 2008, the ceiling value of the Company’s reserves was calculated based upon quoted market prices of $5.71 per Mcf for Henry Hub gas and $41.00 per barrel for West Texas Intermediate oil, adjusted for market differentials. Cash flow hedges of gas production in place at December 31, 2008 increased the calculated ceiling value by approximately $338.7 million (net of tax). Excluding the benefit of the cash flow hedges at December 31, 2008, unamortized costs still did not exceed the ceiling value. The Company had approximately 185.0 Bcf of future gas production hedged at December 31, 2008. At December 31, 2007, the ceiling value of the Company’s reserves was calculated based upon quoted market prices of $6.80 per Mcf for Henry Hub gas and $92.50 per barrel for West Texas Intermediate oil, and at December 31, 2006, the ceiling value of the Company’s reserves was calculated based upon quoted market prices of $5.64 per Mcf for Henry Hub gas and $57.25 per barrel for West Texas Intermediate oil. Decreases in market prices from December 31, 2008 levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs, and service costs could result in future ceiling test impairments.

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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. Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (FAS 143) was adopted by the Company on January 1, 2003. FAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Company owns natural gas and oil properties which require expenditures to plug and abandon the wells when reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the period the liability is incurred (at the time the wells are drilled or acquired). The following table summarizes the Company’s 2008 and 2007 activity related to asset retirement obligations:


	2008	2007
	(in thousands)

Asset retirement obligation at January 1	$ 12,114	$ 10,545
Accretion of discount	519	481
Obligations incurred	2,346	2,236
Obligations settled/removed	(2,744)	(499)
Revisions of estimates	672	(649)
Asset retirement obligation at December 31	$ 12,907	$ 12,114

Current liability	578	720
Long-term liability	12,329	11,394
Asset retirement obligation at December 31	$ 12,907	$ 12,114

Rig Sale and Leaseback

On December 29, 2006, the Company entered into a sale and leaseback transaction pursuant to which it 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. The Company received proceeds of $127.3 million. Subject to certain conditions, the Company has options to purchase the rigs and related equipment from the lessors in December 2013 at an agreed upon price or at the end of the lease term for the then fair market value. Additionally, the Company has 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 December 2008, pursuant to the terms of the lease, one of the lessors required the Company 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.

In 2007, the Company 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 accordance with the Company’s accounting procedures, the lease payments for the drilling rigs, as well as other operating expenses for the Company’s drilling operations, are capitalized to the full cost pool and are partially offset by billings to third-party working interest owners for their share of rig day-rate charges.

The Company’s current aggregate annual rental payment for drilling rigs and related equipment under the leases is approximately $19.4 million.

Gas Production Revenue and Imbalances

The E&P subsidiaries record gas sales using the entitlement method. The entitlement method requires revenue recognition of the Company’s revenue interest share of production from properties in which sales are disproportionately allocated to owners because of marketing or other contractual arrangements. At December 31, 2008, the Company had overproduction of 1.4 Bcf valued at $4.5 million and underproduction of 1.7 Bcf valued at $5.1 million. At December 31, 2007, the Company had overproduction of 1.4 Bcf valued at $4.3 million and underproduction of 1.8 Bcf valued at $5.8 million.

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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. As a result of the gains on the non-core asset sales, the Company used all of its net operating loss carryforward in 2008. See Note 5 for additional information.

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 and crude oil. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas and oil sales in the statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in 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 those contracts that do not qualify for hedge accounting treatment are recognized currently in gas and oil sales. See Note 10 for a discussion of the Company’s hedging activities and the effects of FAS 133.

Earnings Per Share

Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during each year. The diluted earnings per share 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, 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, 2007, 8,142,624 of the Company’s outstanding options with an average exercise price of $3.69 were included in the calculation of diluted shares. Options for 410,250 shares were excluded from the calculation because they would have had an antidilutive effect. For the year ended December 31, 2006, 10,703,618 of the Company’s outstanding options with an average exercise price of $1.79 were included in the calculation of diluted shares. Options for 880,862 shares were excluded from the calculation 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. For the year ended December 31, 2007, the number of shares of restricted stock included in the calculation of diluted shares was 569,508. The calculation excluded 221,522 shares of restricted stock because they would have had an antidilutive effect. For the year ended December 31, 2006, the number of shares of restricted stock included in the calculation of diluted shares was 621,234. The calculation excluded 336,230 shares of restricted stock because they would have had an antidilutive effect.

In February 2008, the Board of Directors declared a two-for-one stock split with respect to the Company’s common stock, which was effected in March 2008. All historical per share information in the financial statements and footnotes has been adjusted, as necessary, to reflect the two-for-one stock split.

Stock-Based Compensation

In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123R “Share-Based Payment” (FAS 123R). FAS 123R requires that companies recognize compensation expense equal to the fair value of stock options or other share based payments. The Company adopted this standard during the year ended December 31, 2006, using the modified prospective method. See Note 12 for further discussion of the Company’s stock based compensation.

(2) ASSETS HELD FOR SALE

As discussed in Note 1 above, the Company sold all of AWG’s capital stock effective July 1, 2008 pursuant to an agreement that was executed in November 2007. Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (FAS 144), requires that long-lived assets or disposal groups to be sold should be classified as “held for sale” in the period in which certain criteria are met. Accordingly, the assets and liabilities of AWG have been presented as “held for sale” in the December 31, 2007 balance sheet.

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The following table presents the assets and liabilities of AWG as of December 31, 2007:


	2007
	(in thousands)
Current Assets:
Cash	$ 1,105
Accounts receivable	29,826
Inventory	23,737
Hedging asset – FAS 133	2,387
Other current assets	1,822
	$ 58,877

Long-term assets, including property, plant and equipment, net of accumulated depreciation and amortization	$ 143,234

Current Liabilities:
Accounts payable	$ 3,700
Interest payable	171
Taxes payable	7,547
Deferred gas purchases	16,289
Customer deposits	7,551
Hedging liability – FAS 133	2,387
Other current liabilities	1,473
	$ 39,118
Long-term Liabilities:
Deferred income taxes	$ 15,066
Other long-term liabilities	351
	$ 15,417

(3) DEBT

Debt balances as of December 31, 2008 and 2007 consisted of the following:


	2008		2007
	(in thousands)
Short-term debt:
7.625% Senior Notes due 2027, putable at the holders’ option in 2009	$ 60,000	$ —
7.15% Senior Notes due 2018	1,200	1,200
Total short-term debt	61,200	1,200

Long-term debt:
Variable rate unsecured revolving credit facility, expires February 2012	—	842,200
7.5% Senior Notes due 2018	600,000	—
7.625% Senior Notes due 2027, putable at the holders’ option in 2009	—	60,000
7.21% Senior Notes due 2017	40,000	40,000
7.15% Senior Notes due 2018	34,200	35,400
Total long-term debt	674,200	977,600

Total debt	$ 735,400	$ 978,800

On January 16, 2008, the Company issued $600 million of 7.5% Senior Notes due 2018 in a private placement. If the Company undergoes a “change of control,” as defined in the indenture, holders of the 7.5% Senior Notes will have the option to require the Company to purchase all or any portion of the notes at a purchase price equal to 101% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the change of control date. Payment obligations with respect to the 7.5% Senior Notes are currently guaranteed 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. 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, on May 2, 2008, the Company and its subsidiaries, SEECO, SEPCO and SES, entered into supplemental indenture agreements with

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the trustees under the indentures relating to the Company’s 7.625% Medium-Term Notes due 2027, 7.125% Fixed Rate Notes due October 10, 2017, 7.35% Fixed Rate Notes due October 2, 2017 and 7.15% Notes due 2018, 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. Please refer to Note 4, "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.

The Company has an unsecured revolving credit facility with a borrowing capacity of $1.0 billion which may be increased to $1.25 billion at any time upon the Company’s agreement with its existing or additional lenders. The interest rate on the credit facility is calculated based upon the Company’s debt rating and is currently 87.5 basis points over the current London Interbank Offered Rate (LIBOR). The revolving credit facility is currently guaranteed by the Company’s subsidiaries, SEECO, SEPCO and SES and requires additional subsidiary guarantors if certain guaranty coverage levels are not satisfied. The revolving credit facility also 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, must maintain a certain level of stockholders' equity, and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of 3.5 or above. There are also restrictions on the ability of the Company’s subsidiaries to incur debt. The credit status of the financial institutions participating in the Company’s revolving credit facility could adversely impact its ability to borrow funds under the facility. While the Company believes all of the lenders under the facility have the ability to provide funds, it cannot predict whether each will be able to meet its obligation under the facility. Current economic conditions make it difficult to access debt and equity markets for funding.

The 7.15% Senior Notes were assumed by the Company in 2006 in connection with the sale of the Company’s general partnership interest in NOARK. The Company had previously guaranteed the notes.

The 7.625% Senior Notes are putable at the holders’ option in May 2009 and, as a result, are classified as short-term debt at December 31, 2008. Other than the 7.625% Senior Notes, aggregate maturities of debt for each of the years ending December 31, 2009 through 2013 are $1.2 million per year for the 7.15% Senior Notes.

At December 31, 2008, the Company’s capital structure consisted of 23% debt and 77% equity and it was in compliance with the financial covenants of its debt agreements. Total interest payments were $42.5 million in 2008, $36.0 million in 2007 and $10.8 million in 2006.

(4) 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 have jointly and severally, fully and unconditionally guaranteed the Company’s 7.625% Senior Notes and 7.21% Senior Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated to any future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors.

In November 2007, the Company entered an agreement to sell AWG, a non-guarantor subsidiary, and the sale was consummated as of July 1, 2008. The assets and liabilities of AWG have been presented as “held for sale” in the condensed consolidating balance sheet for the non-guarantor subsidiaries as of December 31, 2007.

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, 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)	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 before income taxes and minority interest	589,836	806,788	55,480	(532,572)	919,532
Minority interest in partnership	—	(587)	—	—	(587)
Provision for income taxes	21,890	308,127	20,982	—	350,999
Net income	$ 567,946	$ 498,074	$ 34,498	$ (532,572)	$ 567,946

Year ended December 31, 2007:
Operating revenues	$ —	$ 1,115,656	$ 221,805	$ (82,330)	$ 1,255,131
Operating costs and expenses:
Gas purchases	—	336,876	111,338	(56,433)	391,781
Operating expenses	—	62,569	48,588	(25,331)	85,826
General and administrative expenses	—	57,048	23,787	(566)	80,269
Depreciation, depletion and amortization	—	280,592	13,322	—	293,914
Taxes, other than income taxes	—	17,420	4,455	—	21,875
Total operating costs and expenses	—	754,505	201,490	(82,330)	873,665
Operating income	—	361,151	20,315	—	381,466
Other income (loss)	—	109	(328)	—	(219)
Equity in earnings of subsidiaries	221,174	—	—	(221,174)	—
Interest expense	—	16,766	7,107	—	23,873
Income before income taxes and minority interest	221,174	344,494	12,880	(221,174)	357,374
Minority interest in partnership	—	(345)	—	—	(345)
Provision for income taxes	—	130,957	4,898	—	135,855
Net income	$ 221,174	$ 213,192	$ 7,982	$ (221,174)	$ 221,174

Year ended December 31, 2006:
Operating revenues	$ —	$ 641,071	$ 191,778	$ (69,737)	$ 763,112
Operating costs and expenses:
Gas purchases	—	157,375	112,922	(62,547)	207,750
Operating expenses	—	39,138	34,068	(6,627)	66,579
General and administrative expenses	—	43,503	23,172	(563)	66,112
Depreciation, depletion and amortization	—	141,729	9,561	—	151,290
Taxes, other than income taxes	—	20,994	4,115	—	25,109
Total operating costs and expenses	—	402,739	183,838	(69,737)	516,840
Operating income	—	238,332	7,940	—	246,272
Other income (loss)	10,862	6,282	(65)	—	17,079
Equity in earnings of subsidiaries	155,894	—	—	(155,894)	—
Interest expense	—	411	268	—	679
Income before income taxes and minority interest	166,756	244,203	7,607	(155,894)	262,672
Minority interest in partnership	—	(637)	—	—	(637)
Provision for income taxes	4,120	90,719	4,560	—	99,399
Net income	$ 162,636	$ 152,847	$ 3,047	$ (155,894)	$ 162,636

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CONDENSED CONSOLIDATING BALANCE SHEETS

	Parent	Guarantors	Non- Guarantors	Eliminations	Consolidated
December 31, 2008:	(in thousands)

ASSETS

Cash and cash equivalents	$ 195,969	$ —	$ 308	$ —	$ 196,277
Accounts receivable	404	250,687	3,466	—	254,557
Inventories, at average cost	—	49,579	798	—	50,377
Other	9,837	377,455	762	—	388,054
Total current assets	206,210	677,721	5,334	—	889,265
Intercompany receivables/note	1,252,573	(896,577)	(347,293)	(8,703)	—
Investments	—	10,309	(10,308)	(1)	—
Property, plant and equipment, at cost	57,438	4,844,970	426,506	—	5,328,914
Accumulated depreciation, depletion and amortization	(30,679)	(1,548,927)	(35,701)	—	(1,615,307)
Net property, plant and equipment	26,759	3,296,043	390,805	—	3,713,607
Investments in subsidiaries (equity method)	1,811,924	—	—	(1,811,924)	—
Other assets	13,983	99,547	43,756	—	157,286
Total assets	$ 3,311,449	$ 3,187,043	$ 82,294	$(1,820,628)	$ 4,760,158

LIABILITIES AND STOCKHOLDERS’ EQUITY

Accounts and notes payable	$ 241,227	$ 330,270	$ 15,360	$ (8,704)	$ 578,153
Other current liabilities	1,810	210,087	2,811	—	214,708
Total current liabilities	243,037	540,357	18,171	(8,704)	792,861
Long-term debt	674,200	—	—	—	674,200
Other liabilities	25,723	22,686	5,018	—	53,427
Commitments and contingencies
Deferred income taxes	(139,341)	845,593	15,455	—	721,707
Minority interest in partnership	—	10,133	—	—	10,133
Total liabilities	803,619	1,418,769	38,644	(8,704)	2,252,328
Stockholders’ equity	2,507,830	1,768,274	43,650	(1,811,924)	2,507,830
Total liabilities and stockholders’ equity	$ 3,311,449	$ 3,187,043	$ 82,294	$(1,820,628)	$ 4,760,158

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CONDENSED CONSOLIDATING BALANCE SHEETS (Continued)

	Parent	Guarantors	Non- Guarantors	Eliminations	Consolidated
December 31, 2007:	(in thousands)

ASSETS

Cash	$ 433	$ —	$ 294	$ —	$ 727
Accounts receivable	346	173,772	3,562	—	177,680
Inventories, at average cost	—	33,034	—	—	33,034
Current assets held for sale (see Note 2)	—	—	58,877	—	58,877
Other	8,270	83,572	1,181	—	93,023
Total current assets	9,049	290,378	63,914	—	363,341
Intercompany receivables/note	1,565,533	(1,323,433)	(148,949)	(93,151)	—
Investments	—	8,444	(8,443)	(1)	—
Property, plant and equipment, at cost	47,623	4,016,483	214,278	—	4,278,384
Accumulated depreciation, depletion and amortization	(23,772)	(1,149,713)	(27,269)	—	(1,200,754)
Net property, plant and equipment	23,851	2,866,770	187,009	—	3,077,630
Investments in subsidiaries (equity method)	1,120,985	—	—	(1,120,985)	—
Assets held for sale (see Note 2)	—	—	143,234	—	143,234
Other assets	7,518	14,277	16,716	—	38,511
Total assets	$ 2,726,936	$ 1,856,436	$ 253,481	$(1,214,137)	$ 3,622,716

LIABILITIES AND STOCKHOLDERS’ EQUITY

Accounts and notes payable	$ 105,259	$ 220,923	$ 9,503	$ (14,115)	$ 321,570
Current liabilities associated with assets held for sale (see Note 2)	—	—	39,118	—	39,118
Other current liabilities	1,368	67,530	1,309	—	70,207
Total current liabilities	106,627	288,453	49,930	(14,115)	430,895
Long-term debt	977,600	—	—	—	977,600
Indebtedness to related parties – noncurrent	—	—	79,037	(79,037)	—
Liabilities associated with assets held for sale (see Note 2)	—	—	15,417	—	15,417
Other liabilities	26,091	30,845	5,602	—	62,538
Commitments and contingencies
Deferred income taxes	(29,882)	508,041	1,037	—	479,196
Minority interest in partnership	—	10,570	—	—	10,570
Total liabilities	1,080,436	837,909	151,023	(93,152)	1,976,216
Stockholders’ equity	1,646,500	1,018,527	102,458	(1,120,985)	1,646,500
Total liabilities and stockholders’ equity	$ 2,726,936	$ 1,856,436	$ 253,481	$(1,214,137)	$ 3,622,716

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CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Parent	Guarantors	Non-Guarantors		Eliminations	Consolidated
	(in thousands)
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 assets	213,721	700,289	50,021		—	964,031
Other items	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 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
Excess tax benefit for stock-based compensation	43,107	—	—		—	43,107
Other items	24,807	—	—		—	24,807
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

Year ended December 31, 2007:
Net cash provided by operating activities	$ 27,724	$ 573,184	$ 21,827		$ —	$ 622,735
Investing activities:
Capital investments	(6,893)	(1,388,204)	(124,336)		—	(1,519,433)
Proceeds from sale of assets	—	2,725	3,066		—	5,791
Other items	4,883	(4,581)	(157)		—	145
Net cash used in investing activities	(2,010)	(1,390,060)	(121,427)		—	(1,513,497)
Financing activities:
Intercompany activities	(917,475)	816,876	100,599		—	—
Payments on revolving long-term debt	(916,550)	—	—		—	(916,550)
Borrowings under revolving long-term debt	1,758,750	—	—		—	1,758,750
Other items	7,467	—	—		—	7,467
Net cash provided by (used in) financing activities	(67,808)	816,876	100,599		—	849,667
Increase (decrease) in cash and cash equivalents	(42,094)	—	999		—	(41,095)
Cash and cash equivalents at beginning of year	42,527	—	400	⁽¹⁾	—	42,927	^⁽¹⁾
Cash and cash equivalents at end of year	$ 433	$ —	$ 1,399	⁽¹⁾	$ —	$ 1,832	⁽¹⁾

Year ended December 31, 2006:
Net cash provided by (used in) operating activities	$ (3,487)	$ 415,785	$ 17,639		$ —	$ 429,937
Investing activities:
Capital investments	(14,956)	(681,270)	(154,684)		—	(850,910)
Proceeds from sale of assets	69,000	12,876	137,877		—	219,753
Other items	(42)	(6,218)	7,411		—	1,151
Net cash provided by (used in) investing activities	54,002	(674,612)	(9,396)		—	(630,006)
Financing activities:
Intercompany activities	(250,178)	258,827	(8,649)		—	—
Payments on revolving long-term debt	(267,700)	—	—		—	(267,700)
Borrowings under revolving long-term debt	267,700	—	—		—	267,700
Excess tax benefit for stock-based compensation	14,609	—	—		—	14,609
Other items	4,682	—	—		—	4,682
Net cash provided by (used in) financing activities	(230,887)	258,827	(8,649)		—	19,291
Decrease in cash and cash equivalents	(180,372)	—	(406)		—	(180,778)
Cash and cash equivalents at beginning of year	222,899	—	806		—	223,705
Cash and cash equivalents at end of year	$ 42,527	$ —	$ 400		$ —	$ 42,927

(1) Cash and cash equivalents at the beginning of the year for 2008 and the beginning and end of the year 2007 include amounts classified as “held for sale.” See Note 2 for additional information.

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(5) INCOME TAXES

The provision for income taxes included the following components:


	2008	2007	2006
	(in thousands)
Federal:
Current	$ 122,000	$ —	$ —
Deferred	183,601	120,200	90,186
State:
Current	—	—	—
Deferred	45,445	15,757	9,320
Investment tax credit amortization	(47)	(102)	(107)
Provision for income taxes	$ 350,999	$ 135,855	$ 99,399

The provision for income taxes was an effective rate of 38.2% in 2008, 38.1% in 2007 and 37.9% in 2006. 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:


	2008	2007	2006
	(in thousands)

Expected provision at federal statutory rate of 35%	$ 321,631	$ 124,960	$ 91,712
Increase resulting from:
State income taxes, net of federal income tax effect	29,539	10,242	6,058
Other	(171)	653	1,629
Provision for income taxes	$ 350,999	$ 135,855	$ 99,399

The components of the Company’s net deferred tax liability as of December 31, 2008 and 2007 were as follows:


	2008	2007
	(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property	$ 828,074	$ 763,903
Stored gas	—	7,448
Cash flow hedges – FAS 133	158,789	17,043
Other	11,716	7,903
	998,579	796,297

Deferred tax assets:
Accrued compensation	9,325	8,691
Alternative minimum tax credit carryforward	121,526	3,026
Stored gas	6,780	—
Accrued pension costs	5,831	6,040
Book over tax basis in partnerships	1,467	1,247
Asset retirement obligations – FAS 143	4,510	3,728
Net operating loss carryforward	—	252,122
Other	4,985	6,792
	154,424	281,646
Net deferred tax liability	$ 844,155	$ 514,651

The net deferred tax liability at December 31, 2008, consisted of a net current deferred income tax liability of $122.5 million and long-term net deferred income tax liabilities of $721.7 million. In 2008, the Company paid $107.5 million in income taxes. There were no income tax payments made in 2007 and $6,000 paid in 2006. The Company also had an alternative minimum tax credit carryforward of $121.5 million and a statutory depletion carryforward of $8.6 million at December 31, 2008.

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Under FAS 123R, deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises in 2008 and 2007. Some exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the grant (“windfalls”). In 2008 and 2007, windfalls excluded from net income are $52.3 million and $62.6 million, respectively. Pursuant to FAS 123R, the additional tax benefit associated with the windfall is not recognized until the deduction reduces current tax payable. Accordingly, since the tax benefit did not reduce current taxes payable in 2007 due to net operating loss carryforwards, these “windfall” tax benefits were not reflected in 2007. However, due to the utilization of the net operating loss carryforward in 2008, the additional tax benefit associated with the windfall was recognized in 2008.

Under FASB Interpretation number 48 “Accounting for Uncertainty in Income Taxes” (FIN 48), the Company has no material unrecognized tax benefits at the beginning or end of the periods presented in the financial statements. The income tax years 2004-2007 remain open to examination by the major taxing jurisdictions to which the Company is subject.

(6) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

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 plans provide 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.

The Company applies Statement of Financial Accounting Standards No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (FAS 132). Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. Additionally, the Company applies Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (FAS 158). FAS 158 requires, among other things, the recognition of the funded status of each defined pension benefit plan, retiree health care and other postretirement benefit plans and postemployment benefit plans on the balance sheet. Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. The initial impact of the standard due to unrecognized prior service costs or credits and net actuarial gains or losses as well as subsequent changes in the funded status were recognized as a component of accumulated comprehensive loss in stockholders’ equity. Additional minimum pension liabilities and related intangible assets were also derecognized upon adoption of the new standard. FAS 158 was adopted by the Company as of December 31, 2006.

As a result of the sale of AWG on July 1, 2008, the Company transferred pension and other postretirement plan assets and liabilities related to the employees of AWG to the purchaser. Although the net periodic benefit costs for the Company’s pension and other postretirement plans were approximately 30% lower in the second half of 2008 compared to the first half of 2008, the pension costs for the year were higher due to the deterioration of the markets in the second half of 2008. The Company also incurred a net curtailment and settlement cost of $4.4 million resulting from the transfer of certain pension and other postretirement plan assets and liabilities to the purchaser of AWG. Accordingly, the net curtailment and settlement cost was included as an offset to the gain recognized on the sale of AWG.

The amounts in accumulated other comprehensive loss that are expected to be recognized as components of net periodic benefit cost (credit) during the next fiscal year are $0.3 million for prior service costs, $0.7 million net loss and $0.1 million for transition obligation costs.

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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, 2008 and 2007:


			Other Postretirement
	Pension Benefits		Benefits
	2008	2007	2008	2007
	(in thousands)
Change in benefit obligations:
Benefit obligation at January 1	$ 79,393	$ 70,863	$ 4,261	$ 3,694
Service cost	4,883	3,983	581	418
Interest cost	3,808	4,243	217	215
Participant contributions	—	—	52	108
Actuarial loss/(gain)	2,364	4,706	787	129
Benefits paid	(6,874)	(4,889)	(143)	(303)
Plan amendments	—	487	178	—
Curtailments (sale of utility)	(5,505)	—	(2,303)	—
Settlements (sale of utility)	(30,106)	—	(1,291)	—
Benefit obligation at December 31	$ 47,963	$ 79,393	$ 2,339	$ 4,261


			Other Postretirement
	Pension Benefits		Benefits
	2008	2007	2008	2007
	(in thousands)
Change in plan assets:
Fair value of plan assets at January 1	$ 67,125	$ 59,166	$ 1,911	$ 1,617
Actual return/(loss) on plan assets	(8,222)	6,334	(11)	84
Employer contributions	9,773	6,514	278	405
Participant contributions	—	—	52	108
Benefit payments	(6,874)	(4,889)	(143)	(303)
Curtailments and settlements (sale of utility)	(26,936)	—	(2,087)	—
Fair value of plan assets at December 31	$ 34,866	$ 67,125	$ —	$ 1,911
Funded status of plans at December 31	$ (13,097)	$ (12,268)	$ (2,339)	$ (2,350)

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 (loss) related to the pension plans was a loss of $0.3 million ($0.2 million after tax) for the year ended December 31, 2008 and a loss of $2.5 million ($1.4 million after tax) for the year ended December 31, 2007. The change in accumulated other comprehensive income (loss) related to the other postretirement benefit plans was a gain of $0.4 million ($0.2 million after tax) for the year ended December 31, 2008 and was negligible for the year ended December 31, 2007. Included in accumulated other comprehensive income (loss) at December 31, 2008 and 2007 was a $18.2 million loss ($11.2 million net of tax) and an $18.2 million loss ($11.3 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans.

The Company’s pension plans have an accumulated benefit obligation in excess of plan assets as of December 31, 2008 and 2007 as follows:


	2008	2007
	(in thousands)

Projected benefit obligation	$ 47,963	$ 79,393
Accumulated benefit obligation	$ 42,901	$ 71,104
Fair value of plan assets	$ 34,866	$ 67,125

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Pension and other postretirement benefit costs include the following components for 2008, 2007 and 2006:


				Other Postretirement
	Pension Benefits			Benefits
	2008	2007	2006	2008	2007	2006
	(in thousands)

Service cost	$ 4,883	$ 3,983	$ 3,011	$ 581	$ 419	$ 271
Interest cost	3,808	4,243	3,881	217	215	189
Expected return on plan assets	(3,894)	(4,559)	(4,578)	(48)	(81)	(69)
Amortization of transition obligation	—	—	—	76	86	86
Amortization of prior service cost	412	475	436	10	—	—
Amortization of net loss	430	460	759	34	21	34
Net periodic benefit cost	5,639	4,602	3,509	870	660	511
Curtailment and settlement cost (benefit)⁽¹⁾	4,630	—	—	(216)	—	—
Total benefit cost	$ 10,269	$ 4,602	$ 3,509	$ 654	$ 660	$ 511

(1) Related to the sale of AWG and the resulting transfer of certain pension and other postretirement assets and liabilities to the purchaser of AWG. Accordingly, the net curtailment and settlement cost was included as an offset to the gain recognized on the sale of AWG.

Amounts recognized in other comprehensive income for the year ended December 31, 2008 were as follows:


	Pension Benefits	Other Postretirement Benefits
	(in thousands)

Net actuarial loss arising during the year	$ (14,480)	$ (846)
Amortization of transition obligation	—	76
Amortization of prior service cost	412	10
Amortization of net loss	430	34
Plan amendments	—	(178)
Curtailments (sale of utility)	6,096	1,671
Settlements (sale of utility)	7,209	(381)
Tax effect	151	(146)
	$ (182)	$ 240

The weighted average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2008 and 2007 are as follows:


			Other Postretirement
	Pension Benefits		Benefits
	2008	2007	2008	2007

Discount rate	6.00%	6.00%	6.00%	6.00%
Rate of compensation increase	4.50%	4.00%	n/a	n/a

The weighted average assumptions used in the measurement of the Company's net periodic benefit cost for 2008, 2007 and 2006 are as follows:


				Other Postretirement
	Pension Benefits			Benefits
	2008	2007	2006	2008	2007	2006

Discount rate	6.00%	6.00%	5.50%	6.00%	6.00%	5.50%
Expected return on plan assets	7.75%	8.00%	8.25%	5.00%	5.00%	5.00%
Rate of compensation increase	4.00%	4.00%	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 ERISA and with a prudent level of diversification.

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For measurement purposes, the following trend rates were assumed for 2008 and 2007:


	2008	2007

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	2028	2013

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	$ 121	$ (102)
Effect on postretirement benefit obligation	$ 302	$ (258)

The Company’s pension plan weighted-average asset allocations at December 31, 2008 and 2007, by asset category, are as follows:


	2008	2007
Asset category:
Equity securities	41%	55%
Debt securities	43%	39%
Cash equivalents	16%	6%
Total	100%	100%

As a result of the sale of AWG on July 1, 2008, the Company transferred all other postretirement plan assets to the purchaser. Assets of the postretirement benefit plans were invested 100% in debt securities for 2007.

The investment objective of the benefit plans is to ensure, over the long-term life of the plans, an adequate pool of assets to support the benefit obligations to participants, retirees and beneficiaries. As of December 31, 2008, the defined benefit pension plan had a diversified asset allocation strategy of 55% to 75% and a target of 60% for equity securities and 35% to 45% and a target of 40% for debt (fixed income) securities. At December 31, 2008, the plan’s equity allocation was below its strategic range due to cash contributions made to the plan near the end of 2008. Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range. Within the equity allocation, the plan invests in small cap, international, large cap growth, large cap value and large cap core securities.

In 2008, the Company contributed $9.8 million to its pension plans and $0.3 million to its other postretirement benefit plans. The Company expects to contribute $6.0 million to its pension plans and $0.1 million to its other postretirement benefit plans in 2009. 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)

2009	$ 2,580	$ 58
2010	$ 4,222	$ 69
2011	$ 3,915	$ 92
2012	$ 2,558	$ 154
2013	$ 3,275	$ 225
Years 2014-2018	$ 17,973	$ 2,055

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The Company also maintains a non-qualified defined contribution supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation, as permitted by the plan. The Company maintains supplemental retirement savings plan assets that are accounted for in accordance with EITF Issue No. 97-14, “Accounting for Deferred Compensation Arrangements Where Accounts are Held in a Rabbi Trust and Invested” (EITF 97-14), and the underlying assets are held in a Rabbi Trust. Shares of the Company’s common stock purchased under a non-qualified deferred compensation arrangement are held in a Rabbi Trust and are presented as treasury stock. As of December 31, 2008, 225,050 shares were accounted for as treasury stock, compared to 222,774 shares at December 31, 2007.

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

All of the Company’s gas and oil properties are located in the United States. The table below sets forth the results of operations from gas and oil producing activities:


	2008	2007	2006
	(in thousands)

Sales	$ 1,491,302	$ 795,944	$ 491,545
Production (lifting) costs	(194,234)	(97,645)	(68,479)
Depreciation, depletion and amortization	(399,159)	(281,910)	(143,101)
	897,909	416,389	279,965
Income tax expense	(342,658)	(157,584)	(105,227)
Results of operations	$ 555,251	$ 258,805	$ 174,738

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

The table below sets forth capitalized costs incurred in gas and oil property acquisition, exploration and development activities during 2008, 2007 and 2006:


	2008	2007	2006
	(in thousands, except per Mcfe amounts)

Proved property acquisition costs	$ —	$ 1,540	$ 18,697
Unproved property acquisition costs	97,645	72,292	55,032
Exploration costs	245,363	527,456	231,771
Development costs	1,216,987	769,588	453,956
Capitalized costs incurred	1,559,995	1,370,876	759,456
Full cost pool amortization per Mcfe	$ 1.99	$ 2.41	$ 1.90

Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $34.5 million, $13.8 million and $10.3 million during 2008, 2007 and 2006, respectively, based on the Company’s weighted average cost of borrowings used to finance the expenditures. The increases in capitalized interest since 2006 reflect an increase in the Company’s unevaluated costs primarily related to lease acquisition, seismic and drilling activities, along with the overall increased level of capital investments.

In addition to capitalized interest, the Company also capitalized internal costs of $82.4 million, $58.9 million and $44.1 million during 2008, 2007 and 2006, 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. The increases in internal costs capitalized since 2006 have resulted from the addition of personnel and related costs in Southwestern’s exploration and development segment.

The table of capitalized costs incurred above does not include amounts incurred for the acquisition of drilling rigs and related equipment, most of which has been sold and leased back.

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The following table shows the capitalized costs of gas and oil properties and the related accumulated depreciation, depletion and amortization at December 31, 2008 and 2007:


	2008	2007
	(in thousands)

Proved properties	$ 4,295,449	$ 3,648,029
Unproved properties	540,628	372,419

Total capitalized costs	4,836,077	4,020,448
Less: Accumulated depreciation, depletion and amortization	1,548,728	1,158,387
Net capitalized costs	$ 3,287,349	$ 2,862,061

The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2008. Of the total at December 31, 2008, approximately $79.1 million is related to undeveloped leasehold costs in the Company’s Fayetteville Shale play, approximately $124.9 million is related to unevaluated seismic costs in the Fayetteville Shale play and approximately $171.8 million represents costs of wells in progress. Additionally, the Company has $66.6 million of unevaluated costs related to New Ventures. 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. Costs related to wells in progress will be included in the amortization computation in 2009. The timing and amount of the Fayetteville Shale play leasehold 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 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.


	2008	2007	2006	Prior	Total
	(in thousands)

Property acquisition costs	$ 74,502	$ 49,280	$ 23,667	$ 45,008	$ 192,457
Exploration and development costs	226,038	69,787	4,082	1,724	301,631
Capitalized interest	12,254	13,354	6,717	14,215	46,540
	$ 312,794	$ 132,421	$ 34,466	$ 60,947	$ 540,628

(8) NATURAL GAS AND OIL RESERVES (UNAUDITED)

The following table summarizes the changes in the Company’s proved natural gas and oil reserves for 2008, 2007 and 2006:


	2008		2007		2006
	Gas	Oil	Gas	Oil	Gas	Oil
	(MMcf)	(MBbls)	(MMcf)	(MBbls)	(MMcf)	(MBbls)

Proved reserves, beginning of year	1,396,856	8,912	978,934	7,898	772,339	9,079
Revisions of previous estimates	100,230	(355)	30,489	81	(75,420)	(1,870)
Extensions, discoveries and other additions	919,623	93	498,141	1,585	352,734	1,645
Production	(192,265)	(385)	(109,881)	(614)	(68,133)	(698)
Acquisition of reserves in place	—	—	204	—	2,760	22
Disposition of reserves in place	(48,916)	(6,758)	(1,031)	(38)	(5,346)	(280)
Proved reserves, end of year	2,175,528	1,507	1,396,856	8,912	978,934	7,898

Proved developed reserves:
Beginning of year	880,278	7,269	623,870	6,994	551,456	8,309
End of year	1,336,370	1,352	880,278	7,269	623,870	6,994

The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves” (standardized measure) is a disclosure required by Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (FAS 69). The standardized measure does not purport to present the fair market value of a company’s proved gas and oil reserves. In addition, there are uncertainties inherent in estimating quantities of proved reserves. The gas and oil reserve quantities owned by the Company were audited by the independent petroleum engineering firm of Netherland, Sewell & Associates, Inc. (NSA).

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Following is the standardized measure relating to proved gas and oil reserves at December 31, 2008, 2007 and 2006:


	2008	2007	2006
	(in thousands)

Future cash inflows	$11,395,056	$ 9,380,172	$ 5,662,436
Future production costs	(3,115,947)	(2,339,465)	(1,752,482)
Future development costs	(1,491,449)	(1,029,501)	(737,292)
Future income tax expense	(2,178,756)	(1,699,787)	(794,388)
Future net cash flows	4,608,904	4,311,419	2,378,274
10% annual discount for estimated timing of cash flows	(2,499,642)	(2,296,263)	(1,335,519)
Standardized measure of discounted future net cash flows	$ 2,109,262	$ 2,015,156	$ 1,042,755

Under the standardized measure, future cash inflows were estimated by applying year-end prices, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Year-end market prices used for the standardized measures above were $5.71 per Mcf for gas and $41.00 per barrel for oil in 2008, $6.80 per Mcf for gas and $92.50 per barrel for oil in 2007, and $5.64 per Mcf for gas and $57.25 per barrel for oil in 2006. 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. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the standardized measure.

Following is an analysis of changes in the standardized measure during 2008, 2007 and 2006:


	2008	2007	2006
	(in thousands)

Standardized measure, beginning of year	$ 2,015,156	$ 1,042,755	$ 1,420,811
Sales and transfers of gas and oil produced, net of production costs	(1,297,068)	(698,299)	(423,066)
Net changes in prices and production costs	(325,300)	431,780	(711,234)
Extensions, discoveries, and other additions, net of future production and development costs	1,400,044	1,027,946	381,924
Acquisition of reserves in place	—	565	5,106
Sales of reserves in place	(246,223)	(3,906)	(26,618)
Revisions of previous quantity estimates	161,956	59,687	(140,257)
Accretion of discount	259,163	130,872	198,641
Net change in income taxes	(338,661)	(310,500)	299,630
Changes in estimated future development costs	(1,101)	102,760	(69,450)
Previously estimated development costs incurred during the year	178,444	134,149	116,601
Changes in production rates (timing) and other	302,852	97,347	(9,333)
Standardized measure, end of year	$ 2,109,262	$ 2,015,156	$ 1,042,755

(9) DIVESTITURES

In the second quarter of 2008, the Company sold certain oil and gas leases, wells and gathering equipment in its Fayetteville Shale play for $518.3 million. Additionally, the Company sold various oil and 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 gas properties were appropriately credited to the full cost pool.

Effective July 1, 2008, the Company sold all of the capital stock of AWG 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 AWG 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.

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In May 2006, the Company sold its 25% partnership interest in NOARK to Atlas Pipeline Partners, L.P. for $69.0 million and recognized a pre-tax gain of approximately $10.9 million ($6.7 million after tax). The gain on the sale was recorded in other income in the statements of operations.

(10) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate the value:

Cash and Cash Equivalents, and Utility Customer Deposits: The carrying amount is a reasonable estimate of fair value.

Debt: The fair values of the Company’s 7.5% Senior Notes due 2018, 7.21% Senior Notes due 2017 and Senior Notes due 2018 were based on the year-end yield of the Company’s publicly traded debt. The Company’s 7.5% Senior Notes due 2018 were publicly traded at a yield of 9.638% at the end of 2008. The fair value of the Company’s 7.625% Senior Notes due 2027 and putable in 2009 was based on the year-end borrowing rate for companies with a Standard and Poor’s debt rating of BB+, which is the Company’s current debt rating. For 2007, the fair value of the Company’s long-term debt was estimated based on the expected current rates which would have been offered to the Company for debt of the same maturity.

Commodity Hedges: The fair value of all hedging financial 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.

The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2008 and 2007 were as follows:


	2008		2007
	Carrying	Fair	Carrying	Fair
	Amount	Value	Amount	Value
	(in thousands)

Cash and cash equivalents	$ 196,277	$ 196,277	$ 1,832	$ 1,832
Utility customer deposits	$ —	$ —	$ 7,551	$ 7,551
Total debt	$ 735,400	$ 648,616	$ 978,800	$ 976,432
Commodity hedges	$ 421,410	$ 421,410	$ 45,994	$ 45,994

Derivatives and Risk Management

The Company enters into various types of derivative instruments for a portion of its projected gas and oil sales to reduce its exposure to market price volatility for natural gas and oil. The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy entities at the time the transactions are entered into and continually 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 recent events in the financial markets demonstrate there can be no assurance that a counterparty financial institution will be able to meet its obligations to the Company. The Company has not incurred any credit-related losses in 2008 associated with its derivative activities and believes that its counterparties will continue to be able to meet their obligations under these transactions.

At December 31, 2008, our gas derivative instruments consisted of price swaps, costless collars and basis swaps. Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133), as amended (see Note 11 below regarding the adoption of FAS 157 in the first quarter of 2008), requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at its fair value. Accounting for qualifying hedges allows a derivative's gains and losses to be recorded as a component of other comprehensive income. Hedges that are not elected for hedge accounting treatment or that do not meet the requirements of FAS 133 cannot be recorded as a component of other comprehensive income.

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As of December 31, 2008, derivative instruments utilized by the Company included price swaps, costless collars and basis swaps that are defined as follows:

For fixed-price swaps, the Company receives a fixed price for the contract and pays a floating market price to the counterparty.

For floating-price swaps, the Company receives a floating market price from the counterparty and pays a fixed price.

Costless-collars contain a fixed floor price (put) and 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 are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, 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.

Substantially all of the Company’s gas and oil derivative instruments that are not basis related are settled based upon NYMEX prices. Substantially all of the Company’s derivative instruments that are basis related are settled based upon “Inside FERC” published prices for the particular locational basis that is traded. The estimated fair value of these derivative instruments are based upon various market factors.

At December 31, 2008, the Company recorded hedging assets of $437.7 million and hedging liabilities of $16.8 million. Additionally, at December 31, 2008, the Company recorded a gain to other comprehensive income of $258.9 million related to its hedging activities net of a deferred income tax liability of $158.7 million. The amount recorded in other comprehensive income will be relieved over time and taken to the income statement as the physical transactions being hedged occur. At December 31, 2007, the Company recorded hedging assets of $71.5 million, hedging liabilities of $23.8 million as well as a regulatory asset and corresponding current liability of $2.4 million related to its utility gas purchase hedges. At December 31, 2007, the Company recorded a gain to other comprehensive income of $24.6 million related to its hedging activities net of a deferred income tax liability of $15.1 million. The change in accumulated other comprehensive income related to derivatives was a gain of $377.8 million ($234.3 million after tax) for the year ended December 31, 2008, a loss of $26.6 million ($16.8 million after tax) for the year ended December 31, 2007, and a gain of $224.2 million ($141.2 million after tax) for the year ended December 31, 2006. Assuming the market prices of gas futures as of December 31, 2008 remain unchanged, the Company would expect to transfer an aggregate after-tax gain of approximately $205.4 million from accumulated other comprehensive income to earnings during the next 12 months when the transactions actually close. All transactions hedged as of December 31, 2008, are expected to mature by March 31, 2011. Gains or losses from derivative transactions are reflected as adjustments to gas and oil sales on the consolidated statements of operations. Gas and oil sales included a realized loss from settled contracts of $31.6 million in 2008, compared to a realized gain of $70.5 million in 2007 and a realized gain of $14.3 million in 2006. Additional volatility in earnings and other comprehensive income may occur in the future as a result of the application of FAS 133.

Cash Flow Hedges

For cash flow hedges, all derivative instruments are reported as either a hedging asset or hedging liability on the balance sheet and are measured at fair value. The reporting of gains and losses on derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gain or loss on the derivative hedging instrument is recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gains and losses from hedges is recognized in earnings immediately. The Company recorded a loss on the change in ineffectiveness of $7.0 million in 2008, compared to gains of $1.1 million and $20.2 million in 2007 and 2006, respectively.

For those contracts designated as cash flow hedges, the Company formally documents all relationships between the derivative instruments and the commodity being hedged, as well as its risk management objective and strategy for the particular derivative contracts as required by FAS 133.

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Other Derivative Contracts

Although the Company’s basis swaps meet the objectives to manage our commodity price exposure, these trades are typically entered into at different times than our instruments that qualify as cash flow hedges and thus do not qualify for hedge accounting under FAS 133. Basis swap trades are recorded on the balance sheet at their fair values under hedging assets and hedging liabilities, and all realized and unrealized gains and losses related to these contracts are recognized immediately in the statement of operations as a component of gas sales. As of December 31, 2008 and 2007, the fair values of the basis swaps that do not meet the requirements of FAS 133 hedges were a $1.7 million asset and a $0.7 million liability, respectively. The unrealized gain included in gas and oil sales for non-qualifying basis swaps was $2.5 million in 2008, compared to an unrealized gain of $6.0 million in 2007 and an unrealized loss of $25.8 million in 2006.

Hedge Position

At December 31, 2008, the Company had outstanding natural gas price swaps on total notional volumes of 77.3 Bcf in 2009 and 36.0 Bcf in 2010 for which the Company will receive fixed prices ranging from $7.29 to $14.27 per MMBtu. At December 31, 2008, the Company also had outstanding fair value hedges on total notional volumes of 0.7 Bcf in 2009 and 0.2 in 2010 for which the Company will pay an average fixed price of $9.10 per MMBtu. At December 31, 2008, the Company had outstanding fixed price basis differential swaps on 50.0 Bcf of 2009, 32.0 Bcf of 2010 and 7.2 Bcf of 2011 gas production that did not qualify for hedge treatment.

At December 31, 2008, the Company had collars in place on notional volumes of 59.0 Bcf in 2009 and 14.0 Bcf in 2010. The 59.0 Bcf in 2009 had an average floor and ceiling price of $8.71 and $11.69 per MMBtu, respectively. The 14.0 Bcf in 2010 had an average floor and ceiling price of $8.29 and $10.57 per MMBtu, respectively. The Company’s price risk management activities reduced revenues by $40.5 million in 2008 and increased revenues by $70.7 million in 2007 and $8.7 million in 2006.

The primary market risks related to the Company’s derivative contracts are the volatility in commodity prices, basis differentials and interest rates. However, these market risks are offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of oil that is hedged, and payment of variable rate interest. Credit risk relates to the risk of loss as a result of non-performance by the Company’s counterparties. The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy entities at the time the transactions are entered into and continually 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 recent events in the financial markets demonstrate there can be no assurance that a counterparty financial institution will be able to meet its obligations to the Company. The Company has not incurred any credit-related losses in 2008 associated with its derivative activities and believes that its counterparties will continue to be able to meet their obligations under these transactions.

(11) FAIR VALUE MEASUREMENTS

Effective January 1, 2008, the Company adopted Statement of Financial Accounting Standards No. 157, "Fair Value Measurements" (FAS 157), which defines fair value, provides a framework for measuring fair value under generally accepted accounting principles (GAAP) and expands required disclosures about fair value measurements. The Company also adopted Statement of Financial Accounting Standards No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities" (FAS 159), on January 1, 2008, which allows an entity the irrevocable option to elect fair value for the initial and subsequent measurement for certain financial assets and liabilities on a contract-by-contract basis. The Company does not plan to elect to use the fair value option under FAS 159 for any of its financial instruments that are not currently measured at fair value.

FAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels. Level 1 valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority. Level 2 fair value valuations rely on quoted market information for the calculation of fair market value. Level 3 valuations are internal estimates and have the lowest priority. Pursuant to FAS 157, the Company has classified its derivatives into these levels depending upon the data relied on to determine the fair values. The Company’s natural gas swaps are estimated using internal discounted cash flow calculations using the NYMEX futures index and are designated as Level 2. The fair values of collars and natural gas basis swaps are estimated using internal discounted cash flow calculations based upon forward

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commodity price curves or quotes obtained from counterparties to the agreements and are designated as Level 3. Assets and liabilities measured at fair value on a recurring basis are summarized below:


	December 31, 2008
	(in thousands)

	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	$ —	$ 239,436	$ 198,279	$ 437,715
Derivative liabilities	—	(1,377)	(15,456)	(16,833)
Total	$ —	$ 238,059	$ 182,823	$ 420,882

The tables below present reconciliations for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during 2008. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the tables consist of net derivatives valued using pricing models incorporating assumptions that, in management’s judgment, reflect the assumptions a marketplace participant would have used at December 31, 2008.


Total Gains and Losses for the year ended December 31, 2008 (Level 3 Only)
	Net Derivatives
	(in thousands)
Balance at January 1, 2008	$ 32,767
Total gains or losses (realized/unrealized):
Included in earnings⁽¹⁾	58,143
Included in accumulated other comprehensive income (loss)	152,778
Purchases, issuances, and settlements	(60,865)
Transfers into/out of Level 3	—
Balance at December 31, 2008	$ 182,823

Change in unrealized gains (losses) included in earnings relating to derivatives still held as of December 31, 2008	$ (2,722)

(1) Reported in gas sales revenue in the consolidated statements of operations.

(12) STOCK BASED COMPENSATION

The Southwestern Energy Company 2004 Stock Incentive Plan (2004 Plan) was adopted in February 2004 and approved by stockholders in May 2004. The 2004 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2004 Plan replaced the Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan) and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (2002 Plan) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The Company also has awards outstanding under the Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors (1993 Director Plan). 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.

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The 1993 Director Plan, as amended, provided for stock option grants to non-employee directors up to an aggregate of 240,000 shares. The Company has also awarded stock option grants outside the various stock incentive plans to certain non-officer employees and to certain officers at the time of their hire.

The Company may utilize treasury shares, if available, or use authorized but unissued shares when a stock option is exercised or when restricted stock is granted.

On January 1, 2006, the Company adopted Statement on Financial Accounting Standards No. 123R “Share-Based Payment” (FAS 123R), which requires companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. The Company has elected to use the modified prospective application method such that FAS 123R applies to new awards, the unvested portion of existing awards and to awards modified, repurchased or canceled after the effective date. The Company has equity incentive plans that provide for the issuance of stock options and restricted stock. 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. In the fourth quarter of 2005, the Board of Directors prospectively revised the vesting for restricted stock and stock options granted to participants on or after December 8, 2005, under the 2004 Plan to immediately accelerate vesting upon death, disability or retirement (subject to a minimum of five years of service). This change did not affect awards issued prior to December 8, 2005.

Stock Options

For the years ended December 31, 2008, 2007 and 2006, the Company recorded compensation cost of $3.6 million, $2.7 million and $3.1 million, respectively, in general and administrative expense related to stock options. Additional amounts of $1.1 million, $0.7 million and $0.5 million for the same respective periods were directly related to the acquisition, exploration and development activities for the Company’s gas and oil properties and were capitalized into the full cost pool. The Company also recorded a deferred tax benefit of $1.2 million related to stock options in 2008, compared to deferred tax benefits of $0.6 million in 2007 and $1.1 million in 2006. A total of $11.8 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 2.3 years.

The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on exercise of stock options, post vesting forfeitures and other factors to estimate the expected term of the share-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	2008	2007	2006
Risk-free interest rate	2.0%	3.5%	4.5%
Expected dividend yield	—	—	—
Expected volatility	57.0%	41.3%	42.7%
Expected term	5 years	5 years	5 years

The following tables summarize stock option activity for the years 2008, 2007 and 2006 and provide information for options outstanding at December 31 of such years. The number of options and exercise prices have been restated, as necessary, to reflect the two-for-one stock split effected on March 25, 2008:


	2008		2007		2006
		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	8,552,874	$ 4.81	11,584,480	$ 3.10	14,252,930	$ 2.17
Granted	594,870	31.67	406,440	27.12	442,660	20.34
Exercised	(1,690,446)	2.07	(3,414,046)	1.60	(3,099,358)	1.25
Forfeited or expired	(60,761)	24.72	(24,000)	10.46	(11,752)	12.20
Options outstanding at December 31	7,396,537	$ 7.44	8,552,874	$ 4.81	11,584,480	$ 3.10

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	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, 2008	Price	(Years)	(in thousands)	December 31, 2008	Price	(Years)	(in thousands)

$0.75 - $1.00	2,042,464	$ 0.92	1.8		2,042,464	$ 0.92	1.8
$1.01 - $2.50	1,813,238	1.39	3.4		1,813,238	1.39	3.4
$2.51 - $16.75	1,826,932	4.09	4.0		1,826,932	4.09	4.0
$16.76 - $30.00	1,138,033	21.83	4.7		764,044	20.34	4.3
$30.01 - $44.34	575,870	31.80	6.9		—	—	—
	7,396,537	$ 7.44	3.6	$ 159,270	6,446,678	$ 4.25	3.2	$ 159,368

The weighted-average grant-date fair value of options granted during the years 2008, 2007 and 2006 was $15.82, $11.16 and $8.93, respectively. The total intrinsic value of options exercised during 2008, 2007 and 2006 was $60.0 million, $69.9 million and $49.0 million, respectively. Cash received from option exercises was $3.5 million during 2008, $5.5 million during 2007 and $3.9 million during 2006. Associated with the exercise of stock options for 2008, the Company recorded a tax benefit of $43.1 million. The Company recorded a tax benefit of $14.6 million associated with the exercise of stock options in 2006. The tax benefits were recorded as increases in additional paid-in capital.

Restricted Stock

For the years ended December 31, 2008, 2007 and 2006, the Company recorded compensation cost of $4.0 million, $2.7 million and $2.1 million, respectively, in general and administrative expense related to restricted stock grants. Additional amounts of $2.8 million, $1.9 million and $1.2 million for the same respective periods were directly related to the acquisition, exploration and development activities for the Company’s gas and oil properties and were capitalized into the full cost pool. The Company also recorded a deferred tax liability of $3.5 million related to restricted stock for the year ended December 31, 2008, compared to deferred tax liabilities of $1.1 million for 2007 and $1.6 million for 2006. As of December 31, 2008, there was $20.1 million of total unrecognized compensation cost related to nonvested shares of restricted stock that is expected to be recognized over a weighted-average period of 3.0 years.

The following table summarizes the restricted stock activity for the years 2008, 2007 and 2006 and provides information for restricted stock outstanding at December 31, 2008. The number of shares and the grant date fair values have been restated, as necessary, to reflect the two-for-one stock split effected on March 25, 2008:


	2008		2007		2006
		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	791,030	$ 19.89	957,464	$ 12.65	1,414,284	$ 5.57
Granted	417,320	33.50	306,430	25.33	384,130	19.91
Vested	(299,141)	15.65	(422,978)	8.05	(792,804)	3.75
Forfeited	(65,779)	25.93	(49,886)	14.58	(48,146)	9.04
Unvested shares at December 31	843,430	$ 27.66	791,030	$ 19.89	957,464	$ 12.65

The fair values of the grants were $14.0 million for 2008, $7.8 million for 2007 and $7.6 million for 2006. The total fair value of shares vested were $9.3 million for 2008, $11.3 million for 2007 and $15.9 million for 2006.

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(13) COMMON STOCK PURCHASE RIGHTS

In 1999, the Company’s Common Share Purchase Rights Plan was amended and extended for an additional ten years. Under the terms of the amended plan, one common share purchase right is attached to each outstanding share of the Company’s common stock. Each right entitles the holder to purchase one share of common stock at an exercise price of $5.00, subject to adjustment. These rights will become exercisable in the event that a person or group acquires or commences a tender or exchange offer for 15% or more of the Company’s outstanding shares or the Board determines that a holder of 10% or more of the Company's outstanding shares presents a threat to the best interests of the Company. At no time will these rights have any voting power.

If any person or entity actually acquires 15% of the common stock (10% or more if the Board determines such acquiror is adverse), rightholders (other than the 15% or 10% stockholder) will be entitled to buy, at the right's then current exercise price, the Company’s common stock with a market value of twice the exercise price. Similarly, if the Company is acquired in a merger or other business combination, each right will entitle its holder to purchase, at the right’s then current exercise price, a number of the surviving company’s common shares having a market value at that time of twice the right's exercise price.

The rights may be redeemed by the Board for $0.00125 per right or exchanged for shares of common stock on a one-for-one basis prior to the time that they become exercisable. In the event, however, that redemption of the rights is considered in connection with a proposed acquisition of the Company, the Board may redeem the rights only on the recommendation of its independent directors (non-management directors who are not affiliated with the proposed acquiror).

(14) CONTINGENCIES AND COMMITMENTS

Operating Commitments and Contingencies

Pursuant to the precedent agreement with Texas Gas Transmission, LLC (Texas Gas), a subsidiary of Boardwalk Pipeline Partners, LP, in the third quarter of 2008, SES entered into firm transportation agreements with Texas Gas relating to its commitments for the Fayetteville and Greenville Laterals. SES’ options to increase the volumes to be transported on each of the laterals were fully exercised in 2008 and 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. The Company has guaranteed a portion of SES’ obligations under the firm transportation agreements with Texas Gas. The Company’s payment obligations under the guaranty are limited to the lesser of (i) 25% of SES’ negotiated demand charges for the full term of the agreement(s), less any payments made by the Company pursuant to the guaranty, or (ii) 25% of SES’ negotiated demand charges for the remaining initial terms of the agreement(s) as of the first day of the month of services under the agreements for which payment is claimed, which amount shall reflect any reductions in SES’ obligations under the agreements.

In September 2008, SES entered into a precedent agreement pursuant to which it will contract for firm gas transportation services on a proposed new pipeline of Fayetteville Express Pipeline LLC (FEP), which is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P. SES will be a “foundation shipper” for the project and will use the new pipeline primarily to deliver gas volumes produced from the Company’s operations in the Fayetteville Shale play in central Arkansas to eastern markets. Pending regulatory approvals, the pipeline is expected to have an estimated ultimate capacity of up to 2.0 Bcf per day and to be in-service by late 2010 or early 2011. Following the approval of the pipeline by the Federal Energy Regulatory Commission (FERC) and subject to certain conditions, pursuant to the precedent agreement, SES will enter into a firm transportation agreement to transport up to 1,200,000 Dekatherms per day for an initial term of ten years. In connection with the precedent agreement, the Company delivered to FEP a guaranty of SES’ obligations under the precedent agreement and the firm transportation agreements to be entered into thereunder. Initially, and during any period in which SES meets the creditworthiness requirements of the precedent agreement, the Company’s payment obligations under the guaranty are zero but will increase upon the occurrence of certain events.

In the fourth quarter of 2008, one of the Company’s gathering subsidiaries, DeSoto Gathering Company, L.L.C. (DGC), entered into agreements with financial institutions in contemplation of leasing up to 50 compression units pursuant to which those institutions were assigned $61.7 million of DGC’s purchase obligations for the units and provided advances for payment of those obligations. At December 31, 2008, the financial institutions had advanced $20.7 million with respect to the purchase obligations and DGC will pay interest on the advanced amounts until the leases commence. The commencement of the leases is contingent upon certain criteria including, but not limited to, the delivery of the compressors. If the leases do not commence, the Company must repay all advances and the purchase obligations for the compression units revert back to the Company. The Company expects to begin receiving the units in the first quarter of

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2009, with all of the units expected to be delivered by the end of 2009. Aggregate rental payments, including interim interest, are expected to total approximately $60.1 million over the terms of the leases, which will vary between seven and eight years. In addition, the Company has guaranteed DGC’s obligations under the advances and the anticipated leases subject to an aggregate cap of $100 million.

The Company’s E&P and Midstream Services segments have commitments to third parties for demand transportation charges. At December 31, 2008, future payments under non-cancelable demand charges for the Company’s E&P and Midstream Services segments are approximately $72,878,000 in 2009, $101,363,000 in 2010, $91,194,000 in 2011, $84,169,000 in 2012, $84,169,000 in 2013 and $458,656,000 thereafter.

Southwestern leases drilling rigs and equipment for its E&P operations under leases that expire on January 1, 2015. In accordance with the Company’s accounting procedures, the lease payments for the drilling rigs, as well as other operating expenses for the Company’s drilling operations, are capitalized to the full cost pool and are partially offset by billings to third-party working interest owners for their share of rig day-rate charges. The Company’s current aggregate annual rental payment under the leases is approximately $19.4 million.

The Company has commitments for compression services related to its Midstream Services and E&P operations. At December 31, 2008, future minimum payments under these non-cancelable agreements are approximately $26,413,000 in 2009, $24,780,000 in 2010, $21,492,000 in 2011, $14,075,000 in 2012 and $5,315,000 in 2013. The Company also leases compressors, aircraft, office space and equipment under non-cancelable operating leases expiring through 2018. At December 31, 2008, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $15,398,000 in 2009, $13,287,000 in 2010, $10,999,000 in 2011, $9,977,000 in 2012, $7,379,000 in 2013 and $14,602,000 thereafter.

At December 31, 2008, the Company had purchase obligations consisting of outstanding purchase orders under existing agreements for approximately $101.4 million. Included in this amount are $81.5 million of purchase obligations relating to compression units for the Company’s Midstream Services segment, $61.7 million of which have been assigned to financial institutions in connection with anticipated lease arrangements.

Environmental Risk

The Company is subject to laws and regulations relating to the protection of the environment. The Company's 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 the financial position or reported results of operations of the Company.

Litigation

The Company is subject to 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 or the financial position of the Company.

(15) SEGMENT INFORMATION

The Company applies Statement of Financial Accounting Standards No. 131, “Disclosures About Segments of an Enterprise and Related Information” (FAS 131). 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. Gathering revenues are expected to increase in the future as the level of production from our Fayetteville Shale properties continues to increase. Revenues for the Natural Gas Distribution segment arise from the transportation and sale of natural gas at retail by AWG. As a result of the closing of the sale of AWG on July 1, 2008, the Company no longer has any natural gas distribution operations.

Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs and expenses. Income before income taxes is the sum of operating income, interest expense, interest and other income (loss), gain on sale of utility assets

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and minority interest in partnership. The "Other" column includes items not related to the Company's reportable segments including real estate and corporate items.


	Exploration			Natural
	And		Midstream	Gas
	Production		Services	Distribution	Other		Total
	(in thousands)
2008
Revenues from external customers	$1,424,439		$ 771,915	$ 114,957	$ 241		$2,311,552
Intersegment revenues	66,863		1,402,056	2,753	448		1,472,120
Operating income	813,504		62,349	10,733	182		886,768
Interest and other income (loss)⁽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	⁽⁴⁾	519,258	—	290,887	⁽²⁾	4,760,158
Capital investments⁽³⁾	1,595,828		183,021	3,574	13,745		1,796,168

2007
Revenues from external customers	$ 752,720		$ 328,609	$ 173,802	$ —		$ 1,255,131
Intersegment revenues	43,224		633,385	664	448		677,721
Operating income	358,079		13,236	9,960	191		381,466
Interest and other income (loss)⁽¹⁾	382		(3)	(601)	3		(219)
Depreciation, depletion and amortization expense	281,910		5,524	6,319	161		293,914
Interest expense⁽¹⁾	16,926		2,006	4,941	—		23,873
Provision for income taxes⁽¹⁾	129,315		4,294	1,672	574		135,855
Assets	3,088,219	⁽⁴⁾	274,305	202,111	58,081	⁽²⁾	3,622,716
Capital investments⁽³⁾	1,379,657		107,363	11,375	4,743		1,503,138

2006
Revenues from external customers	$ 452,887		$ 138,251	$ 171,974	$ —		$ 763,112
Intersegment revenues	38,658		336,956	233	448		376,295
Operating income	237,307		4,111	4,474	380		246,272
Interest and other income (loss)⁽¹⁾	6,271		(581)	(415)	11,804		17,079
Depreciation, depletion and amortization expense	143,101		1,772	6,325	92		151,290
Interest expense⁽¹⁾	508		—	171	—		679
Provision for income taxes⁽¹⁾	91,276		554	1,698	5,871		99,399
Assets	1,965,247	⁽⁴⁾	112,027	206,919	94,876	⁽²⁾	2,379,069
Capital investments⁽³⁾	861,041		48,660	11,232	21,474		942,407

⁽¹⁾ Interest income, interest expense and the provision 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⁾ Other assets include the Company’s investment in cash equivalents for 2008 and 2006, corporate assets not allocated to segments and assets for non-reportable segments.

⁽³⁾ Capital investments include an increase of $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.

⁽⁴⁾ Includes capital investments for office, technology, drilling rigs and other ancillary equipment not directly related to gas and oil property acquisition, exploration and development activities, as defined by FAS 69.

Included in intersegment revenues of the Midstream Services segment are $1.3 billion, $559.5 million and $284.9 million for 2008, 2007 and 2006, respectively, for marketing of the Company’s E&P sales. Intersegment sales by the E&P segment and Midstream Services segment to the Natural Gas Distribution segment are priced in accordance with terms of existing contracts and current market conditions. Parent company assets include cash and cash equivalents, furniture and fixtures, prepaid debt and other costs. Parent company general and administrative costs, depreciation expense and taxes other than income are allocated to segments. All of the Company's operations are located within the United States.

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(16) QUARTERLY RESULTS (UNAUDITED)

The following is a summary of the quarterly results of operations for the years ended December 31, 2008 and 2007:


	Mar 31	June 30	Sept 30		Dec 31
	(in thousands, except per share amounts)

	2008

Operating revenues	$ 524,106	$ 604,370	$ 682,999		$ 500,077
Operating income	187,510	229,286	299,040		170,932
Net income	109,029	136,550	218,168	⁽¹⁾	104,199
Basic earnings per share	0.32	0.40	0.64	⁽¹⁾	0.30
Diluted earnings per share	0.31	0.39	0.63	⁽¹⁾	0.30

	2007

Operating revenues	$ 284,652	$ 270,082	$ 297,622		$ 402,775
Operating income	83,759	82,006	89,453		126,248
Net income	50,988	47,594	50,960		71,632
Basic earnings per share⁽²⁾	0.15	0.14	0.15		0.21
Diluted earnings per share⁽²⁾	0.15	0.14	0.15		0.21

(1) Includes an after-tax gain on the sale of the Company’s utility segment of $35.4 million, or $0.10 per basic and diluted earnings per share.

(2) Restated to reflect the two-for-one stock split effected in March 2008.

(17) NEW ACCOUNTING STANDARDS

During the first quarter of 2008, the Company adopted Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This statement applies to other accounting pronouncements that require or permit fair value measurements, and is effective for financial statements issued for fiscal years beginning after November 15, 2007. In addition to required disclosures, FAS 157 also requires companies to evaluate current measurement techniques. The adoption of FAS 157 had no material impact on the Company’s results of operations and financial condition.

During the first quarter of 2008, the Company adopted Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (FAS 159). FAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value and applies to other accounting pronouncements that require or permit fair value measurements. FAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of FAS 159 had no impact on the Company’s results of operations and financial condition.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB No. 51” (FAS 160). FAS 160 will change the financial accounting and reporting of noncontrolling (or minority) interests in consolidated financial statements, and is effective for financial statements issued for fiscal years beginning after December 15, 2008. FAS 160 will impact the presentation of the Company’s balance sheet line item “Minority Interest” related to its Overton partnership, a partnership formed by SEPCO with an investor to drill and complete 14 wells in the Overton Field in East Texas, but is expected to have no impact on its results of operations and financial condition.

In February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”). FSP FAS 157-2 delays the effective date of FAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). FSP FAS 157-2 is effective for the Company’s fiscal year beginning January 1, 2009. The adoption of FSP FAS 157-2 is not expected to have a material impact on the Company’s results of operations and financial condition.

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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, 2008. There were no changes in our internal control over financial reporting during the three months ended December 31, 2008, 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 58 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, 2008, that was not reported on such form.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 19, 2009, or the 2009 Proxy Statement, is hereby incorporated by reference for the purpose of providing information about the identification of 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 2009 Proxy Statement for information concerning our directors. We refer you to the section “Corporate Governance – Committees of the Board of Directors” 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” 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 2009 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 2009 Proxy Statement.

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

The 2009 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 2009 Proxy Statement. Refer to the sections “Security Ownership of Certain Beneficial Owners” and “Share Ownership of Management, Directors and Nominees” in our 2009 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 2009 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 2009 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 2009 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.

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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.

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 26, 2009

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 26, 2009.



/s/ Harold M. Korell	Director, Chairman and Chief Executive Officer
Harold M. Korell

/s/ Greg D. Kerley	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

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EXHIBIT INDEX


Exhibit Number	Description
3.1	Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
3.2	Bylaws of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.2 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
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	Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First National Bank of Chicago (now J.P. Morgan Chase Bank). (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)
4.3	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)
4.4	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, 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)
4.5	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)
4.6	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 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)
4.7	Second Supplemental Indenture between Southwestern Energy Company and UMB Bank, N.A. as successor to the Bank of New York 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)
4.8	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)
4.9	Amended and Restated Rights Agreement between Southwestern Energy Company and the First Chicago Trust Company of New York dated April 12, 1999. (Incorporated by reference to Exhibit 4.1 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1999)
4.10	Amendment No. 1 to the Amended and Restated Rights Agreement between Southwestern Energy Company and Equiserve Trust Company as successor to the First Chicago Trust Company of New York dated March 15, 2002. (Incorporated by reference to Exhibit 4.1 to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2001)
4.11	Amendment No. 2 to the Amended and Restated Rights Agreement between Southwestern Energy Company and Computershare Trust Company, N.A. as successor to the First National Bank of Chicago dated June 30, 2006. (Incorporated by reference to Exhibit 4.5 to the Registrant's Current Report on Form 8-K/A filed August 3, 2006)
4.12	Guaranty dated June 1, 1998 by Southwestern Energy Company in favor of The Bank of New York, as trustee (the “Trustee”), under the Indenture dated as of June 1, 1998 between NOARK Pipeline Finance L.L.C. and the Trustee. (Incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report filed on Form 10-K (Commission file No. 1-08246) for the year ended December 31, 2005)

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4.13	Second Amended and Restated Credit Agreement dated February 9, 2007 among Southwestern Energy Company, JPMorgan Chase Bank, NA, SunTrust Bank, The Royal Bank of Scotland PLC, Royal Bank of Canada, Bank of America, N.A., and the other lenders named therein, JPMorgan Chase Bank, NA, as administrative agent, SunTrust Bank as syndication agent. (Incorporated by reference to Exhibit 4.11 to the Registrant’s Annual Report on Form 10-K filed on March 1, 2007)
4.14	First Amendment dated October 12, 2007 to Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as Administrative Agent, and a lender under the facility, SunTrust Bank as Syndication Agent, Bank of America, N.A., Royal Bank of Canada and Royal Bank of Scotland plc dated February 9, 2007. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2007)
4.15	Second Amendment to Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as Administrative Agent, and a lender under the facility, SunTrust Bank as Syndication Agent, Bank of America, N.A., Royal Bank of Canada and Royal Bank of Scotland plc dated February 9, 2007. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2008)
4.16	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)
4.17	Form of the Notes (included as an exhibit to the Indenture incorporated by reference as Exhibit 4.16 to this Form 10-K).
4.18	Registration Rights Agreement by and between Southwestern Energy Company and J.P. Morgan Securities Inc., acting as representative of the initial purchasers dated January 16, 2008. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed January 17, 2008)
4.19	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)
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.
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.
10.6	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)
10.7	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)

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10.8	Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors, dated April 7, 1993. (Incorporated by reference to Exhibit 10.4(f) to the Registrant's Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1993)
10.9	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)
10.10	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)
10.11*	Southwestern Energy Company 2002 Performance Unit Plan, as amended, effective December 31, 2008.
10.12	Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)
10.13	Form of Incentive Stock Option Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.14	Form of Restricted Stock Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
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	Form of Restricted Stock Agreement for Special Incentives. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 14, 2006)
10.20	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)
10.21	Separation Agreement between Richard F. Lane and Southwestern Energy Company, effective as of September 3, 2008 (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on September 3, 2008).
10.22	Consulting Agreement between Richard F. Lane and Southwestern Energy Company, effective as of September 3, 2008 (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on September 3, 2008).
10.23	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)
10.24*	Amended and Restated Project Services Agreement by and between SEECO, Inc., a wholly-owned subsidiary of Southwestern Energy Company, and Schlumberger Technology Corporation dated February 16, 2009.

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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.

____________

*Filed herewith

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