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, 2009

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesx   Noo   

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o 

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

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

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

The aggregate market value of the voting stock held by non-affiliates of the registrant was $13,121,603,390 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2009, of $38.85. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.

As of February 23, 2010, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 346,087,780.

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 18, 2010 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, 2009

TABLE OF CONTENTS

                      Page

PART I

Item 1.

Business

3

Glossary of Certain Industry Terms

20

Item 1A.

Risk Factors

25

Item 1B.

Unresolved Staff Comments

35

Item 2.

Properties

36

Item 3.

Legal Proceedings

39

Item 4.

Submission of Matters to a Vote of Security Holders

39

Executive Officers of the Registrant

39

PART II

Item 5.

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

40

Stock Performance Graph

41

Item 6.

Selected Financial Data

42

Item 7.

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

Overview

44

Results of Operations

46

Liquidity and Capital Resources

51

Critical Accounting Policies and Estimates

55

Cautionary Statement about Forward-Looking Statements

60

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

62

Item 8.

Financial Statements and Supplementary Data

64

Index to Consolidated Financial Statements

64

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

105

Item 9A.

Controls and Procedures

105

Item 9B.

Other Information

105

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

105

Item 11.

Executive Compensation

105

Item 12.

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

106

Item 13.

Certain Relationships and Related Transactions, and Director Independence

106

Item 14.

Principal Accounting Fees and Services

106

PART IV

Item 15.

Exhibits, Financial Statement Schedules

106

EXHIBIT INDEX

108

This Annual Report on Form 10-K includes certain statements that may be deemed to be “forward-looking” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. We refer you to “Risk Factors” in Item 1A of Part I and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a discussion of factors that could cause actual results to differ materially from any such forward-looking statements. The electronic version of this Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those forms filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge as soon as reasonably practicable after they are filed with the Securities and Exchange Commission, or SEC, on our website at www.swn.com.  Our corporate governance guidelines and the charters of the Audit, Compensation, Nominating and Governance and Retirement Committees of our Board of Directors are available on our website, and are available in print free of charge to any stockholder upon request.


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Table of Contents

ITEM 1.  BUSINESS

Southwestern Energy Company is an independent energy company engaged in natural gas and crude oil exploration, development and production (E&P). We are also focused on creating and capturing additional value through our 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 an unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, which we refer to as the Fayetteville Shale play.  We are also actively engaged in exploration and production activities in Oklahoma, Texas and Pennsylvania.  We conduct our exploration and production operations through our wholly-owned subsidiaries, SEECO, Inc., or SEECO, and Southwestern Energy Production Company, or SEPCO. SEECO operates exclusively in Arkansas where it holds a large base of both developed and undeveloped gas reserves, and conducts the Fayetteville Shale drilling program and the conventional Arkoma Basin drilling program in the Arkoma Basin. SEPCO conducts development drilling and exploration programs in the Oklahoma portion of the Arkoma Basin as well as in Texas and Pennsylvania.  DeSoto Drilling, Inc., or DDI, a wholly-owned subsidiary of SEPCO, operates drilling rigs in the Fayetteville Shale play and in East Texas.  


Midstream Services - We engage in gas gathering activities in Arkansas and Texas through our gathering subsidiaries, DeSoto Gathering Company, L.L.C., which we refer to as DeSoto Gathering, and Angelina Gathering Company, L.L.C., which we refer to as Angelina Gathering. DeSoto Gathering and Angelina Gathering primarily support our E&P operations and generate revenue from gathering fees associated with the transportation of our and third party gas to market. Our gas marketing subsidiary, Southwestern Energy Services Company, or SES, captures downstream opportunities which arise through marketing and transportation activity of the gas produced in our E&P operations.  


The vast majority of our operating income and earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA, is derived from our E&P business.  In 2009, absent our $907.8 million, or $558.3 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties, 86% of our operating income and 90% of our EBITDA were generated from our E&P business, compared to 92% of our operating income and 89% of our EBITDA in 2008 and 94% of our operating income and 95% of our EBITDA in 2007. In 2009, 14% of our operating income, absent the non-cash ceiling test impairment of our natural gas and oil properties, and 10% of our EBITDA were generated from Midstream Services, compared to 7% of our operating income and 5% of our EBITDA in 2008 and 3% of our operating income and 3% of our EBITDA in 2007. In 2008 and 2007, the remainder of our EBITDA was generated from our Gas Distribution business which was sold effective July 1, 2008.  EBITDA is a non-GAAP measure.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA to net income (loss) attributable to Southwestern Energy.   


Our Business Strategy

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 will continue to provide significant production and reserve growth. We intend to further develop our acreage position and improve our well results through the use of advanced technologies and detailed technical analysis of our properties. During 2009, primarily as a result of the economic recession, natural gas prices fell to their lowest levels over the last 7 years and if natural gas prices rebound in 2010 we could increase our planned investments and accelerate the development of our Fayetteville Shale play by utilizing additional drilling rigs.

·

Maximize Efficiency through Economies of Scale.  In our key operating areas, the concentration of our properties allows us to achieve economies of scale that result in lower costs.  In our Fayetteville Shale play, we have achieved significant cost savings by operating a fleet of drilling rigs designed specifically for the play and from our other associated oilfield services.  We seek to serve as the operator of the wells in which we have a significant interest.  As the operator, we are better positioned to control the enhancing, drilling, completing and producing of wells and the marketing of production to minimize costs and maximize both production volumes and realized price.

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Table of Contents

·

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 have continued to design and improve our gas gathering infrastructure to better manage the physical movement of our production and the costs of our operations.  As of December 31, 2009, we have invested approximately $548.9 million in the 1,137 mile gas gathering system built for our Fayetteville Shale play which was gathering approximately 1.3 Bcf per day at year-end. We intend to invest $270 million in our Midstream operations in 2010 to continue the expansion of our infrastructure.  We have also been proactive in encouraging the construction of interstate pipelines to provide access to increase the markets in which we can sell our production.  Our marketing subsidiary is a “foundation shipper” on two Fayetteville Shale pipeline projects that will provide access to the eastern and southern United States.

·

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 and our Marcellus Shale play began as a New Ventures projects in 2002 and 2007, respectively. As of December 31, 2009, we held 36,125 net undeveloped acres in New Ventures projects. In addition to New Ventures prospects, we also strategically seek to expand existing operations including joint ventures, farm-ins or farm-outs.

Recent Developments

Our planned capital investment program for 2010 is approximately $2.1 billion, which includes approximately $1.7 billion for our E&P segment, $270 million for our Midstream Services segment and $95 million for corporate and other purposes.  Our 2010 capital program is expected to be primarily funded by our cash flow from operations and borrowings under our $1 billion revolving credit facility.  The planned capital program for 2010 is flexible and can be adjusted to reflect market conditions.  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 2010 gas and oil production of approximately 400 to 410 Bcfe, an increase of approximately 35% over our 2009 production (using the midpoint of targeted 2010 gas and oil production).

Exploration and Production

Overview

Our operations are primarily focused on the Fayetteville Shale, an unconventional reservoir located in the Arkoma Basin in Arkansas. We also conduct conventional operations in the Arkoma Basin where we target Atokan-age gas reservoirs. In addition to our Arkansas operations, we conduct both conventional and unconventional operations in East Texas primarily targeting the Cotton Valley, James Lime, Pettet, Haynesville Shale and Middle Bossier formations. We also hold a significant acreage position in northeastern Pennsylvania that we will begin drilling in 2010 targeting the Marcellus Shale. We continue to actively seek to develop both conventional and unconventional natural gas and oil resource plays with significant exploration and exploitation potential.


Our E&P segment recorded an operating loss of $157.7 million in 2009 as a result of the recognition of a $907.8 million, or $558.3 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties recorded for the three months ended March 31, 2009 due to a significant decline in natural gas prices. Our E&P segment recorded operating income of $813.5 million in 2008 and $358.1 million in 2007. The operating loss in 2009 was primarily due to the recognition of this ceiling test impairment, however, even without the write-down, operating income would have decreased, when compared to 2008 operating income, due to lower prices realized from the sale of our production and an increase in operating costs and expenses which more than offset the higher revenues realized from increased gas production.  EBITDA from our E&P segment was $1.2 billion in 2009, compared to $1.2 billion in 2008 and $640.5 million in 2007. Our EBITDA in 2009 was approximately equal to 2008 as the impact of our increased production volumes was offset by decreased prices realized from the sale of our production and increased operating costs and expenses.  The increases in both our operating income and EBITDA in 2008 when compared to 2007 were due to increased production volumes and higher realized prices, partially offset by increases in operating costs and expenses.  EBITDA is a non-GAAP measure. We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a reconciliation of EBITDA to net income (loss) attributable to Southwestern Energy.

 

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Our Proved Reserves

Our estimated proved natural gas and oil reserves were 3,657 Bcfe at year-end 2009, compared to 2,185 Bcfe at year-end 2008 and 1,450 Bcfe at year-end 2007. The overall increase in total estimated proved reserves in the past three years is primarily due to the development of the Fayetteville Shale play in Arkansas. In 2009, the SEC adopted a number of  revisions to its oil and gas reporting disclosure requirements which are effective for this Form 10-K and accordingly, our estimated proved natural gas and oil reserves as of December 31, 2009 were valued utilizing the average prices in the 12-month period, which is defined, with certain exceptions, as the unweighted arithmetic average of the first-day-of-the-month price for each month within such period, of $3.87 per Mcf for natural gas and $57.65 per barrel for oil. The market prices for natural gas and crude oil used in calculating the value of our estimated proved natural gas and oil reserves for 2008 and 2007 were single day prices permitted to be used under the SEC’s prior rules, which were $5.71 per Mcf for natural gas and $41.00 per barrel for oil at year-end 2008 and $6.80 per Mcf and $92.50 per barrel at year-end 2007.


The after-tax PV-10, or standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities, was $1.8 billion at year-end 2009, compared to $2.1 billion at year-end 2008 and $2.0 billion at year-end 2007.  The decrease in the after-tax PV-10 value in 2009 is primarily due to a comparative decrease in the average 2009 price from the year-end 2008 gas price and higher operating and future development costs which were partially offset by an increase in reserves. Our proved reserves are almost entirely natural gas and as such the after-tax PV-10 measure is highly dependent upon the natural gas price used in the after-tax PV-10 calculation. The reconciling difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2009 Proved Reserves by Category and Summary Operating Data table below) is the discounted value of future income taxes on the estimated cash flows.  Our year-end 2009 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pre-tax PV-10, of $2.3 billion, compared to $3.0 billion at year-end 2008 and $2.6 billion at year-end 2007.  


We believe that the pre-tax PV-10 value of the estimated cash flows related to our estimated proved reserves is a useful supplemental disclosure to the after-tax PV-10 value.  While pre-tax PV-10 is based on prices, costs and discount factors that are comparable from company to company, the after-tax PV-10 is dependent on the unique tax situation of each individual company.  We understand that securities analysts use pre-tax PV-10 as one measure of the value of a company’s current proved reserves and to compare relative values among peer companies without regard to income taxes.  We refer you to Note 4 in the consolidated financial statements for a discussion of our standardized measure of discounted future cash flows related to our proved 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 2009 estimated proved reserves were natural gas and 54% were classified as proved developed, compared to 100% and 62%, respectively, in 2008 and 96% and 64%, respectively, in 2007.  We operate approximately 94% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index approximated 12.2 years at year-end 2009.  Sales of natural gas production accounted for nearly 100% of total operating revenues for this segment in 2009, 97% in 2008 and 94% in 2007.


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The following table provides an overall and by category summary of our oil and gas reserves, as of fiscal year-end 2009 based on average fiscal year prices, and our well count, net acreage and PV-10 as of December 31, 2009 and sets forth 2009 annual information related to production and capital investments for each of our operating areas:

                                    2009 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA

 

 

 

U.S. Exploitation

 

 

 

 

 

Fayetteville

 

East

 

Arkoma

 

 

 

New

 

 

 

Shale Play

 

Texas

 

Basin

 

Appalachia

 

Ventures

 

Total

Estimated Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Bcf):


 


 


 


 


 


Developed (Bcf)

 1,501 

 

 280 

 

 190 

 

 2 

 

 - 

 

 1,973 

Undeveloped (Bcf)

 1,616 

 

 43 

 

 18 

 

 - 

 

 - 

 

 1,677 

 

 3,117 

 

 323 

 

 208 

 

 2 

 

 - 

 

 3,650 

Crude Oil (MMBbls):

 

 

 

 

 

 

 

 

 

 

 

Developed (MMBbls)

 - 

 

 1 

 

 - 

 

 - 

 

 - 

 

 

Undeveloped (MMBbls)

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

 

 

 - 

 

 1 

 

 - 

 

 - 

 

 - 

 

 

Total Proved Reserves (Bcfe)(1):

 

 

 

 

 

 

 

 

 

 

 

Proved Developed (Bcfe)

 1,501 

 

 287 

 

 190 

 

 2 

 

 - 

 

 1,980 

Proved Undeveloped (Bcfe)

 1,616 

 

 43 

 

 18 

 

 - 

 

 - 

 

 1,677 

 

 3,117 

 

 330 

 

 208 

 

 2 

 

 - 

 

 3,657 

Percent of Total

 85%

 

 9%

 

 6%

 

 - 

 

 - 

 

 100%

 

 

 

 

 

 

 

 

 

 

 

 

Percent Proved Developed

 48%

 

 87%

 

 91%

 

 100%

 

 - 

 

 54%

    Percent Proved Undeveloped

 52%

 

 13%

 

 9%

 

 - 

 

 - 

 

 46%

 

 

 

 

 

 

 

 

 

 

 

 

Production (Bcfe)

 243.5 

 

 34.9 

 

 22.0 

 

 - 

 

 - 

 

 300.4 

Capital Investments (millions)(2)

$            1,259 

 

$               167 

 

$                 40 

 

$                 40 

 

$                 25 

 

$            1,531 

Total Gross Producing Wells

 1,428 

 

 582 

 

 1,193 

 

 - 

 

 - 

 

 3,203 

Total Net Producing Wells

 993 

 

 449 

 

 583 

 

 - 

 

 - 

 

 2,025 

 

 

 

 

 

 

 

 

 

 

 

 

Total Net Acreage

 763,293(3)

 

 115,199(4)

 

 463,888(5)

 

 149,317(6)

 

 36,125 

 

 1,527,822 

Net Undeveloped Acreage

 394,538(3)

 

 61,298(4)

 

 278,927(5)

 

 149,317(6)

 

 36,125 

 

 920,205 

 

 

 

 

 

 

 

 

 

 

 

 

PV-10:

 

 

 

 

 

 

 

 

 

 

 

Pre-tax (millions)(7)

$            1,857 

 

$               260 

 

$               185 

 

$                   2 

 

$                   - 

 

$            2,304 

PV of taxes (millions)(7)

 405 

 

 57 

 

 40 

 

 - 

 

 - 

 

 502 

After-tax (millions)(7)

$            1,452 

 

$               203 

 

$               145 

 

$                   2 

 

$                   - 

 

$            1,802 

Percent of Total

 81%

 

 11%

 

 8%

 

 - 

 

 - 

 

 100%

Percent Operated(8)

 95%

 

 97%

 

 85%

 

 - 

 

 - 

 

 94%


 (1) We have no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. Our proved reserves increased by 1,685 Bcfe as a result of our drilling program and net upward revisions of 92.9 Bcfe in 2009.  Of the reserve additions, 757.6 Bcfe were proved developed and 927.5 Bcfe were proved undeveloped.  We used standard engineering and geoscience methods, or a combination of methods, such as performance analysis, volumetric analysis and analogy to establish the appropriate level of certainty for reserve estimates from the material properties included in our total reserves.

(2)  Our Total and Fayetteville Shale play capital investments exclude $35 million related to our sand facility and the purchase of drilling rig related and ancillary equipment.

(3)  Assuming successful wells are not drilled and leases are not extended, leasehold expiring over the next three years will be 120,977 net acres in 2010, 23,722 net acres in 2011 and 34,231 net acres in 2012.

(4)  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 21,747 net acres in 2010, 24,594 net acres in 2011 and 2,334 net acres in 2012.

(5)  Includes 123,442 net developed acres and 1,960 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 32,434 net acres in 2010, 34,115 net acres in 2011 and 28,153 net acres in 2012.

(6)  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 1,475 net acres in 2010, 551 net acres in 2011 and 61,133 net acres in 2012.

(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 of proved developed producing properties.

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Table of Contents


We refer you to Note 4 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.

  

Proved Undeveloped Reserves


As of December 31, 2009, we had 1,677 Bcfe of proved undeveloped reserves, none of which were proved undeveloped reserves that remain undeveloped for five years or more after initially being disclosed by us.  During 2009, we invested $19.0 million in connection with converting 120.8 Bcfe of our proved undeveloped reserves as of December 31, 2008 into proved developed reserves and added 927.5 Bcfe of proved undeveloped reserve additions. Our 2009 proved undeveloped reserve additions are expected to be developed and to begin to generate cash inflows over the next five years.

 

The development of our proved undeveloped reserves will require us to make significant additional investments.  We expect that the development costs for our proved undeveloped reserves of 1,677 Bcfe as of December 31, 2009, will require us to invest an additional $2.3 billion in order for those reserves to be brought to production.  Our ability to make the necessary investments to generate these cash inflows is subject to factors that may be beyond our control.  A significant decrease in price levels for an extended period of time could result in certain reserves no longer being economic to produce, leading to both lower proved reserves and cash flows.  We refer you to the risk factors “A substantial or extended decline in natural gas and oil prices would have a material adverse affect on us,” “We may have difficulty financing our planned capital investments, which could adversely affect our growth” and “Our future level of indebtedness and the terms of our financing arrangements may adversely affect operations and limit our growth” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a more detailed discussion of these factors and other risks.


Our Reserve Replacement


The ability of an E&P company to add new reserves to replace the reserves that are being depleted by its current production volumes is viewed by many investors as an indication of its long-term prospects. Reserves additions can be proved developed. The reserve replacement ratio, which we discuss below, is an important analytical measure used within the E&P industry by investors and peers to evaluate performance results.  There are limitations as to the usefulness of this measure as it does not reflect the type of reserves or the cost of adding the reserves or indicate the potential value of the reserve additions.  Our reserve replacement ratio has averaged over 500% during the last three years, primarily driven by increases in the reserves associated with our Fayetteville Shale play.


In 2009, we replaced 592% of our production volumes with an increase of 1,685 Bcfe of proved natural gas and oil reserves as a result of our drilling program and net upward revisions of 92.9 Bcfe.  Of the reserve additions, 757.6 Bcfe were proved developed and 927.5 Bcfe were proved undeveloped. The upward reserve revisions during 2009 were primarily due to 384.8 Bcfe in upward revisions related to the improved performance of wells in our Fayetteville Shale play, partially offset by downward reserve revisions of 251.5 Bcfe due to a comparative decrease in the average gas price for 2009 as compared to year-end 2008.  Additionally, we had downward performance revisions of 25.5 Bcfe and 15.1 Bcfe in our East Texas and conventional Arkoma Basin operating areas, respectively.


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


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For the period ending December 31, 2009, our three-year average reserve replacement ratio, including revisions, was 548%. Our reserve replacement ratio for 2009, excluding the effect of reserve revisions, was 561%, compared to 473% in 2008 and 447% in 2007. Excluding reserve revisions, our three-year average reserve replacement ratio is 512%.


Since 2005, the substantial majority of our reserve additions have been generated from our drilling program in the Fayetteville Shale play.  We expect our drilling program in the Fayetteville Shale play to continue to be the primary source of our reserve additions in the future, however, our ability to add reserves depends upon many factors that are beyond our control.  We refer you to the risk factors “Our drilling plans for the Fayetteville Shale play are subject to change” and “Our exploration, development and drilling efforts and our operation of our wells may not be profitable or achieve our targeted returns” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a more detailed discussion of these factors and other risks.


Our Operations


Fayetteville Shale Play


Our Fayetteville Shale play is currently the primary focus of our E&P business. The Fayetteville Shale is a Mississippian-age unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, ranging in thickness from 50 to 550 feet and ranging in depth from 1,500 to 6,500 feet.  The Barnett Shale found in north Texas is an analogous reservoir.  At December 31, 2009, we held leases for approximately 888,695 net acres in the play area (394,538 net undeveloped acres, 368,755 net developed acres held by Fayetteville Shale production, 123,442 net developed acres held by conventional production and an additional 1,960 net undeveloped acres in the traditional Fairway portion of the Arkoma Basin), compared to approximately 875,000 net acres at year-end 2008 and 906,700 net acres at year-end 2007.  The increase in our acreage during 2009 was primarily due to additional acreage capture related to the integration of new sections and a small acquisition of producing properties in the play.  The slight decrease in our net acreage during 2008 as compared to 2007 was primarily due to the sale of 55,631 acres to XTO Energy, Inc. in April 2008.  

Approximately 3,117 Bcf of our reserves at year-end 2009 were attributable to our Fayetteville Shale play, compared to approximately 1,545 Bcf at year-end 2008 and 716 Bcf at year-end 2007.  Gross production from our operated wells in the Fayetteville Shale play increased from approximately 720 MMcf per day at the beginning of 2009 to approximately 1,225 MMcf per day by year-end.  Our net production from the Fayetteville Shale play was 243.5 Bcf in 2009, compared to 134.5 Bcf in 2008 and 53.5 Bcf in 2007. In 2010, our estimated production from the Fayetteville Shale play is expected to range between 344 and 352 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 2009, approximately 48% 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 acreage position was obtained at an average cost of approximately $203 per acre with an average royalty interest of 15% and the undeveloped portion of our acreage had an average remaining lease term of 3 years.  For more information about our acreage and well count, we refer you to “Properties” in Item 2 of Part I of this Form 10-K.

As of December 31, 2009, we had spud a total of 1,792 wells in the play, 1,437 of which were operated by us and 355 of which were outside-operated wells.  Of the wells spud, 570 were in 2009, 604 were in 2008 and 415 were in 2007.  Of the wells spud in 2009, 565 were designated as horizontal wells.  At year-end 2009, 1,288 wells had been drilled and completed, including 1,201 horizontal wells.  Of the 1,201 horizontal wells, 1,178 wells were fracture stimulated using either slickwater or crosslinked gel stimulation treatments, or a combination thereof.


During 2009, we continued to improve our drilling practices in the Fayetteville Shale play.  Our horizontal wells had an average completed well cost of $2.9 million per well, average horizontal lateral length of 4,100 feet and average time to drill to total depth of 12 days from re-entry to re-entry.  This compares to 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 during 2008.  In 2007, our average completed well cost was $2.9 million per well with an 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.  We also continued to improve our completion practices, as wells placed on production during 2009 averaged initial production rates of 3,478 Mcf per day, compared to average initial production rates of 2,777 and 1,687 Mcf per day in 2008 and 2007, respectively.  Since 2007, improvements in our completion practices and longer lateral lengths have resulted in quarter-

 

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over-quarter improvements in average initial production rates of operated wells placed on production.  During 2009, we placed 60 wells on production with initial production rates that exceeded 5.0 MMcf per day, including six wells that exceeded 6.0 MMcf per day and the play’s highest rate well, the Arklan, Inc. 09-11 #4-32H located in Cleburne County, with an initial production rate of approximately 7.6 MMcf per day.  


Beginning in late 2008 and continuing through 2009, we drilled a significant number of wells to test tighter well spacing. At December 31, 2009, we had placed over 300 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing or less, with encouraging results. In areas tested to date, we expect to drill between 10 and 12 wells per section in the Fayetteville Shale play, pending additional well data and analyses. We will continue to focus on optimizing the well spacing for the play and plan to test over 20 different pilot areas with well spacings that will range from 300 to 600 feet apart as part of our 2010 drilling program.


Our total proved net reserves booked in the play at year-end 2009 were 3,117 Bcf from a total of 2,675 locations, of which 1,428 were proved developed producing, 97 were proved developed non-producing and 1,150 were proved undeveloped.  Of the 2,675 locations, 2,609 were horizontal. The average gross proved reserves for the undeveloped wells included in our year-end reserves was approximately 2.2 Bcf per well, up from 1.9 Bcf per well at year-end 2008 and 1.5 Bcf per well at year-end 2007.  Total proved gas reserves booked in the play in 2008 totaled approximately 1,545 Bcf from a total of 1,508 locations, of which 882 were proved developed producing, 18 were proved developed non-producing and 608 were proved undeveloped.  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.  If the Fayetteville Shale play continues to be successfully developed, we expect a continued significant level of proved undeveloped reserves in the Fayetteville Shale play over the next few years.


In 2009, we invested approximately $1.3 billion in our Fayetteville Shale play, which included approximately $1.1 billion to spud 570 wells, 420 of which we operated.  We increased our reserves in the Fayetteville Shale play by 1,815 Bcf, which included net upward reserve revisions of 238 Bcf due primarily to improved well performance which was partially offset by downward revisions due to lower prices.  Included in our total capital investments in the play during 2009 was $40 million for acquisition of properties, $22 million for seismic and $106 million in capitalized costs and other expenses.  At December 31, 2009, we had acquired approximately 1,324 square miles of 3-D seismic data, which provides us with seismic data on approximately 68% of our net acreage position in the Fayetteville Shale, excluding our acreage in the traditional Fairway portion of the Arkoma Basin.  In 2008, we invested approximately $1.2 billion in our Fayetteville Shale play, which included $1.0 billion to spud 604 wells, $23 million for acquisition of properties, $61 million for 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 acquisition of properties, $97 million for 3-D seismic and $49 million in capitalized costs and other expenses.  


In 2010, we plan to invest approximately $1.2 billion in our Fayetteville Shale play, which includes participating in approximately 650 to 680 gross wells, 475 to 500 of which are planned to be operated by us.  


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


U.S. Exploitation

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

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At December 31, 2009, we had approximately 330 Bcfe of reserves in East Texas, compared to 351 Bcfe at year-end 2008 and 353 Bcfe at year-end 2007.  Our proved reserves have decreased over the past three years primarily due to our annual field production and downward reserve revisions resulting from comparative decreases in gas prices and negative performance revisions, which have more than offset our successful drilling in the James Lime and Haynesville Shale formations.  In 2009, we invested approximately $167 million in East Texas and participated in 46 wells, of which 33 were successful and 13 were in progress at year-end, resulting in a 100% success rate and adding new reserves of 94 Bcfe.  This area recorded net downward revisions of approximately 55.3 Bcfe primarily due to a comparative decrease in the average 2009 gas price from the 2008 year-end gas price and 25.5 Bcfe of negative performance revisions.  Net production from East Texas was 34.9 Bcfe in 2009, compared to 31.6 Bcfe in 2008 and 29.9 Bcfe in 2007.  Production has grown over the past three years primarily due to our successful drilling program in the James Lime formation which, combined with successful drilling in the Haynesville Shale in 2009, more than offset the natural production decline at Overton.


Our original interest in Overton (which was approximately 10,800 gross acres) was acquired in April 2000 for $6 million. Our wells in Overton produce from four Taylor series sands in the Cotton Valley formation at approximately 12,000 feet.  At December 31, 2009, we held approximately 24,400 gross acres in Overton with an average working interest of 83% and an average net revenue interest of 67%.  In 2009, we invested approximately $4 million to drill two wells at Overton, both of which were successful.  Our proved reserves in Overton were 189 Bcfe at year-end 2009, compared to 273 Bcfe at year-end 2008 and 315 Bcfe at year-end 2007.  Net production from Overton was 14.6 Bcfe in 2009, compared to 19.9 Bcfe in 2008 and 25.1 Bcfe in 2007. We expect our production and reserves from Overton to continue to decline due to the planned lack of significant investment in the field during 2010 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, Haynesville Shale, James Lime, Pettet and Middle Bossier formations. At December 31, 2009, we held approximately 95,200 gross undeveloped acres and 40,200 gross developed acres at Angelina with an average working interest of 65% and an average net revenue interest of 50%.  Our acreage position was obtained at an average cost of approximately $241 per acre and the undeveloped portion of our acreage has an average remaining lease term of 2 years.  Our proved reserves in the Angelina area were 137 Bcfe at year-end 2009, compared to 74 Bcfe at year-end 2008 and 33 Bcfe at year-end 2007.  Net production from our Angelina properties was 19.7 Bcfe in 2009, compared to 11.3 Bcfe in 2008 and 2.5 Bcfe in 2007.


In 2009, we invested approximately $143 million to drill 44 wells at Angelina, all of which were successful or in progress at December 31, 2009.  Our 2009 drilling program was primarily focused on developing the James Lime formation in our Jebel prospect area located in Shelby County, Texas. We also successfully initiated drilling in the Haynesville Shale and Middle Bossier in Shelby and San Augustine Counties with the first horizontal well, the Red River 877 #1 located in Shelby County, production testing at 7.2 MMcf per day in the first quarter of 2009. We drilled four additional wells in the Haynesville Shale formation which production tested at 13.4 MMcf per day, 16.7 MMcf per day, 21.0 MMcf per day and 18.1 MMcf per day. Additionally, we completed our first well in the Middle Bossier formation which production tested at 11.3 MMcf per day. In total, we have approximately 42,300 net acres we believe are prospective for the Haynesville and Middle Bossier Shales and our average gross working interest is approximately 61%.  

At December 31, 2009, we had participated in 77 James Lime horizontal wells, 51 of which we operated, including 8 wells which were in progress.  Of those, 43 wells that we operated were placed on production at an average gross initial production rate of 9.8 MMcfe per day, resulting in net production from the James Lime of approximately 48 MMcf per day at December 31, 2009.

In 2010, we expect to invest approximately $230 million and participate in approximately 50 to 60 gross wells in East Texas, 22 to 27 of which will be operated.  Of the wells planned in 2010, 21 to 26 wells will be targeting the Haynesville or Middle Bossier Shales and 29 to 34 will target the James Lime, Pettet or Cotton Valley formations.

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


At December 31, 2009, we had approximately 208 Bcf of reserves that were attributable to our conventional Arkoma properties, representing approximately 6% of our total reserves, compared to 281 Bcf at year-end 2008 and 304 Bcf at year-end 2007.  Our proved reserves have declined over the past three years primarily due to lower capital

 

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investments in the area which were not sufficient to offset our annual field production and downward revisions due to comparative decreases in gas prices and negative performance revisions.  In 2009, we invested approximately $40 million in our conventional Arkoma drilling program and participated in 20 wells, of which 15 were successful and 3 were in progress at year-end, resulting in an 88% success rate and adding new reserves of 14 Bcf.  This area recorded net downward revisions of approximately 64 Bcf primarily due to a comparative decrease in the average 2009 price from the year-end 2008 gas price and negative performance revisions. Net production from our conventional Arkoma properties was 22.0 Bcf in 2009, compared to 24.4 Bcf in 2008 and 23.8 Bcf in 2007.  Production decreased during 2009 primarily due to significantly lower capital investments in the area as compared to 2008 levels, while production increased in 2008 from 2007 as new production stemming from our 2008 drilling program more than offset the natural production decline from existing wells.  


In 2010, we plan to invest approximately $25 million in our conventional Arkoma program and participate in approximately 15 to 20 wells.

Appalachia.  We began leasing in northeastern Pennsylvania in 2007 in an effort to gain a position in the emerging Marcellus Shale play.  At December 31, 2009, we had approximately 149,317 net acres in Pennsylvania under which we believe the Marcellus Shale is prospective.  Our undeveloped acreage position as of December 31, 2009 had an average remaining lease term of 5 years, an average royalty interest of 13% and was obtained at an average cost of approximately $594 per acre.  During 2009, we invested approximately $40 million in Pennsylvania, almost all of which was for acquisition of properties, including approximately 22,829 net acres in Lycoming County that was purchased for approximately $8.7 million, or $382 per acre. In 2008, we invested approximately $58 million in the Marcellus Shale play in Pennsylvania and drilled our first four wells (three vertical and one horizontal) on our acreage in Bradford and Susquehanna Counties, three of which have been production tested.  In 2007, we invested approximately $17.5 million to purchase acreage in the Marcellus Shale play.  

In 2010, we plan to invest approximately $145 million in Appalachia, which includes participating in a total of 35 to 40 wells, 21 to 24 of which will be operated.

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, 2009, we held 36,125 net undeveloped acres in the United States outside of our core operating areas in connection with New Ventures prospects.  This compares to 138,638 and 156,465 net undeveloped acres held at year-end 2008 and 2007, respectively, of which 114,738 and 88,000 net undeveloped acres, respectively, were in Pennsylvania where we are targeting the Marcellus Shale. The Marcellus Shale acreage was transferred to our U.S. Exploitation group in 2009 and is discussed in more detail in the paragraphs above.


In 2009, we invested approximately $25 million in our New Ventures program, compared to approximately $73 million invested in our New Ventures program in 2008 and approximately $42 million in 2007.  Of the amounts invested during 2008 and 2007, approximately $58 million and $17.5 million, respectively, were invested in the Marcellus Shale play in Pennsylvania.  In 2010, we plan to invest approximately $135 million in various unconventional, exploration and New Ventures projects.  

Acquisitions and Divestitures

During 2009, we purchased approximately 22,829 net acres in Lycoming County, Pennsylvania, for approximately $8.7 million.  Additionally, during 2009 we also purchased the oil and gas leases, wells and gathering equipment on approximately 16,980 net acres in the Fayetteville Shale play for approximately $4.0 million and sold the oil and gas leases, wells and gathering equipment in our Riverton coalbed methane project in Caldwell Parish, Louisiana, for approximately $4.1 million.

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.

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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.  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 or divestitures of gas and oil properties in 2007.

Capital Investments

During 2009, we invested a total of $1.6 billion in our E&P business and participated in drilling 636 wells, 419 of which were successful, 5 were dry and 212 were in progress at year-end.  Of the 212 wells in progress at year-end, 196 were located in our Fayetteville Shale play.  Our investments focused primarily on our active drilling programs in the Fayetteville Shale play, East Texas, Appalachia and the conventional Arkoma Basin, which accounted for 82%, 11%, 3% and 3% of our E&P capital investments in 2009, respectively.  We invested approximately $1.3 billion in our Fayetteville Shale play, $167 million in East Texas, $40 million in Appalachia, $40 million in our conventional Arkoma Basin program and $25 million in New Ventures projects.

Of the $1.6 billion invested in 2009, approximately $1.3 billion was invested in exploratory and development drilling and workovers, $82 million for acquisition of properties, $32 million for seismic expenditures and $155 million in capitalized interest and expenses and other technology-related expenditures.  Additionally, we invested approximately $35 million in our sand facility and drilling rig related and ancillary equipment.  In 2008, we invested approximately $1.6 billion in our primary E&P business activities and participated in drilling 750 wells. Of the $1.6 billion invested in 2008, approximately $1.3 billion was invested in exploratory and development drilling and workovers, $83 million for acquisition of properties, $66 million for seismic expenditures and $118 million in capitalized interest and expenses and other technology-related expenditures. 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, $68 million for acquisition of properties, $100 million for seismic expenditures and $77 million in capitalized interest and expenses and other technology-related expenditures.  

In 2010, we plan to invest approximately $1.7 billion in our E&P program and participate in drilling 750 to 800 gross wells, 520 to 555 of which are planned to be operated by us.  The Fayetteville Shale play will be the primary focus of our capital investments, with planned investments of approximately $1.2 billion.  Our planned 2010 capital investments also include approximately $230 million in East Texas, $145 million in Appalachia, $135 million in unconventional, exploration and New Ventures projects, $25 million in our conventional drilling program in the Arkoma Basin and $15 million for other E&P projects.

Of the $1.7 billion allocated to our 2010 E&P capital budget, approximately $1.3 billion (or 76%) will be invested in development and exploratory drilling, $25 million in seismic and other geological and geophysical expenditures, $180 million in acquisition of properties and $220 million in capitalized interest and expenses as well as equipment, facilities and technology-related expenditures.  We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Investments” for additional discussion of the factors that could impact our planned capital investments in 2010.

Other Revenues

Other revenues and operating income for 2009 included gains of approximately $3.4 million related to the sale of gas-in-storage inventory and charges totaling $6.1 million primarily related to a $4.3 million non-cash impairment to reduce the current portion of our natural gas inventory to the lower of cost or market.  Other revenues and operating income for 2008 and 2007 included gains of approximately $4.8 million and $6.4 million, respectively, related to the sale of gas-in-storage inventory.

Sales, Delivery Commitments and Customers

Sales. Our daily natural gas equivalent production averaged 823.1 MMcfe in 2009, compared to 533.1 MMcfe in 2008 and 311.1 MMcfe in 2007.  Total natural gas equivalent production was 300.4 Bcfe in 2009, up from 194.6 Bcfe in 2008 and 113.6 Bcfe in 2007.  Our natural gas production was 299.7 Bcf in 2009, compared to 192.3 Bcf in 2008 and 109.9 Bcf in 2007.  The increase in production in 2009 resulted primarily from a 109.0 Bcf increase in production from the Fayetteville Shale play and an increase in our East Texas production, which more than offset a combined decrease in net production arising from decreased production from our Arkoma and other properties and the sale of our Permian Basin and Gulf Coast properties in 2008.  The increase in production in 2008 resulted primarily from an 81.0 Bcf increase in


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production from the Fayetteville Shale play which combined with increases in our East Texas and Arkoma production to more than offset the decreases resulting from the oil and gas properties sold during 2008.  We also produced 124,000 barrels of oil in 2009, compared to 385,000 barrels of oil in 2008 and 614,000 barrels of oil in 2007.  Our oil production decreased during 2009 and 2008 primarily due to the sale of our Permian and Gulf Coast properties in 2008.  For 2010, we are targeting total natural gas and crude oil production of approximately 400 to 410 Bcfe, which represents a growth rate of approximately 35% over our 2009 production volumes.

Sales of gas and oil production are conducted under contracts that reflect current prices and are subject to seasonal price swings. We are unable to predict changes in the market demand and price for natural gas, including changes that may be induced by the effects of weather on demand for our production.

We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude oil production in order to support certain desired levels of cash flow and to minimize the impact of price fluctuations.  Our policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. At December 31, 2009, we had hedges in place on 66 Bcf, or approximately 16% of our targeted 2010 gas production, and 30 Bcf of our expected 2011 gas production. We intend to hedge additional future production volumes to the extent natural gas prices rise to levels that we believe will achieve certain desired levels of cash flow.  We refer you to Item 7A of this Form 10-K, “Quantitative and Qualitative Disclosures about Market Risks,” for further information regarding our hedge position at December 31, 2009.

Including the effect of hedges, we realized an average wellhead price of $5.30 per Mcf for our natural gas production in 2009, compared to $7.52 per Mcf in 2008 and $6.80 per Mcf in 2007.  Our hedging activities increased our average gas price $1.96 per Mcf in 2009, decreased our average price $0.21 per Mcf in 2008 and increased our average price $0.64 per Mcf in 2007.  Our average oil price realized was $54.99 per barrel in 2009, compared to $107.18 per barrel in 2008 and $69.12 per barrel in 2007.  None of our crude oil production was hedged during 2009, 2008 or 2007.  

In recent years, locational differences in market prices for natural gas have been wider than historically experienced.  Disregarding the impact of hedges, from 2005 through 2007, the average price received for our gas production was approximately $0.50 to $1.00 per Mcf lower than average NYMEX spot market prices primarily due to the locational market differentials. However, during 2009 and 2008, widening market differentials caused the difference in our annual average price received for our gas production to range from approximately $0.65 to $1.30 per Mcf lower than market prices.  The discount was at its highest in late 2008, due to increased production in the Fayetteville Shale for which there was not sufficient transportation to other markets as a result of the delay in the completion of the Boardwalk Pipeline. Since the completion of the Boardwalk Pipeline, the locational differences in the market prices for our gas production has narrowed.  Assuming a NYMEX commodity price for 2010 of $5.00 per Mcf of gas, the average price received for our gas production is expected to be approximately $0.10 to $0.20 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges. Our E&P segment receives a sales price for our natural gas at a discount to NYMEX spot prices due to locational basis differentials, while transportation charges and fuel charges also reduce the price received.  In 2010, we expect to pay average third-party transportation charges in the range of $0.25 to $0.32 per Mcf and average fuel charges in the range of 0.25% to 1.00% of our sales price for natural gas.

Delivery Commitments. As of February 1, 2010, we had natural gas delivery commitments of 134 Bcf in 2010 and 38 Bcf in 2011 under existing agreements.  These commitments require the delivery of natural gas in Arkansas and Texas.   These amounts are well below our forecasted 2010 and anticipated 2011 production from our available reserves in our Fayetteville Shale and East Texas operations, which are not subject to any priorities or curtailments that may affect quantities delivered to our customers or any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond our control that may affect our ability to meet our contractual obligations other than those discussed in Item 1A. “Risk Factors”.  We expect to be able to fulfill all of our short-term or long-term contractual obligations from available reserves from our own production, however, if we are unable to do so, we may have to purchase gas at market to fulfill our obligations. We may have to borrow funds to pay for these gas purchases and if we are unable to do so, our earnings could be adversely affected.

Customers. Our customers include major and small energy companies, utilities and industrial consumers of natural gas. During the years ended December 31, 2009, 2008 and 2007, no single third-party customer accounted for 10% or more of our consolidated revenues.

 

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Impact of Federal Regulation of Sales of Natural Gas and Oil

 

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

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

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 natural gas.  

Our operating income from this segment was $122.6 million on revenues of $1.6 billion in 2009, compared to $62.3 million on revenues of $2.2 billion in 2008 and $13.2 million on revenues of $962.0 million in 2007.  Revenues decreased in 2009 as increased gathering revenues and increased volumes marketed were more than offset by considerably lower gas prices.  The increase in revenue in 2008 was largely attributable to increased gathering revenues, increased volumes marketed and higher gas prices.  EBITDA generated by our Midstream Services segment was $141.9 million in

 

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2009, compared to $73.9 million in 2008 and $18.8 million in 2007.  The increases in 2009 and 2008 operating income and EBITDA were primarily due to increased gathering revenues and marketing margins, partially offset by increased operating costs and expenses.  We expect that the operating income and EBITDA of our Midstream Services segment will increase significantly over the next few years as we continue to develop our Fayetteville Shale acreage.  EBITDA is a non-GAAP measure.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA to net income (loss) attributable to Southwestern Energy.  

Gas Gathering

We engage in gas gathering activities through our gathering subsidiaries, DeSoto Gathering and Angelina Gathering. DeSoto Gathering engages in gathering activities in Arkansas primarily related to the development of our Fayetteville Shale play.  In 2009, we invested approximately $214.2 million related to these activities and had gathering revenues of $205.6 million, compared to $183.0 million invested and revenues of $114.9 million in 2008 and $107.4 million invested and $37.7 million in revenues in 2007.  


DeSoto Gathering is rapidly expanding its network of gathering pipelines and facilities throughout the Fayetteville Shale play area. During 2009, DeSoto Gathering gathered approximately 367.3 Bcf of gas volumes in the Fayetteville Shale play area, including 26.9 Bcf of third-party natural gas.  During 2008, DeSoto Gathering 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, DeSoto Gathering gathered approximately 78.7 Bcf of gas volumes in the Fayetteville Shale play area, including 7.6 Bcf of third-party natural gas.  The increase in volumes gathered in 2009, 2008 and 2007 was primarily due to our growing production volumes from the Fayetteville Shale play.  At the end of 2009, DeSoto Gathering had approximately 1,137 miles of pipe from the individual wellheads to the transmission lines and compression equipment had been installed at 48 central point gathering facilities in the field. Angelina Gathering currently engages in gathering activities in East Texas in connection with our Angelina properties.  Angelina Gathering provides gathering support for all of our E&P operations outside of Arkansas.  At year-end 2009, Angelina Gathering had approximately 21 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 related to marketing and transportation of natural gas. SES purchases gas production and sells it to end-users and manages the basis and marketing portfolio and acquires 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 2009, we marketed 382.5 Bcf of natural gas, compared to 258.0 Bcf in 2008 and 145.7 Bcf in 2007.  Of the total volumes marketed, production from our E&P operated wells accounted for 92% in 2009, compared to 96% in 2008 and 89% in 2007.


In 2008 and 2006, SES became a “foundation shipper” on two pipeline projects serving the Fayetteville Shale play in anticipation of significant growth in the future production volumes from our operations in the play. In 2008, Fayetteville Express Pipeline LLC, or FEP, which is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P., agreed to construct a pipeline with an estimated ultimate capacity of up to 2.0 Bcf per day that will provide our operations in the Fayetteville Shale play with access to midwestern and eastern markets.  The application for the pipeline was approved by the Federal Energy Regulatory Commission, or the FERC, in December 2009, and it is expected to be in-service by late 2010 or early 2011.  SES has a maximum aggregate commitment of 1,200,000 Dekatherms per day for an initial term of ten years from the in-service date. The other project, which began in 2006 and consists of two pipeline laterals called the Fayetteville and Greenville Laterals, has already been constructed by Texas Gas Transmission, LLC, or Texas Gas, a subsidiary of Boardwalk Pipeline Partners, LP. 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.

 

On April 1, 2009, Texas Gas placed in service the Fayetteville and the Greenville laterals and subsequently reduced the capacity on, or shut down, both laterals on several occasions due to various activities, including maintenance and pipeline inspection.  As a result, we curtailed a portion of our natural gas production during the third and fourth quarters of 2009 as Texas Gas remediated pipe anomalies pursuant to protocol agreed with the Pipeline and Hazardous Materials Safety Administration, or PHMSA.  On October 8, 2009, Texas Gas announced it received authorization from the PHMSA to operate the Fayetteville and Greenville Laterals at standard operating pressures with a capacity of 805,000 MMBtu per day, which is less than the total capacity anticipated under the firm transportation and resulted in a reduction in the capacity to which we are entitled.  Texas Gas is continuing to perform the testing protocol required by PHMSA and, once that testing has been completed and the results known, expects to request from PHMSA the authority to operate the 

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Fayetteville Lateral at higher than normal operating pressures under a special permit. In January 2010, Texas Gas added compression facilities that increased peak-day delivery capacity to approximately 1.0 Bcf per day on the Greenville Lateral and approximately 1.1 Bcf per day on the Fayetteville Lateral. The designed peakday delivery capacity of the Fayetteville Lateral is approximately 1.3 Bcf per day once the authority to operate it at higher than normal operating pressures is received from PHMSA or Texas Gas completes other system upgrades on that project. The increase in capacity to 1.3 Bcf per day will be needed in order for Texas Gas to meet its contractual commitments that will be in effect in mid-2011.   

Prior to the commencement of service on the Fayetteville and Greenville Laterals, 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.”  The Fayetteville and Greenville Laterals allow us to transport our gas to markets in the eastern United States and interconnect with Texas Gas Zone 1, Tennessee Gas Pipeline 100, Trunkline Zone 1A, ANR, Tennessee Gas Pipeline 800, Columbia Gulf Mainline, TETCO M1 30" and Sonat price indices.  We rely in part upon the Fayetteville and Greenville Laterals to service our increased production from the Fayetteville Shale play.  There can be no assurance that the amount of gas being produced in the Fayetteville Shale will not exceed the available capacity of the various intrastate or interstate transportation pipelines.  Our projections, financial condition, results of operation and planned capital expenditures could be adversely impacted by lack of available capacity and continued capacity reductions, shutdowns or other curtailments of the laterals or other pipelines.


Competition

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

Regulation

On March 15, 2006, the United States Department of Transportation, or DOT, issued new rules pertaining to certain gathering lines. Compliance with the new rules has not had a material adverse impact on our operations. We refer you to “Other Items — Environmental Matters” and the risk factor “We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future” in Item 1A of Part I of this Form 10-K for a discussion of the impact of government regulation on our Midstream Services business.


On November 20, 2008, the FERC issued a Final Rule in Order No. 720, which requires, in relevant part, major non-interstate natural gas pipelines to post, on a daily basis, specific scheduled flow information at each receipt or delivery point with a design capacity of 15,000 MMBtu per day or more. A “major non-interstate pipeline” is a pipeline that is not classified as a natural gas company under the NGA and delivers on average more than 50 million MMBtu of gas annually over a three year period.  Our gathering system in Arkansas 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 and such an order was issued on January 21, 2010.  We believe that we will be able to comply with the requirements of Order No. 720 within the prescribed 150 days.


Natural Gas Distribution

Effective July 1, 2008, we sold all of the capital stock of Arkansas Western Gas for $223.5 million (net of expenses related to the sale). In order to receive regulatory approval for the sale and certain related transactions, we paid $9.8 million to Arkansas Western Gas for the benefit of its customers.  We recorded a pre-tax gain on the sale of $57.3 million in the third quarter of 2008.  As a result of the sale of the utility, we are no longer engaged in natural gas distribution operations.  Arkansas Western Gas provided operating income for the first half of 2008 of $10.7 million, compared to $10.0 million for the entire year of 2007.

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Other

Our other operations have primarily consisted of real estate development activities concentrated on tracts of land located in Arkansas.  There were no sales of commercial real estate in 2009, 2008 or 2007. As of December 31, 2009, we owned our office complex in Fayetteville, Arkansas, an interest in approximately 15 acres of undeveloped real estate near the Fayetteville complex and 731 acres in or near Conway, Arkansas, related to our operations in the Fayetteville Shale play.

Other Items

Reconciliation of Non-GAAP Measures

EBITDA is defined as net income (loss) attributable to Southwestern Energy plus interest, income tax expense, depreciation, depletion and amortization.  We have included information concerning EBITDA in this Form 10-K because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in our industry.  EBITDA should not be considered in isolation or as a substitute for net income (loss) attributable to Southwestern Energy, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles in the United States, or GAAP, or as a measure of our profitability or liquidity.  EBITDA as defined above may not be comparable to similarly titled measures of other companies.

We believe that net income (loss) attributable to Southwestern Energy is the financial measure calculated and presented in accordance with GAAP that is most directly comparable to EBITDA as defined.  The following table reconciles EBITDA, as defined, with net income (loss) attributable to Southwestern Energy for the years-ended December 31, 2009, 2008 and 2007:


 

 

 

Midstream

 

Natural Gas

 

 

 

 

 

E&P

 

Services

 

Distribution

 

Other

 

Total

 

(in thousands)

2009

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Southwestern Energy........................................................................

$      (109,690)

 

$         73,950 

 

$                — 

 

$                90 

 

$      (35,650)

Depreciation, depletion and amortization.................

 474,014 

 

 19,213 

 

 — 

 

 431 

 

 493,658 

Impairment of natural gas and oil properties……...

 907,812 

 

 — 

 

 — 

 

 — 

 

 907,812 

Net interest expense....................................................

 15,237 

 

 3,401 

 

 — 

 

 — 

 

 18,638 

Provision (benefit) for income taxes..........................

 (61,724)

 

 45,303 

 

 — 

 

 58 

 

 (16,363)

EBITDA.........................................................................

$    1,225,649 

 

$       141,867 

 

$                — 

 

$              579 

 

$  1,368,095 

 

 

 

 

 

 

 

 

 

 

2008

 

 

 

 

 

 

 

 

 

Net income attributable to Southwestern Energy...

$       492,283 

 

$         35,145 

 

$           5,050 

 

$         35,468 

 

$     567,946 

Depreciation, depletion and amortization.................

 399,159 

 

 11,402 

 

 3,484 

 

 415 

 

 414,460 

Net interest expense....................................................

 20,528 

 

 6,059 

 

 2,317 

 

 — 

 

 28,904 

Provision for income taxes..........................................

 304,636 

 

 21,278 

 

 3,095 

 

 21,990 

 

 350,999 

EBITDA.........................................................................

$    1,216,606 

 

$         73,884 

 

$         13,946 

 

$         57,873 

 

$  1,362,309 

 

 

 

 

 

 

 

 

 

 

2007

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Southwestern Energy........................................................................

$       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 


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 the CERCLA, the Clean Water Act, the Clean Air Act and similar state statutes.  These laws and regulations require permits for drilling wells and the maintenance of bonding requirements in order to drill or operate wells and also regulate the spacing and location of wells, the method of drilling

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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 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.   

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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.

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

Employees

At December 31, 2009, we had 1,702 total employees.  None of our employees were covered by a collective bargaining agreement at year-end 2009.  We believe that our relationships with our employees are good.

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GLOSSARY OF CERTAIN INDUSTRY TERMS

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

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

Analogous reservoir”  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)

Same environment of deposition;

(iii)

Similar geological structure; and

(iv)

Same drive mechanism.

For additional information, see the SEC’s definition in Rule 4-10(a) (2) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

 

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

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

“Bcf”  One billion cubic feet of 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).

Developed oil and gas reserves Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required    equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

For additional information, see the SEC’s definition in Rule 4-10(a) (6) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

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Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

For additional information, see the SEC’s definition in Rule 4-10(a) (7) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

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

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

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

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

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

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

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

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

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

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

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

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

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

Mcf”  One thousand cubic feet of natural gas.

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

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

MMBtu”  One million British thermal units (Btu).

MMcf”  One million cubic feet of natural gas.

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

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

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

NYMEX”  The New York Mercantile Exchange.

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

Overriding royalty interest”  A fractional, undivided interest or right to production or revenues, free of costs, of a lessee with respect to an oil or 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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 “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 in the applicable jurisdiction.  The order may be statewide in its application (subject to change for local conditions) or it may be entered for each field after its discovery. In the operational context, “well spacing” refers to the area attributable between producing wells within the scope of what is permitted under a regulatory order.

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

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

WTI”  West Texas Intermediate, the benchmark crude oil in the United States.

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ITEM 1A.  RISK FACTORS

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

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

Natural gas and oil prices have historically been, and are likely to continue to be, volatile.  The prices for natural gas and oil are subject to wide fluctuation in response to a number of factors, including:

;

·

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

·

market uncertainty;

·

worldwide economic conditions;

·

weather conditions;

·

import prices;

·

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

·

actions taken by OPEC;  

·

competition from other sources of energy; and

·

economic, political and regulatory developments.

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

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

In the first half of 2008, natural gas and oil prices were at or near their highest historical levels but subsequently natural gas and oil prices declined significantly, resulting in a ceiling test write-down in the first quarter of 2009. Natural gas prices remained at substantially lower levels throughout 2009. The further decline in natural gas and oil prices would have a material adverse effect on our financial position, our results of operations, our access to capital and the quantities of natural gas and oil that may be economically produced by us.  A significant decrease in price levels for an extended period would negatively affect us in several ways including:

·

our cash flow would be reduced, decreasing funds available for capital investments employed to replace reserves or increase production;

·

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

·

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

Consequently, our revenues and profitability would suffer.

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

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

These rules generally require pricing future natural gas and oil production at the unescalated natural gas and oil prices in effect at the end of each fiscal quarter, including the impact of derivatives qualifying as cash flow hedges, utilizing the average price in the 12-month period prior to December 31, 2009, defined as the unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. They also require a write-down if the ceiling limit is exceeded, 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.

In the period ended March 31, 2009, we incurred a ceiling test write-down of $907.8 million which resulted in an operating loss for our company for 2009. If natural gas and oil prices decline below levels utilized in our ceiling limit test at December 31, 2009 and/or development costs increase, a write-down may occur, which would adversely impact our results of operation and financial condition.

We may have difficulty financing our planned capital investments, which could adversely affect our growth.

We have experienced and expect to continue to experience substantial capital expenditure and working capital needs as a result of our drilling program. Our planned capital investments for 2010 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, 2009, we were in compliance with the borrowing conditions of our credit facility.  If we are not in compliance with the terms of our credit facility in the future or if the lenders under our credit facility are unable to fulfill their commitments, we may not be able to borrow under the facility to fund our capital investments.  We also cannot be certain that other financing will be available to us on acceptable terms or at all.  In the event additional capital resources are unavailable, we may curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.  Any such curtailment or sale could have a material adverse effect on our results and future operations.

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

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

Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate.

Our reserve data represents the estimates of our reservoir engineers made under the supervision of our management.  Our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm.  In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently develop reserve estimates.  NSAI’s audit consists primarily of substantive testing, which includes a detailed review of major properties that account for approximately 88% of the present worth of our total proved reserves.  NSAI’s audit process consists of sorting all fields by descending present value order and selecting the fields from highest value to descending value until the selected fields account for more than 80% of the present worth of our reserves.  The properties in the bottom 20% of the total present worth are the lowest value properties and are not reviewed in the audit.  The fields included in approximately the top 88% present value as of December 31, 2009 accounted for approximately 90% of our total proved reserves and approximately 97% of our proved undeveloped reserves.  In the conduct of its audit, NSAI 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

 

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agreements relating to current and future operations of the properties and sales of production.  NSAI has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data. The estimates of NSAI may differ significantly on an individual property basis from our estimates. When, in the aggregate, such differences are within 10%, NSAI is generally satisfied that the estimates of proved reserves are reasonable. 

Our estimate of natural gas and oil reserves requires extensive judgments of reservoir engineering data and projections of cost that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates under the supervision of our management.  Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team to which the property is assigned.  The reservoir engineering and financial data included in these estimates are reviewed by senior engineers who are not part of the asset management teams and by our Vice President-Economic Planning and Acquisitions who is the technical person primarily responsible for the preparation of our reserve estimates, and has over twenty years of experience in petroleum engineering, including over fifteen years in estimating oil and gas reserves. On our behalf, the Vice President-Economic Planning and Acquisitions engages NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in more detail below. The financial data included in the reserve estimates are also separately reviewed by our accounting staff.  Our proved reserve estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our Chief Executive Officer.  Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors and final authority over the estimates of our proved reserves rests with our Board of Directors. 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 2009, our reserves were revised upward by 92.9 Bcfe, primarily due to improved performance in our Fayetteville Shale properties, partially offset by downward revisions due to a comparative decrease in the average 2009 price from the year-end 2008 gas price.  In 2008, our reserves were revised upward by 98.1 Bcfe, primarily due to improved performance in our Fayetteville Shale properties, partially offset by downward revisions due to lower year-end oil and 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.  These revisions represented no greater than 5% 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, 2009, approximately 1,677 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.

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

At December 31, 2009, we had total indebtedness of $998.7 million, including borrowings of $324.5 million under our revolving credit facility.  At February 25, 2010, we had total long-term indebtedness of $1,089.2 million, including borrowings of $415.0 million under our revolving credit facility.  We currently expect to utilize the borrowing availability under our revolving credit facility in order to fund a portion of our capital investments in 2010.  See also our risk factor headed “We may have difficulty financing our planned capital investments which could adversely affect our growth,” above.

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

·

incurring additional debt, including guarantees of indebtedness;

·

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.  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 such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.

If we fail to find or acquire additional reserves, our reserves and production will decline materially from their current levels.

The rate of production from natural gas and oil properties generally declines as reserves are depleted.  Unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities, successfully apply new technologies or identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline materially as reserves are produced.  Future natural gas and oil production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

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

As of December 31, 2009, we had drilled and completed 1,288 wells relating to our Fayetteville Shale play.  At year-end 2009, approximately 48% of our leasehold acreage was held by production, excluding our acreage in the traditional Fairway portion of the Arkoma Basin. Our drilling plans with respect to our Fayetteville Shale play are flexible and are dependent upon a number of factors, including the extent to which we can replicate the results of our most successful Fayetteville Shale wells on our other Fayetteville Shale acreage as well as the natural gas and oil commodity price environment.  The determination as to whether we continue to drill wells in the Fayetteville Shale may depend on any one or more of the following factors:

·

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

·

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

·

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

·

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

·

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

·

the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services;

·

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

·

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

·

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

·

availability and cost of capital; or

·

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

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

If we fail to drill all of the wells that are necessary to hold our Fayetteville Shale acreage, the initial lease terms could expire, which would result in the loss of certain leasehold rights.

Approximately 178,930 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 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, 2009, we had invested approximately $548.9 million in our gas gathering system built for the Fayetteville Shale play.  We intend to continue to make substantial investments in the expansion of our gas gathering system as we further develop the play.  Our gas gathering business will largely rely on gas sourced in our Fayetteville Shale play area in Arkansas.  In addition, we have entered into 10-year firm transportation agreements committing us to transportation on the Fayetteville and Greenville laterals recently built by Texas Gas to service the Fayetteville Shale play 

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area as well as the pipeline being constructed by Fayetteville Express Pipeline LLC, which is jointly owned by Kinder Morgan Energy Partners, L.P. Our marketing subsidiary has also entered into multiple other firm transportation agreements relating to gas volumes from our Fayetteville Shale play. As of December 31, 2009, our aggregate demand charge commitments under these firm transportation agreements were approximately $1.8 billion. If our Fayetteville Shale drilling program fails to produce a significant supply of natural gas, our investments in our gas gathering operations could be lost, and we could be forced to pay demand charges for transportation on pipelines that we would not be using.  These events could have an adverse effect on our results of operations, financial condition and cash flows.

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

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

In addition, we may not be successful in implementing our business strategy of controlling and reducing our drilling and production costs in order to improve our overall return.  The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project.  Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, environmental and other governmental requirements and the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.

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

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

As an owner or lessee and operator of natural gas and oil properties, and an owner of gas gathering systems, we are subject to various federal, state and local regulations relating to discharge of materials into, and protection of, the environment.  These regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas.  Changes in or additions to regulations regarding the protection of the environment could significantly increase our costs of compliance, or otherwise adversely affect our business.

One of the responsibilities of owning and operating natural gas and oil properties is paying for the cost of abandonment. We may incur significant abandonment costs in the future which could adversely affect our financial results.

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

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

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

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

We maintain insurance against many potential losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent.  However, our insurance does not protect us against all operational risks.  For example, we 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, 2009, approximately 6% of our gas and oil properties, based on the PV-10 value of our proved developed producing reserves, were operated by other companies.  Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and our targeted production growth rate.  The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond our control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of technology.

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

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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. 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.

Delays in the construction of the pipelines serving the Fayetteville Shale play or in the receipt of regulatory approvals affecting the pipelines could result in capacity constraints that may limit our ability to sell natural gas and/or receive favorable prices for our gas.

If drilling in the Fayetteville Shale continues to be successful, the amount of gas being produced in the area from new wells, as well as gas produced from existing wells, may exceed the capacity of the various intrastate or interstate transportation pipelines currently available.  We have subscribed for capacity on the Fayetteville and Greenville Laterals recently built by Texas Gas Transmission, LLC, and the pipeline being constructed by Fayetteville Express Pipeline LLC which is expected to be in service in late 2010 or early 2011.

On April 1, 2009, Texas Gas placed in service the entire Fayetteville and Greenville laterals and subsequently reduced the capacity on, or shut down, both laterals on several occasions due to various activities, including maintenance and pipeline inspection.  As a result, we curtailed a portion of our natural gas production during the third and fourth quarters of 2009 primarily due to the inspections, repairs and maintenance relating to the remediation of pipe anomalies on the Fayetteville and Greenville Laterals.  The remediation of the pipe anomalies by Texas Gas was pursuant to an agreement with the Pipeline and Hazardous Materials Safety Administration, or PHMSA, entered during the second quarter 2009, which defined the testing protocol and remediation efforts that Texas Gas would need to complete in order to return to normal operating pressures, and for the Fayetteville Lateral, to operate at higher than normal operating pressures.  On October 8, 2009, Texas Gas announced it received authorization from the PHMSA to operate the Fayetteville and Greenville Laterals at standard operating pressures with a capacity of 805,000 MMBtu per day.  Texas Gas is continuing to perform the testing protocol required by PHMSA and, once that testing has been completed and the results known, expects to request from PHMSA the authority to operate the Fayetteville Lateral at higher than normal operating pressures under a special permit.  In addition, Texas Gas plans to add compression in 2010 that will increase peak-day delivery capacities to approximately 1.0 Bcf per day on the Greenville Lateral, and assuming that the authority is received to operate the Fayetteville Lateral at higher than normal operating pressures, increase peak-day delivery capacities to approximately 1.3 Bcf per day on the Fayetteville Lateral.  The compression for the Fayetteville and Greenville Laterals has been approved by the FERC.  PHMSA retains discretion as to whether to grant, or to maintain in force, authority to operate a pipeline at higher than normal operating pressures.  We cannot predict when or if the Fayetteville Lateral will be able to operate at higher capacities.  In addition, PHMSA mandated repairs in conjunction with obtaining the special operating permit or any other substantial delay in obtaining the special operating permit from PHMSA could result in future curtailments of our capacity.  

We rely upon the Fayetteville and Greenville Laterals to service our increased production from the Fayetteville Shale play and are relying upon the FEP pipeline’s timely construction. There can be no assurance that the amount of gas being produced in the Fayetteville Shale will not exceed the available capacity of the various intrastate or interstate transportation pipelines. Our projections, financial condition, results of operation and planned capital expenditures could be adversely impacted by lack of available capacity and continued capacity reductions, shutdowns or other curtailments of the laterals or other pipelines.

Shortages of oilfield equipment, services, supplies, raw materials and qualified personnel could adversely affect our results of operations.  

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These factors also cause significant increases in costs for equipment, services, personnel and raw materials (such as sand, cement, manufactured proppants and other materials utilized in the provision of the oilfield services).  Higher natural gas and oil prices generally stimulate increased

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demand and result in increased prices for drilling rigs, crews and associated supplies, equipment, services and raw materials.  In addition, our E&P operations also require local access to large quantities of water supplies and disposal services for produced water in connection with our hydraulic fracture stimulations due to prohibitive transportation costs. We cannot be certain when we will experience shortages or price increases, which could adversely affect our profit margin, cash flow and operating results or restrict our ability to drill wells and conduct ordinary operations.

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

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

We have made significant investments in our own drilling rig and sand mine operations in order to meet certain of our oilfield service and resource needs, lower our costs and increase of the efficiency of our operations.  If disrupted, these operations may adversely impact our results of operations.  In addition, these operations may adversely impact our relationships with third-party providers.  

We have made significant investments in order to meet certain of our oilfield services needs, including establishing our own drilling rig operations and sand mine and we may make additional investments to expand these operations in the future.  Our drilling operations are conducted through our subsidiary, DDI, which had 366 employees as of December 31, 2009.  We have lease commitments for 14 drilling rigs and related equipment with respect to DDI's operations and we also own one drilling rig.  In addition to these rigs, we have contracts with third-party drilling companies for use of their rigs which may not be terminable without penalty.  In 2009, another of our subsidiaries, DeSoto Sand, LLC, began operating our first sand mine in Arkansas in order to meet a portion of our sand needs for the Fayetteville Shale play. We also purchase sand for use in our operations from various third parties, including certain of our oilfield service providers.  Our drilling rig and sand mine operations may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.  We may also compete with third-party providers for qualified personnel, which could adversely affect our relationships with such providers. If the operations of our drilling rigs operations and/or sand mine are disrupted or our existing third-party providers discontinue their relationships with us, we may not be able to secure alternative services or resources on a timely basis, or at all.  Even if we are able to secure alternative services or resources, there can be no assurance that such services or resources will be of equivalent quality or that pricing and other terms will be favorable to us.  If we are unable to secure third-party services or resources or if the terms are not favorable to us, our financial condition and results of operations could be adversely affected.

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

The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy depends, in part, on our experienced management team, as well as certain key geoscientists, geologists, engineers and other professionals employed by us.  The loss of key members of our management team or other highly qualified technical professionals could have a material adverse effect on our business, financial condition and operating results.

If natural gas prices decline, our failure to hedge a significant portion of our expected 2010 production could adversely affect our results of operations and financial condition.

To reduce our exposure to fluctuations in the prices of natural gas and oil, historically, we have entered into hedging arrangements with respect to a significant portion of our expected production.  As of December 31, 2009, we had hedges on approximately 16% of our targeted 2010 natural gas production as compared to approximately 60% to 80% from 2006 to 2008 and 45% for 2009.  Our price risk management activities increased gas sales by $587.8 million in 2009, decreased gas sales by $40.5 million in 2008 and increased gas sales by $70.7 million in 2007. If natural gas prices decline in 2010, unless we enter into additional hedging arrangements, our revenues would be adversely affected.   To the extent 

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that we engage in additional hedging activities in the current price environment, we would not realize the benefit of price increases above the levels of the hedges.  

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

·

our production is less than expected;

·

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

·

the counterparties to our futures contracts fail to perform the contracts; or

·

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

Finally, future market price volatility could create significant changes to the hedge positions recorded on our financial statements.  We refer you to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of Part II of this Form 10-K.

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

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

Climate change and global warming concerns could lead to additional regulatory measures that may adversely impact our operations and financial condition.

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

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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.

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


ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.


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ITEM 2.  PROPERTIES

  The summary of our oil and gas reserves as of fiscal year-end 2009 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2009 Proved Reserves by Category and Summary Operating Data” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Form 10-K and incorporated by reference into this Item 2.  Our proved reserves are based upon estimates prepared for each of our properties annually by the reservoir engineers assigned to the asset management team in the geographic locations in which the property is located. These estimates are reviewed by senior engineers who are not part of the asset management teams and by our Vice President-Economic Planning and Acquisitions, or Vice President-EP&A,  who was the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Vice President-EP&A has more than twenty years of experience in petroleum engineering, including over fifteen years of experience in estimating oil and gas reserves and holds a Bachelor of Science in Chemical Engineering.  Prior to joining us in 1993, our Vice President-EP&A worked for Conoco Inc. in various engineering functions.  Our Vice President-EP&A is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers, Society of Petroleum Evaluation Engineers, and an associate member of the American Association of Petroleum Geologists. On our behalf, the Vice President-EP&A engages Netherland, Sewell & Associates, Inc., or NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the technical persons primarily responsible for auditing our proved reserves estimates each (1) have at a minimum over 25 years of practical experience in petroleum engineering; (2) have at a minimum over 18 years of experience in the estimation and evaluation of reserves; (3) have college degrees; (4) is a registered Professional Engineer in the State of Texas or a Certified Petroleum Geologist and Geophysicist in the State of Texas; (5) meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and (6) is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates are also separately reviewed by our accounting staff.  Our proved reserves estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our Chief Executive Officer.  Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors and final authority over the estimates of our proved reserves rests with our Board of Directors.  A copy of NSAI's report has been filed as Exhibit 99.1 to this Form 10-K.   

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

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

 

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The following information is provided to supplement the information that is presented in Item 8 of Part II of this Form 10-K.  

Oil and Gas Properties, Wells, Operations and Acreage

Leasehold acreage as of December 31, 2009:


 

Undeveloped

 

Developed

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

Fayetteville Shale Play(1)

…………..

 689,840 

 

 394,538 

 

 558,720 

 

 368,755 

U.S. Exploitation:

 

 

 

 

 

 

 

Conventional Arkoma(2)………….

 366,996 

 

 278,927 

 

 271,476 

 

 184,961 

East Texas(3)…………………….....

 104,220 

 

 61,298 

 

 70,679 

 

 53,901 

Appalachia(4)……….......................

 150,362 

 

 149,317 

 

 - 

 

 - 

New Ventures……………………......

 41,573 

 

 36,125 

 

 - 

 

 - 

 

 1,352,991 

 

 920,205 

 

 900,875 

 

 607,617 


(1)  Assuming successful wells are not drilled and leases are not extended, leasehold expiring over the next three years will be 120,977 net acres in 2010, 23,722 net acres in 2011 and 34,231 net acres in 2012.

(2)  Includes 123,442 net developed acres and 1,960 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 32,434 net acres in 2010, 34,115 net acres in 2011 and 28,153 net acres in 2012.

(3)  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 21,747 net acres in 2010, 24,594 net acres in 2011 and 2,334 net acres in 2012.

(4)  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 1,475 net acres in 2010, 551 net acres in 2011 and 61,133 net acres in 2012.


Producing wells as of December 31, 2009:


 

Gas

 

Oil

 

Total

 

Gross Wells

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Operated

 


 


 


 


 


 


 


Fayetteville Shale Play…..

 1,428 

 

 993 

 

 - 

 

 - 

 

 1,428 

 

 993 

 

 1,160 

U.S. Exploitation:

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional Arkoma...

 1,193 

 

 583 

 

 - 

 

 - 

 

 1,193 

 

 583 

 

 548 

East Texas……………...

 580 

 

 447 

 

 2 

 

 2 

 

 582 

 

 449 

 

 523 

 

 3,201 

 

 2,023 

 

 2 

 

 2 

 

 3,203 

 

 2,025 

 

 2,231 


Drilling and Other Exploratory and Development Activities:


 

Exploratory

 

 

 

 

 

 

 

Productive Wells

 

Dry Wells

 

Total

Year

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 


 


 


 


 


 


2009…………………….......

 1.0 

 

 0.9 

 

 2.0 

 

 1.2 

 

 3.0 

 

 2.1 

2008…………………….......

 34.0 

 

 22.4 

 

 2.0 

 

 2.0 

 

 36.0 

 

 24.4 

2007…………………….......

 97.0 

 

 69.4 

 

 5.0 

 

 3.7 

 

 102.0 

 

 73.1 


 

Development

 

 

 

 

 

 

 

Productive Wells

 

Dry Wells

 

Total

Year

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 


 


 


 


 


 


2009…………………….......

 418.0 

 

 253.6 

 

 3.0 

 

 1.8 

 

 421.0 

 

 255.4 

2008…………………….......

 445.0 

 

 270.2 

 

 9.0 

 

 6.8 

 

 454.0 

 

 277.0 

2007…………………….......

 342.0 

 

 225.2 

 

 12.0 

 

 8.5 

 

 354.0 

 

 233.7 


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Present Activities

Wells in progress as of December 31, 2009:


 

Gross

 

Net

 


 


Drilling:


 


  Exploratory

 - 

 

 - 

  Development

 83.0 

 

 51.8 

Total

 83.0 

 

 51.8 

 

 

 

 

Completing:

 

 

 

  Exploratory

 1.0 

 

 0.1 

  Development

 128.0 

 

 76.4 

Total

 129.0 

 

 76.5 

 

 

 

 

Drilling & Completing:

 

 

 

  Exploratory

 1.0 

 

 0.1 

  Development

 211.0 

 

 128.2 

 Total

 212.0 

 

 128.3 


Production, Average Sales Price and Average Production Cost:


 

2009

 

2008

 

2007

Gas:

 

 

 

 

 

Production (Bcf)

 299.7 

 

 192.3 

 

 109.9 

Average sales price (per Mcf), including hedges

 $              5.30 

 

 $              7.52 

 

 $              6.80 

Average sales price (per Mcf), excluding hedges

 $              3.34 

 

 $              7.73 

 

 $              6.16 

 

 

 

 

 

 

Oil:

 

 

 

 

 

Production (MBbls)

 124 

 

 385 

 

 614 

Average sales price (per Bbl)

 $            54.99 

 

 $          107.18 

 

 $            69.12 

 

 

 

 

 

 

Average Production Cost:

 

 

 

 

 

Cost, excluding ad valorem and severance taxes (per Mcfe)

 $              0.77 

 

 $              0.89 

 

 $              0.73 


During 2009, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas Reserves,” with the U.S. Department of Energy.  The basis for reporting reserves on Form 23 is not comparable to the reserve data included in Note 4 to the consolidated financial statements in Item 8 to this Form 10-K. The primary differences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we are the operator.

Miles of Pipe

At December 31, 2009, our Midstream Services segment had 1,137 miles and 21 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.

38 SWN


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ITEM 3.  LEGAL PROCEEDINGS  

We are subject to laws and regulations relating to the protection of the environment. Our policy is to accrue environmental and cleanup related costs of a non-capital nature when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position 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.   


EXECUTIVE OFFICERS OF THE REGISTRANT

Name

Officer Position

Age

Years Served as Officer

Harold M. Korell

Executive Chairman of the Board

65

13

Steven L. Mueller

President and Chief Executive Officer

56

1

Greg D. Kerley

Executive Vice President and Chief Financial Officer

54

20

Mark K. Boling

Executive Vice President, General Counsel and Secretary

52

8

Gene A. Hammons

President, Southwestern Midstream Services Company

64

5


Mr. Korell was appointed Executive Chairman of the Board of Directors in May 2009 and has served as the Chairman of the Board of Directors since May 2002. Mr. Korell also served as our Chief Executive Officer from January 1999 to May 2009 and 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 Chief Executive Officer in May 2009 and was subsequently elected to the Board of Directors in July 2009. Mr. Mueller joined us as President and Chief Operating Officer in June 2008. He joined us from CDX Gas, LLC, where he was employed as Executive Vice President from September 2007 to May 2008.  In December 2008, CDX Gas, LLC voluntarily filed for bankruptcy.  In 2009, CDX emerged from bankruptcy and resumed operations as Vitruvian Exploration LLC.  From 2001 until 2007, Mr. Mueller served first as the Senior Vice President and General Manager Onshore and later as the Executive Vice President and Chief Operating Officer of The Houston Exploration Company.  A graduate of the Colorado School of Mines, Mr. Mueller has over 30 years of experience in the oil and 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.

39 SWN


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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.

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, 2010, the closing price of our stock was $42.49 and we had 2,815 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

 

2009

 

2008

 

2007

March 31..................

 

$   34.14 

 

$   25.99 

 

$    34.07 

 

$    24.82 

 

$    20.64 

 

$    16.44 

June 30.....................

 

$   45.65 

 

$   30.01 

 

$    48.69 

 

$    33.77 

 

$    25.09 

 

$    20.69 

September 30...........

 

$   45.08 

 

$   35.39 

 

$    48.53 

 

$    27.91 

 

$    22.85 

 

$    18.00 

December 31............

 

$   50.62 

 

$   40.28 

 

$    37.22 

 

$    20.81 

 

$    28.27 

 

$    21.26 


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 2009.  The increase in common stock in treasury in 2009 is due to an increase in shares held on behalf of participants in a non-qualified deferred compensation supplemental retirement savings plan. We refer you to Note 12 “Equity” to our consolidated financial statements in Item 8 of Part II.


Recent Sales of Unregistered Equity Securities

 

We did not sell any unregistered equity securities during 2009.

 

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STOCK PERFORMANCE GRAPH


The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index.  The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2004, and that all dividends were reinvested.  The stock performance shown on the graph below is not indicative of future price performance.


 

 

 

Southwestern Energy Company

Dow Jones U.S. Exploration & Production

 

S&P 500 Index


 

12/31/04

 

12/31/05

 

12/31/06

 

12/31/07

 

12/31/08

 

12/31/09

Southwestern Energy Company

 100 

 

 284 

 

 277 

 

 440 

 

 457 

 

 761 

Dow Jones U.S. Exploration & Production

 100 

 

 165 

 

 174 

 

 250 

 

 150 

 

 211 

S&P 500 Index

 100 

 

 105 

 

 121 

 

 128 

 

 81 

 

 102 


41 SWN


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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, 2009. 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.”


 

2009

 

2008

 

2007

 

2006

 

2005

 

(in thousands except share, per share, stockholder data and percentages)

Financial Review

 

 

 

 

 

 

 

 

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Exploration and production

$  1,593,231 

 

$    1,491,302 

 

$       795,944 

 

$       491,545 

 

$       403,234 

Midstream services

 1,603,332 

 

 2,173,971 

 

 961,994 

 

 475,207 

 

 459,890 

Gas distribution and other

 687 

 

 118,399 

 

 174,914 

 

 172,655 

 

 179,375 

Intersegment revenues

 (1,051,471)

 

 (1,472,120)

 

 (677,721)

 

 (376,295)

 

 (366,170)

 

 2,145,779 

 

 2,311,552 

 

 1,255,131 

 

 763,112 

 

 676,329 

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

Gas purchases – midstream services

 482,836 

 

 710,129 

 

 306,336 

 

 128,387 

 

 124,730 

Gas purchases – gas distribution

 — 

 

 61,439 

 

 85,445 

 

 79,363 

 

 82,689 

Operating and general

 259,159 

 

 209,536 

 

 166,095 

 

 132,691 

 

 101,500 

Depreciation, depletion and amortization

 493,658 

 

 414,408 

 

 293,914 

 

 151,290 

 

 96,211 

Impairment of natural gas and oil properties

 907,812 

 

 — 

 

 — 

 

 — 

 

 — 

Taxes, other than income taxes

 37,280 

 

 29,272 

 

 21,875 

 

 25,109 

 

 25,279 

 

 2,180,745 

 

 1,424,784 

 

 873,665 

 

 516,840 

 

 430,409 

Operating income (loss)

 (34,966)

 

 886,768 

 

 381,466 

 

 246,272 

 

 245,920 

 

 

 

 

 

 

 

 

 

 

Interest expense, net

 18,638 

 

 28,904 

 

 23,873 

 

 679 

 

 15,040 

Other income (loss)

 1,449 

 

 4,404 

 

 (219)

 

 17,079 

 

 4,784 

Gain on sale of utility assets

 — 

 

 57,264 

 

 — 

 

 — 

 

 — 

Income (loss) before income taxes

 (52,155)

 

 919,532 

 

 357,374 

 

 262,672 

 

 235,664 

Provision (benefit) for income taxes:

 

 

 

 

 

 

 

 

 

Current

 (64,969)

 

 122,000 

 

 — 

 

 — 

 

 — 

Deferred

 48,606 

 

 228,999 

 

 135,855 

 

 99,399 

 

 86,431 

 

 (16,363)

 

 350,999 

 

 135,855 

 

 99,399 

 

 86,431 

Net income (loss)

 (35,792)

 

 568,533 

 

 221,519 

 

 163,273 

 

 149,233 

Less: net income (loss) attributable to noncontrolling interest

 (142)

 

 587 

 

 345 

 

 637 

 

 1,473 

Net income (loss) attributable to Southwestern Energy

$      (35,650)

 

$       567,946 

 

$       221,174 

 

$       162,636 

 

$       147,760 

Return on equity(1)

 (1.5%)

 

 22.6%

 

 13.3%

 

 11.2%

 

 13.2%

Net cash provided by operating activities

$  1,359,376 

 

$    1,160,809 

 

$       622,735 

 

$       429,937 

 

$       304,482 

Net cash used in investing activities

$(1,780,604)

 

$      (792,078)

 

$   (1,513,497)

 

$     (630,006)

 

$      (452,918)

Net cash provided by (used in) financing activities

$     238,135 

 

$      (174,286)

 

$       849,667 

 

$         19,291 

 

$       370,906 

 

 

 

 

 

 

 

 

 

 

Common Stock Statistics (2)

 

 

 

 

 

 

 

 

 

Earnings per share:

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to Southwestern stockholders – Basic

$          (0.10)

 

$             1.66 

 

$             0.65 

 

$             0.49 

 

$             0.49 

Net income (loss) attributable to Southwestern stockholders – Diluted

$          (0.10)

 

$             1.64 

 

$             0.64 

 

$             0.47 

 

$             0.47 

Cash dividends declared and paid per share

$                — 

 

$                — 

 

$                — 

 

$                — 

 

$                — 

Book value per average diluted share(1)

$            6.82 

 

$             7.27 

 

$             4.77 

 

$             4.22 

 

$             3.59 

Market price at year-end

$          48.20 

 

$           28.97 

 

$           27.86 

 

$           17.52 

 

$           17.97 

Number of stockholders of record at year-end

 2,639 

 

 2,497 

 

 2,275 

 

 2,412 

 

 2,126 

Average diluted shares outstanding

 343,420,568 

 

 346,245,938 

 

 347,442,660 

 

 342,575,500 

 

 312,618,078 


(1) The return on equity and the book value per average diluted share calculations have been recalculated for 2008, 2007, 2006 and 2005 and now include an addition to equity for the Company’s noncontrolling interest in partnership.

(2) Share and per share amounts in 2007, 2006 and 2005 have been restated to reflect the two-for-one stock split effected in March 2008.  

 

42 SWN


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2009

 

2008

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

Capitalization (in thousands)

 

 

 

 

 

 

 

 

 

Total debt

$     998,700 

 

$       735,400 

 

$        978,800 

 

$       137,800 

 

$       100,000 

Total equity

 2,340,981 

 

 2,517,963 

 

 1,657,070 

 

 1,445,677 

 

 1,121,917 

Total capitalization

$  3,339,681 

 

$    3,253,363 

 

$     2,635,870 

 

$    1,583,477 

 

$    1,221,917 

Total assets

$  4,770,250 

 

$    4,760,158 

 

$     3,622,716 

 

$    2,379,069 

 

$    1,868,524 

Capitalization ratios:

 

 

 

 

 

 

 

 

 

Debt

 29.9%

 

 22.6%

 

 37.1%

 

 8.7%

 

 8.2%

Equity

 70.1%

 

 77.4%

 

 62.9%

 

 91.3%

 

 91.8%

 

 

 

 

 

 

 

 

 

 

Capital Investments (in millions) (1)

 

 

 

 

 

 

 

 

 

Exploration and production:

 

 

 

 

 

 

 

 

 

Exploration and development

$      1,556.3 

 

$        1,569.1 

 

$         1,375.2 

 

$           767.4 

 

$           416.2 

Drilling rigs and related equipment (2)

 9.2 

 

 26.7 

 

 4.5 

 

 93.6 

 

 35.1 

 

 1,565.5 

 

 1,595.8 

 

 1,379.7 

 

 861.0 

 

 451.3 

Midstream services

 214.2 

 

 183.0 

 

 107.4 

 

 48.7 

 

 15.8 

Gas distribution (3)

 — 

 

 3.6 

 

 11.4 

 

 11.2 

 

 10.9 

Other

 29.4 

 

 13.8 

 

 4.6 

 

 21.5 

 

 5.1 

 

$      1,809.1 

 

$        1,796.2 

 

$         1,503.1 

 

$           942.4 

 

$           483.1 

 

 

 

 

 

 

 

 

 

 

Exploration and Production

 

 

 

 

 

 

 

 

 

Natural gas:

 

 

 

 

 

 

 

 

 

Production, Bcf

 299.7 

 

 192.3 

 

 109.9 

 

 68.1 

 

 56.8 

Average price per Mcf, including hedges

$            5.30 

 

$             7.52 

 

$              6.80 

 

$             6.55 

 

$             6.51 

Average price per Mcf, excluding hedges

$            3.34 

 

$             7.73 

 

$              6.16 

 

$             6.37 

 

$             7.73 

Oil:

 

 

 

 

 

 

 

 

 

Production, MBbls

 124 

 

 385 

 

 614 

 

 698 

 

 705 

Average price per barrel, including hedges

$          54.99 

 

$         107.18 

 

$            69.12 

 

$           58.36 

 

$           42.62 

Average price per barrel, excluding hedges

$          54.99 

 

$         107.18 

 

$            69.12 

 

$           63.17 

 

$           54.37 

Total gas and oil production, Bcfe

 300.4 

 

 194.6 

 

 113.6 

 

 72.3 

 

 61.0 

Lease operating expenses per Mcfe

$            0.77 

 

$             0.89 

 

$              0.73 

 

$             0.66 

 

$             0.48 

General and administrative expenses per Mcfe

$            0.35 

 

$             0.41 

 

$              0.48 

 

$             0.58 

 

$             0.46 

Taxes, other than income taxes per Mcfe

$            0.11 

 

$             0.13 

 

$              0.16 

 

$             0.30 

 

$             0.37 

Proved reserves at year-end:

 

 

 

 

 

 

 

 

 

Natural gas, Bcf

 3,650 

 

 2,176 

 

 1,397 

 

 979 

 

 772 

Oil, MMBbls

 

 

 2 

 

 9 

 

 8 

 

 9 

Total reserves, Bcfe

 3,657 

 

 2,185 

 

 1,450 

 

 1,026 

 

 827 

 

 

 

 

 

 

 

 

 

 

Midstream Services

 

 

 

 

 

 

 

 

 

Gas volumes marketed, Bcf

 382.5 

 

 258.0 

 

 145.7 

 

 72.7 

 

 61.9 

Gas volumes gathered, Bcf

 387.1 

 

 224.1 

 

 78.7 

 

 14.6 

 

 2.3 

 

 

 

 

 

 

 

 

 

 

Natural Gas Distribution (3)

 

 

 

 

 

 

 

 

 

Sales and transportation volumes, Bcf

 n/a 

 

 14.5 

 

 23.6 

 

 21.8 

 

 23.2 

Off-system transportation, Bcf (4)

 n/a 

 

 — 

 

 0.3 

 

 0.1 

 

 — 

Total volumes delivered

 n/a 

 

 14.5 

 

 23.9 

 

 21.9 

 

 23.2 

Customers at year-end:

 

 

 

 

 

 

 

 

 

Residential

 n/a 

 

 n/a 

 

 134,616 

 

 133,679 

 

 130,654 

Commercial

 n/a 

 

 n/a 

 

 17,180 

 

 17,151 

 

 16,996 

Industrial

 n/a 

 

 n/a 

 

 192 

 

 173 

 

 170 

 

 n/a 

 

 n/a 

 

 151,988 

 

 151,003 

 

 147,820 

Annual degree days

 n/a 

 

 n/a 

 

 3,699 

 

 3,413 

 

 3,744 

Percent of normal

 n/a 

 

 n/a 

 

 91%

 

 83%

 

 91%

(1) Capital investments include increases of $12.2 million for 2009, $36.2 million for 2008, a reduction of $20.6 million for 2007 and increases of $88.9 million and $28.1 million for 2006 and 2005, 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 and, as a result, we no longer have any natural gas distribution operations. The 2008 column reflects results for the first six months of 2008 for Arkansas Western Gas.

(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 “Item 6. Selected Financial Data” and our consolidated financial statements and the related notes included in this Form 10-K.

OVERVIEW

Background


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


We are focused on providing long-term growth in the net asset value of our business, which we achieve in our E&P business through the drillbit.  We derive the vast majority of our operating income and cash flow from the natural gas production of our E&P business and expect this to continue in the future.  We expect that growth in our operating income and revenues will primarily depend on natural gas prices and our ability to increase our natural gas production.  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 as evidenced by New York Mercantile Exchange natural gas prices ranging from highs of $13.58 per Mcf in 2008 to lows of $2.51 per Mcf in 2009.  Natural gas prices fluctuate due to a variety of factors we cannot control or predict.  These factors, which include weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which in turn determines the sale prices for our production.  In addition to the factors identified above, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices.

Recent Financial and Operating Results


We reported a net loss attributable to Southwestern Energy of $35.7 million in 2009, or $0.10 per diluted share, down from net income attributable to Southwestern Energy of $567.9 million, or $1.64 per diluted share, in 2008. The loss in 2009 resulted from the recognition of a $907.8 million, or $558.3 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties recorded during the three months ended March 31, 2009.  The ceiling test impairment was recognized as a result of a significant decline in natural gas prices. We reported net income attributable to Southwestern Energy of $567.9 million in 2008, or $1.64 per diluted share, up 157% from 2007. Net income attributable to Southwestern Energy in 2008 included a $35.4 million net of tax gain, or $0.10 per diluted share, related to the sale of our utility subsidiary that closed on July 1, 2008.  Excluding the $35.4 million gain on the sale of the utility, the increase in net income attributable to Southwestern Energy in 2008 was the result of a $1,056.4 million increase in revenues, partially offset by an increase in operating costs and expenses of $551.1 million and an increase in interest expense of $5.0 million. Our cash flow from operating activities increased 17% to $1,359.4 million in 2009 and increased 86% to $1,160.8 million in 2008, due to increases in net income adjusted for non-cash expenses.


In 2009, our gas and oil production increased 54% to 300.4 Bcfe, up from 194.6 Bcfe in 2008.  The 105.8 Bcfe increase in our 2009 production resulted from a 109.0 Bcf increase in net production from our Fayetteville Shale play and a 3.3 Bcfe increase in net production from our East Texas properties, which more than offset a combined 6.5 Bcfe decrease in net production arising from decreased production from our Arkoma and other properties and the sale of our Permian Basin and Gulf Coast properties in 2008. In 2008, our gas and oil production increased to 194.6 Bcfe, up from 113.6 Bcfe in 2007.  We are targeting 2010 gas and oil production of 400.0 to 410.0 Bcfe, an increase of approximately 35% over our 2009 production. Our year-end reserves grew 67% in 2009 to 3,657 Bcfe, up from 2,185 Bcfe at the end of 2008, primarily as a result of the continued development of our Fayetteville Shale play.


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Our E&P segment reported an operating loss of $157.7 million in 2009, down from operating income of $813.5 million in 2008 and $358.1 million in 2007. The operating loss for our E&P segment was primarily the result of the $907.8 million non-cash ceiling test impairment of our natural gas and oil properties.  Operating income for our E&P segment increased in 2008 due to an increase in revenues of $695.4 million resulting from higher gas production volumes and increased product prices, partially offset by an increase in operating costs and expenses of $239.9 million.


Operating income for our Midstream Services segment was $122.6 million in 2009, compared to $62.3 million in 2008 and $13.2 million in 2007. Operating income for our Midstream Services segment increased in 2009 due to an increase of $90.7 million in gathering revenues and an increase of $6.3 million in the margin generated from our natural gas marketing activities, which were partially offset by a $36.7 million increase in operating costs and expenses, exclusive of purchased gas costs.  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 Natural Gas Distribution segment was $10.7 million for the first six months in 2008, prior to the sale of Arkansas Western Gas, compared to $10.0 million in 2007.


Outlook


We believe the outlook for our business is favorable despite the uncertainties of natural gas prices in the United States and the overall economic recovery. Our resource base, financial strength and disciplined investment of capital provide us with an opportunity to exploit and develop our position in the Fayetteville Shale play, maximize efficiency through economies of scale in our key operating areas, enhance our overall returns through expansion of our Midstream Services operations and grow through new exploration and development activities. Our capital investment plan for 2010 is based on our expectation that natural gas prices will remain near or above 2009 price levels and the realized sales price for our production continues to meet our targeted return of $1.30 of discounted pre-tax PVI for each dollar we invest in our E&P projects.

 

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RESULTS OF OPERATIONS

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


Exploration and Production

 

Year Ended December 31,

 

2009

 

2008

 

2007

 

 

 

 

 

 

Revenues (in thousands)

$   1,593,231 

 

$      1,491,302 

 

$         795,944 

Impairment of natural gas and oil properties (in thousands)

$       907,812 

 

$                  — 

 

$                  — 

Operating costs and expenses(in thousands)

$       843,144 

 

$         677,798 

 

$         437,865 

Operating income (loss) (in thousands)

$     (157,725)

 

$         813,504 

 

$         358,079 

 

 

 

 

 

 

Gas production (Bcf)

 299.7 

 

 192.3 

 

 109.9 

Oil production (MBbls)

 124 

 

 385 

 

 614 

Total production (Bcfe)

 300.4 

 

 194.6 

 

 113.6 

 

 

 

 

 

 

Average gas price per Mcf, including hedges

$              5.30 

 

$               7.52 

 

$               6.80 

Average gas price per Mcf, excluding hedges

$              3.34 

 

$               7.73 

 

$               6.16 

Average oil price per Bbl

$           54.99 

 

$           107.18 

 

$             69.12 

 

 

 

 

 

 

Average unit costs per Mcfe:

 

 

 

 

 

Lease operating expenses

$              0.77 

 

$               0.89 

 

$               0.73 

General and administrative expenses

$              0.35 

 

$               0.41 

 

$               0.48 

Taxes, other than income taxes

$              0.11 

 

$               0.13 

 

$               0.16 

Full cost pool amortization

$              1.51 

 

$               1.99 

 

$               2.41 

 

Revenues


Revenues for our E&P segment were up $101.9 million, or 7%, in 2009, compared to the prior year. Higher production volumes in 2009 increased revenues by approximately $779.5 million, which were partially offset by a $669.9 million decrease in revenue attributable to lower realized gas and oil prices.  E&P revenues were up $695.4 million, or 87%, in 2008, compared to 2007, of which approximately $544.3 million was attributable to an increase in production volumes and $152.4 million 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 widely fluctuate. As of February 25, 2010, we had hedged 66.0 Bcf of 2010 gas production and 37.3 Bcf of 2011 gas production to limit our exposure to price fluctuations. For more information about our derivatives and risk management activities, we refer you to Note 5 to the consolidated financial statements included in this Form 10-K and to “Commodity Prices” below for additional information.  


Production


In 2009, our gas and oil production increased 54% to 300.4 Bcfe, up from 194.6 Bcfe in 2008.  The 105.8 Bcfe increase in our 2009 production resulted from a 109.0 Bcf increase in net production from our Fayetteville Shale play and a 3.3 Bcfe increase in net production from our East Texas properties, which more than offset a combined 6.5 Bcfe decrease in net production from our Arkoma Basin and other properties and the sale of our Permian Basin and Gulf Coast properties.  Gas and oil production was up approximately 71% to 194.6 Bcfe in 2008, as compared to 2007, 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 of 2.3 Bcfe, which more than offset decreases in net production due to the sale of our Permian Basin and Gulf Coast properties. Our net production from the Fayetteville Shale play was 243.5 Bcf in 2009, up from 134.5 Bcf in 2008 and 53.5 Bcf in 2007.


Prior to our July 1, 2008 sale of Arkansas Western Gas, intersegment gas sales to Arkansas Western Gas totaled 4.3 Bcf for the first six months of 2008 and 4.8 Bcf for the year ended December 31, 2007. Future increases in demand for our gas production are expected to come from sales to major and small energy companies, utilities and industrial consumers of natural gas.

 

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We are targeting 2010 gas and oil production of 400.0 to 410.0 Bcfe, an increase of approximately 35% over our 2009 production using the midpoint of the 2010 target range. Approximately 344.0 to 352.0 Bcf of our 2010 targeted gas production is projected to come from our activities in the Fayetteville Shale play. Although we expect production volumes in 2010 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


The average price realized for our gas production, including the effects of hedges, decreased 30% to $5.30 per Mcf in 2009 and increased 11% to $7.52 per Mcf in 2008.  The change in the average price realized reflects changes in average market prices and the effects of our price hedging activities.  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 5 to the consolidated financial statements for additional discussion about our derivatives and risk management activities).


Our hedging activities increased the average gas price $1.96 per Mcf in 2009, compared to a decrease of $0.21 per Mcf in 2008 and an increase $0.64 per Mcf in 2007. In recent years, locational differences in market prices for natural gas have been wider than historically experienced. Disregarding the impact of hedges, from 2005 through 2007, the average price received for our gas production was approximately $0.50 to $1.00 per Mcf lower than average NYMEX spot market prices primarily due to the locational market differentials. However, during 2009 and 2008, widening market differentials caused the difference in our annual average price received for our gas production to range from approximately $0.65 to $1.30 per Mcf lower than market prices.  The discount was at its highest in late 2008, due to increased production in the Fayetteville Shale for which there was not sufficient transportation to other markets as a result of the delay in the completion of the Boardwalk Pipeline. Since the completion of the Boardwalk Pipeline, the locational differences in the market prices for our gas production has narrowed. Assuming a NYMEX commodity price for 2010 of $5.00 per Mcf of gas, the average price received for our gas production is expected to be approximately $0.10 to $0.20 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges. At December 31, 2009, we had basis protected on approximately 140 Bcf of our 2010 expected gas production through financial hedging activities and physical sales arrangements at a differential to NYMEX gas prices of approximately $0.15 per Mcf.  Our E&P segment receives a sales price for our natural gas at a discount to NYMEX spot prices due to locational basis differentials, while transportation charges and fuel charges also reduce the price received.  In 2010, we expect to pay average third-party transportation charges in the range of $0.25 to $0.32 per Mcf and average fuel charges in the range of 0.25% to 1.00% of our sales price for natural gas.


In addition to the basis hedges discussed above, at December 31, 2009, we had NYMEX commodity price hedges in place on 66.0 Bcf of our 2010 expected future gas production and 30.0 Bcf of our 2011 expected future gas production.


We realized an average price of $54.99 per barrel for our oil production for the year ended December 31, 2009, down approximately 49% from the prior year. The 2008 average realized price of $107.18 per barrel was up 55% from 2007. We did not hedge any of our 2009, 2008 or 2007 oil production.


Operating Income

 

We recorded an operating loss from our E&P segment of $157.7 million for 2009, which represents a decline of $971.2 million, or 119%, from 2008.  The $971.2 million decrease in operating income was the result of a $907.8 million non-cash ceiling test impairment recorded in the first quarter resulting from lower natural gas prices, an increase in other operating costs and expenses of $165.3 million, or 24%, resulting from our significant production growth, which were partially offset by a net increase in revenue of $101.9 million, or 7%, as increased gas production volumes more than offset the decline in gas prices from the prior year.  In 2008, operating income increased 127% to $813.5 million from $358.1 million in 2007, as revenues increased $695.4 million, or 87%, due to higher gas production and higher gas prices which were partially offset by an increase in operating costs and expenses of $239.9 million, or 55%.

 

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Operating Costs and Expenses


Lease operating expenses per Mcfe for the E&P segment were $0.77 in 2009, compared to $0.89 in 2008 and $0.73 in 2007. Lease operating expenses per unit of production decreased in 2009 primarily due to the impact that lower natural gas prices had on the cost of compressor fuel in 2009. Lease operating expenses per unit of production increased in 2008, as compared to 2007, primarily due to higher per unit operating costs associated with our Fayetteville Shale operations, including the impact of higher natural gas prices on the cost of compressor fuel in 2008.  We expect our per unit operating cost for this segment to range between $0.87 and $0.92 per Mcfe in 2010.


General and administrative expenses for the E&P segment were $0.35 per Mcfe in 2009, down from $0.41 per Mcfe in 2008 and $0.48 per Mcfe in 2007. The decreases in general and administrative costs per Mcfe in 2009 and 2008 were due to the effects of our increased production volumes. In total, general and administrative expenses for the E&P segment were $105.0 million in 2009, $80.2 million in 2008 and $54.8 million in 2007.  The increases in general and administrative expenses since 2007 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 79%, of the 2009 increase and $19.7 million, or 78%, of the 2008 increase. We added 261 new E&P employees during 2009, compared to 145 employees added in 2008.

We expect our per unit cost for general and administrative expenses in 2010 to range between $0.32 and $0.37 per Mcfe.  The expected decrease in per unit costs in 2010 is due to an anticipated increase in 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, amount of stock-based compensation expense and the amount of incentive compensation paid to our employees. For eligible employees, a portion of incentive compensation is based on the achievement of certain operating and performance results, including production, proved reserve additions, present value added for each dollar of capital invested, and lease operating expenses and general and administrative expenses per unit of production, while another portion is discretionary based upon an employee’s performance. Additional discretionary awards may also be awarded under the incentive compensation plan.

Taxes other than income taxes per Mcfe were $0.11 in 2009, $0.13 in 2008 and $0.16 in 2007, and vary from period to period due to changes in severance and ad valorem taxes that result from the mix of our production volumes and fluctuations in commodity prices. Effective January 1, 2009, the State of Arkansas increased the severance tax on natural gas wells, new discovery gas wells and gas wells that produce below a specified level.  The new severance tax rates increased the severance taxes we pay with respect to all of our production within the State of Arkansas, including our Fayetteville Shale operations, and impacted our results of operations by increasing taxes other than income by $11.1 million, or $0.04 per Mcfe, in 2009 compared to 2008. Additionally, we recognized $3.3 million, or $0.01 per Mcfe, in 2009 for severance tax refunds related to our East Texas production, compared to $5.0 million, or $0.03 per Mcfe, in 2008.


Our full cost pool amortization rate averaged $1.51 per Mcfe for 2009, $1.99 per Mcfe for 2008 and $2.41 per Mcfe for 2007. The decline in the average amortization rate for 2009 was primarily the result of the $907.8 million non-cash ceiling test impairment recorded in the first quarter of 2009 as well as sales of natural gas and oil properties in 2008, the proceeds of which were credited to the full cost pool.  The decline in the average amortization rate for 2008 was primarily the result of the sales of oil and gas properties in 2008.  The amortization rate is impacted by the timing and amount of reserve additions and the costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from full cost ceiling tests, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserves attributed to our Fayetteville Shale play.


Unevaluated costs excluded from amortization were $595.4 million at the end of 2009, compared to $540.6 million at the end of 2008 and $372.4 million at the end of 2007. In 2009, the increase in unevaluated costs primarily resulted from a $61.8 million increase in our acquisition of properties and seismic costs (with $28.3 million of the increase related to our Fayetteville Shale play) offset by a $10.4 million decrease in our drilling activity.  See Note 4 to the consolidated financial statements for additional information regarding our unevaluated costs excluded from amortization. The timing and amount of production and reserve additions 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.

 

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Midstream Services

 

Year Ended December 31,

 

2009

 

2008

 

2007

 

(in millions, except volumes)

 

 

 

 

 

 

Revenues – marketing

$     1,397.7 

 

$       2,059.1 

 

$          924.3 

Revenues – gathering

$         205.6 

 

$          114.9 

 

$            37.7 

Gas purchases – marketing

$     1,375.8 

 

$       2,043.5 

 

$          915.1 

Operating costs and expenses

$         104.9 

 

$            68.2 

 

$            33.7 

Operating income

$         122.6 

 

$            62.3 

 

$            13.2 

Gas volumes marketed (Bcf)

 382.5 

 

 258.0 

 

 145.7 

Gas volumes gathered (Bcf)

 387.1 

 

 224.1 

 

 78.7 


Revenues


Revenues from our marketing activities were down 32% to $1,397.7 million for 2009 compared to 2008. The decrease in marketing revenues for 2009 resulted from a decrease in the prices received for volumes marketed and was partially offset by an increase in gas volumes marketed. Revenues from our marketing activities were up 123% to $2,059.1 million for 2008 compared to 2007. The increase in marketing revenues for 2008 resulted from increases in both gas volumes marketed and prices received for volumes marketed. The price received for volumes marketed decreased 54% in 2009 compared to 2008, and increased 26% in 2008 compared to 2007. Volumes marketed increased 48% in 2009 compared to 2008, and increased 77% in 2008 compared to 2007. Of the total volumes marketed, production from our E&P operated wells accounted for 92% in 2009, 96% in 2008 and 89% in 2007. Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in gas purchase expenses.


Revenues from our gathering activities were up 79% to $205.6 million for 2009 compared to 2008, and were up 205% to $114.9 million for 2008 compared to 2007. Substantially all of the increases in gathering revenues for 2009 and 2008 resulted from increases in the volumes gathered in our Fayetteville Shale play.  Total volumes gathered increased 73% in 2009 compared to 2008 and increased 185% in 2008 compared to 2007.  Gathering volumes, revenues and expenses for this segment are expected to continue to grow as production from our Fayetteville Shale play increases.


Operating Income


Operating income from our Midstream Services segment increased 97% to $122.6 million in 2009 due to an increase of $90.7 million in gathering revenues and an increase of $6.3 million in the margin generated from our natural gas marketing activities, which were partially offset by a $36.7 million increase in operating costs and expenses, exclusive of purchased gas costs.  Operating income from our Midstream Services segment increased 371% to $62.3 million 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.  


The margin generated from natural gas marketing activities was $21.9 million for 2009, compared to $15.6 million for 2008 and $9.2 million for 2007.  Margins may fluctuate depending on the prices paid for commodities and the ultimate disposition of those commodities. The increases in volumes marketed in 2009 and 2008, 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. For more information about our derivatives and risk management activities, we refer you to “Quantitative and Qualitative Disclosures about Market Risk” and Note 5 to the consolidated financial statements for additional information.

 

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Natural Gas Distribution

 

Year Ended December 31,

 

2009

 

2008(1)

 

2007

 

($ in thousands, except for Bcf and per Mcf amounts)

 

 

 

 

 

 

Revenues

$                    — 

 

$           117,710 

 

$           174,466 

Gas purchases

$                    — 

 

$             79,120 

 

$           111,338 

Operating costs and expenses

$                    — 

 

$             27,857 

 

$             53,168 

Operating income

$                    — 

 

$             10,733 

 

$               9,960 

 

 

 

 

 

 

Sales and end-use transportation deliveries (Bcf)

n/a 

 

 14.5 

 

 23.6 

 

 

 

 

 

 

Sales customers at year-end

n/a 

 

n/a 

 

 151,988 

Average sales rate per Mcf

n/a 

 

$               11.61 

 

$               11.07 

 

 

 

 

 

 

Annual heating weather – degree days

n/a 

 

n/a 

 

 3,699 

Percent of normal

n/a 

 

n/a 

 

 91%


(1)

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


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


Interest Expense and Interest Income

Interest expense, net of capitalization, was $18.6 million in 2009, a decrease of $10.3 million compared to 2008 primarily due to an increase in capitalized interest and a decrease in our weighted average interest rate during 2009. Our weighted average interest rate decreased during 2009 as a result of the redemption of our 7.625% Senior Notes and an increase in our Credit Facility borrowings which had a 2009 weighted average interest rate of 1.16%.  Interest capitalized increased to $40.2 million in 2009, up from $34.5 million in 2008, 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 $595.4 million at December 31, 2009, compared to $540.6 million at December 31, 2008.


In 2008, interest expense, net of capitalization, was $28.9 million, an increase of $5.0 million compared to 2007 amounts primarily due to an increase in our average indebtedness resulting from our increased capital investments in 2008. Interest capitalized increased to $34.5 million in 2008, up from $13.8 million in 2007, as our costs excluded from amortization in the E&P segment increased along with the overall increased level of our capital investments. Costs excluded from amortization in the E&P segment were $540.6 million at December 31, 2008, compared to $372.4 million at December 31, 2007.


During 2009, 2008 and 2007, we earned interest income of $0.4 million, $4.4 million and $0.1 million, respectively, related to our cash investments.  These amounts are recorded in other income on the Statements of Operations.

Income Taxes

Our effective tax rates were 31.5% in 2009, 38.2% in 2008 and 38.1% in 2007. The decrease in our 2009 effective tax rate resulted from our permanent tax differences comprising a larger percentage of our before tax operating results than in 2008. Our effective tax rate excluding the $907.8 million non-cash ceiling test impairment of our natural gas and oil properties would have been 39.0%. In general, differences between our effective tax rate and the statutory tax rate of 35% primarily result from the effect of certain state income taxes and permanent items attributable to book-tax differences.    

 

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Stock-Based Compensation Expense

 

We recognized expense of $10.2 million and capitalized $5.9 million for stock-based compensation in 2009, compared to $7.6 million expensed and $3.9 million capitalized in 2008 and $5.4 million expensed and $2.6 million capitalized in 2007. We refer you to Note 13 to the consolidated financial statements for additional discussion of our equity based compensation plans.  


LIQUIDITY AND CAPITAL RESOURCES


We depend primarily on internally-generated funds, our Credit Facility and funds accessed through debt and equity markets. We may borrow up to $1.0 billion under our Credit Facility from time to time. The amount available under our 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, 2009, we had $324.5 million in borrowings outstanding under our Credit Facility compared to no indebtedness at December 31, 2008. During 2010, assuming gas prices remain at current levels, we expect to draw on a portion of the funds available under the Credit Facility to fund our planned capital investments (discussed below under “Capital Investments”), which are expected to exceed the net cash generated by our operations.  We refer you to Note 7 to the consolidated financial statements included in this Form 10-K and the section below under “Financing Requirements” for additional discussion of our Credit Facility.


Net cash provided by operating activities increased 17% to $1.4 billion in 2009, due to an increase in net income adjusted for non-cash expenses which was partially offset by changes in working capital accounts.  Net cash provided by operating activities increased 86% to $1.2 billion in 2008, due to a $516.3 million increase in net income attributable to Southwestern Energy and adjustments for non-cash expenses.  For 2009, requirements for our capital investments were funded from our cash generated by operating activities, our Credit Facility and our 2009 beginning of the year cash and cash equivalents balance. Net cash from operating activities provided 76% of our cash requirements for capital investments in 2009, 66% in 2008 and 41% in 2007.


At December 31, 2009, our capital structure consisted of 30% debt and 70% equity. We believe that our operating cash flow and available funds under our Credit Facility will be adequate to meet our capital and operating requirements for 2010. The credit status of the financial institutions participating in our Credit Facility could adversely impact our ability to borrow funds under the Credit Facility. While we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet its obligation.


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


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


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

 

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Capital Investments

Our capital investments were approximately $1.8 billion in 2009, approximately flat compared to 2008. Capital investments include an increase of $12.2 million in 2009, an increase of $36.2 million in 2008 and a reduction of $20.6 million in 2007 related to the change in accrued expenditures between years. Our E&P segment investments in 2009 were $1.6 billion, compared to $1.6 billion in 2008 and $1.4 billion in 2007.


 

2009

 

2008

 

2007

 

(in thousands)

Exploration and production

 

 

 

 

 

Exploration and development

$   1,556,260 

 

$      1,569,089 

 

$      1,375,204 

Drilling rigs and related equipment

 9,190 

 

 26,739 

 

 4,453 

 

 1,565,450 

 

 1,595,828 

 

 1,379,657 

Midstream services

 214,208 

 

 183,021 

 

 107,363 

Natural gas distribution

 — 

 

 3,574 

(1)

 11,375 

Other

 29,459 

 

 13,745 

 

 4,743 

 

$   1,809,117 

 

$      1,796,168 

 

$      1,503,138 

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

Our capital investments for 2010 are planned to be $2.1 billion, consisting of $1.7 billion for E&P, $270 million for Midstream Services and $95 million for corporate and other purposes. Of the approximate $2.1 billion, we expect to allocate approximately $1.5 billion to our Fayetteville Shale play. Our planned level of capital investments in 2010 is expected to allow us to continue our progress in the Fayetteville Shale and East Texas programs, begin drilling in the Marcellus Shale in Pennsylvania and explore and develop other existing gas and oil properties and generate new drilling prospects. As discussed above, our 2010 capital investment program is expected to be funded through cash flow from operations and borrowings under our Credit Facility. The planned capital program for 2010 is flexible and can be modified, including downward, if the low natural gas price environment persists for an extended period of time.  We will reevaluate our proposed investments as needed to take into account prevailing market conditions and if natural gas prices rebound in 2010, we could increase our planned investments and accelerate the development of our Fayetteville Shale play by utilizing additional drilling rigs.

Financing Requirements

Our total debt outstanding was $998.7 million at December 31, 2009, compared to $735.4 million at December 31, 2008. Our Credit Facility has a borrowing capacity of $1.0 billion, which may be increased up to $1.25 billion at any time upon our agreement with our existing or additional lenders. As of December 31, 2009, we had $324.5 million outstanding under our Credit Facility with a weighted average interest rate of 1.106%, compared to no indebtedness outstanding as of December 31, 2008.  The interest rate on our Credit Facility is calculated based upon our public debt rating and is currently 87.5 basis points over LIBOR. 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 Credit Facility contains covenants which impose certain restrictions on us. Under the Credit Facility, we must keep our total debt at or below 60% of our total capital, must maintain a certain level of equity and must maintain a ratio of EBITDA to interest expense of 3.5 or above. Our Credit Facility’s financial covenants with respect to capitalization percentages exclude the noncontrolling interest in equity, the effects of non-cash entries that result from any full cost ceiling impairments, hedging activities and our pension and other postretirement liabilities. Therefore, under our Credit Facility, our capital structure at December 31, 2009 would have been 26% debt and 74% equity. We were also in compliance with all of the covenants of our Credit Facility at December 31, 2009. Although we do not anticipate any violations of our financial covenants, our ability to comply with those covenants is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas and oil.  If we are unable to borrow under our Credit Facility, we would have to decrease our capital investment plans.


At December 31, 2009, our capital structure consisted of 30% debt and 70% equity. Our debt as a percentage of total capital increased throughout 2009, primarily due to our increased debt levels and our net loss attributable to Southwestern Energy of $35.7 million and other changes in equity for 2009. Equity at December 31, 2009 included an accumulated other comprehensive gain of $95.3 million related to our hedging activities and a loss for $11.0 million related to our pension and other postretirement liabilities. The amount recorded in equity for our hedging activities is based on current market values for our hedges at December 31, 2009 and does not necessarily reflect the value that we will

 

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receive or pay when the hedges are ultimately settled, nor does it take into account revenues to be received associated with the physical delivery of sales volumes hedged.


Our hedges allow us to ensure a certain level of cash flow to fund our operations.  At December 31, 2009, we had NYMEX commodity price hedges in place on 66.0 Bcf of our 2010 expected future gas production and 30.0 Bcf of our 2011 expected future gas production.  The amount of long-term debt we incur will be dependent upon commodity prices and our capital investment plans.


Off-Balance Sheet Arrangements

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


Contractual Obligations and Contingent Liabilities and Commitments


We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual obligations at December 31, 2009, were as follows:


Contractual Obligations:

 

Payments Due by Period

 

 

 

Less than

 

 

 

 

 

More than

 

Total

 

1 Year

 

1 to 3 Years

 

3 to 5 Years

 

5 Years

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

Demand charges(1)

$ 1,846,938 

 

$       106,839 

 

$       358,715 

 

$       389,500 

 

$       991,884 

Debt

 998,700 

 

 1,200 

 

 326,900 

 

 2,400 

 

 668,200 

Interest on senior notes

 431,215 

 

 53,897 

 

 104,545 

 

 100,015 

 

 172,758 

Operating leases(2)

 263,262 

 

 51,338 

 

 96,267 

 

 83,440 

 

 32,217 

Purchase obligations(3)

 71,493 

 

 71,493 

 

 — 

 

 — 

 

 — 

Compression services(4)

 68,509 

 

 25,418 

 

 36,728 

 

 6,363 

 

 — 

Operating agreements(5)

 6,482 

 

 6,482 

 

 — 

 

 — 

 

 — 

Other obligations(6)

 26,591 

 

 23,451 

 

 3,092 

 

 48 

 

 — 

 

$ 3,713,190 

 

$       340,118 

 

$       926,247 

 

$       581,766 

 

$    1,865,059 


(1)  Our Midstream Services segment has commitments for demand transportation charges, including approximately $1.0 billion related to the FEP pipeline which, although approved, is not expected to be in service until late 2010 or early 2011.  For purposes of this table, we have assumed an in-service date of October 1, 2010 for the FEP pipeline.

(2)  Operating leases include costs for compressors, aircraft, office space and equipment under non-cancelable operating leases expiring through 2018. Additionally, this includes $96.9 million for leases of 14 drilling rigs and related equipment through 2014.

(3)  Purchase obligations consist of outstanding purchase orders under existing agreements.  Our Midstream Services segment has outstanding purchase obligations of $46.4 million relating to compression units.

(4)  Our Midstream Services segment has commitments of approximately $61.9 million and our E&P segment has commitments of approximately $6.6 million for compression services associated primarily with our Fayetteville Shale play and our Overton operations.

(5)  Our E&P segment has commitments for up to $6.0 million in termination fees related to rig operator agreements.  

(6)  Our other significant contractual obligations include approximately $7.8 million for various information technology support and data subscription agreements, approximately $5.3 million for insurance premium financing, approximately $4.8 million related to seismic services and approximately $4.3 million for funding of benefit plans.

 

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

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Commitments and Contingent Liabilities

Substantially all of our employees are covered by defined benefit and postretirement benefit plans. We currently expect to contribute approximately $9.6 million to our pension plans and $0.1 million to our postretirement benefit plan in 2010. For 2009, we contributed $9.0 million to our pension plans and contributed less than $0.1 million to our postretirement benefit plan. At December 31, 2009 we recognized a liability of $13.3 million as a result of the underfunded status of our pension and other postretirement benefit plans compared to a liability of $15.4 million at December 31, 2008. For further information regarding our pension and other postretirement benefit plans, we refer you to Note 11 to the consolidated financial statements and “Critical Accounting Policies” below for additional information.


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 Credit Facility described in “Financing Requirements” above. We had positive working capital of $28.1 million at December 31, 2009 and positive working capital of $102.9 million at December 31, 2008. Current assets decreased $318.8 million during 2009 due to a $183.1 million decrease in cash and cash equivalents and a $180.3 million decrease in our current hedging asset. Current liabilities decreased $244.0 million as a result of a $122.4 million decrease in our current deferred income taxes related to our hedging activities, a $46.9 million decrease in accounts payable and a $60.0 million decrease in short-term debt relating to the prepayment of the 7.625% Senior Notes.


Gas in Underground Storage


We record our gas stored in inventory that is owned by the E&P segment at the lower of weighted average cost or market. We recorded a $4.3 million non-cash natural gas inventory impairment charge for the three months ended March 31, 2009 to reduce the current portion of our natural gas inventory to the lower of cost or market. The gas in inventory for the E&P segment is used primarily to supplement production in meeting the segment’s contractual commitments, especially during periods of colder weather. In determining the lower of cost or market for storage gas, we utilize the 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 additional write-downs of our gas in underground storage carrying cost.

 

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Natural Gas and Oil Properties

We utilize the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized 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, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10 percent (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Effective December 31, 2009, companies using the full cost method must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves. For quarter and annual periods ending prior to December 31, 2009, prices in effect at the date of each accounting quarter, including the impact of derivatives qualifying as cash flow hedges, were required to be used.


At March 31, 2009, the net capitalized costs of our gas and oil properties exceeded the ceiling by approximately $558.3 million (net of tax) and resulted in a non-cash ceiling test impairment in the first quarter of 2009. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.87 per MMBtu and $57.65 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2009. Cash flow hedges of gas production in place increased the ceiling value by approximately $225.9 million at December 31, 2009. Excluding the benefit of those cash flow hedges at December 31, 2009, unamortized costs would have exceeded the ceiling value by $195.7 million. Decreases in average market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and service costs could result in future ceiling test impairments.  


Natural gas and oil reserves cannot be measured exactly. Our estimate of natural gas and oil reserves requires extensive judgments of reservoir engineering data and projections of cost that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates under the supervision of our management.  Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team to which the property is assigned.  The reservoir engineering and financial data included in these estimates are reviewed by senior engineers who are not part of the asset management teams and our Vice President-EP&A, who was the technical person primarily responsible for the preparation of our reserve estimates, and has over twenty years of experience in petroleum engineering, including over fifteen years in estimating oil and gas reserves.  On our behalf, the Vice President-EP&A engages Netherland, Sewell & Associates, Inc., or NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in more detail below. The financial data included in the reserve estimates are also separately reviewed by our accounting staff. Following these reviews and the audit, the reserve estimates are submitted to our Chief Executive Officer for his review and approval prior to the presentation to our Board of Directors. NSAI reports the results of its reserve audit to the Board of Directors and final authority over the estimates of our proved reserves rests with our Board of Directors.  

In each of the past three years, revisions to our proved reserve estimates represented no greater than 5% of our total proved reserve estimates, which we believe is indicative of the effectiveness of our internal controls. Proved developed reserves generally have a higher degree of accuracy in this estimation process, when compared to proved undeveloped and proved non-producing reserves, as production history and pressure data over time is available for the majority of our proved developed properties. Proved developed reserves accounted for 54% of our total reserve base at December 31, 2009. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of

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such reserve estimates. The uncertainties inherent in the reserve estimates are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves.  We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control.  We refer you to “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A, “Risk Factors,” of Part I of this Form 10-K for a more detailed discussion of these uncertainties, risks and other factors.

In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently develop reserve estimates.  NSAI’s audit consists primarily of substantive testing, which includes a detailed review of major properties that account for approximately 88% of present worth of the company’s total proved reserves.  NSAI’s audit process consists of sorting all fields by descending present value order and selecting the fields from highest value to descending value until the selected fields account for more than 80% of the present worth of our reserves.  The properties in the bottom 20% of the total present worth are not reviewed in the audit.  The fields included in approximately the top 88% present value as of December 31, 2009, accounted for approximately 90% of our total proved reserves and approximately 97% of our proved undeveloped reserves.


 In the conduct of its audit, NSAI did not independently verify the data we provided to them with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production.  NSAI has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data. For the year-ended December 31, 2009, on February 10, 2010, NSAI issued its audit opinion as to the reasonableness of our reserve estimates, stating that our estimated proved oil and gas reserves are, in the aggregate, reasonable and have been prepared in accordance with 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. Our standardized measure and reserve quantities at December 31, 2009, were $1,801.8 million and 3,656.7 Bcfe, respectively. An assumed decrease of $1.00 per Mcf in the average 2009 gas price used to price our reserves would have resulted in an approximate $671.9 million decline in our standardized measure, adjusted for the effects of derivatives qualifying as cash flow hedges, and an approximate decrease of 1,018 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, capitalized costs and future development costs.

Hedging

We use natural gas and crude oil swap agreements and options to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil. Our policies prohibit speculation with derivatives and limit agreements to counterparties with appropriate credit standings to minimize the risk of uncollectability. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. From 2006 through 2008, we established a portfolio of hedges relating to approximately 60% to 80% of our annual production. However, only 45% of our 2009 production was hedged due to credit and overall market events of late 2008 as well as the low commodity price environment throughout 2009. 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 recorded at fair value in our financial statements and generally qualify for hedge accounting. We have established the fair value of derivative instruments using data provided by our counterparties in conjunction with assumptions evaluated internally using established index prices and other sources. These valuations are recognized as assets or liabilities in our balance sheet and, to the extent an open position is an effective cash flow hedge on equity production, the offset is recorded in other comprehensive income. Results of settled commodity hedging transactions are reflected in natural gas and oil sales. Any derivative not qualifying for hedge accounting treatment or any ineffective portion of a properly designated hedge is recognized immediately in earnings. For the year ended December 31, 2009, we recorded an unrealized loss of $15.1 million related to basis differential swaps that did not qualify for hedge accounting in addition to a $9.9 million gain related to the change in estimated ineffectiveness of our commodity cash flow

 

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hedges. Future market price volatility could create significant changes to the hedge positions recorded in our financial statements. We refer you to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of Part II of this Form 10-K for additional information regarding our hedging activities.


Pension and Other Postretirement Benefits


We record our prepaid or accrued benefit cost, as well as our periodic benefit cost, for our pension and other postretirement benefit plans using measurement assumptions that we consider reasonable at the time of calculation (see Note 11 to the consolidated financial statements for further discussion and disclosures regarding these benefit plans). Two of the assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be effectively settled, and the expected return on plan assets, which reflects the average rate of earnings expected on the funds invested. For the December 31, 2009 benefit obligation and the periodic benefit cost to be recorded in 2010, the discount rate assumed is 5.75%. For the 2010 periodic benefit cost, the expected return assumed is 7.50%. This compares to a discount rate of 6.0% and an expected return of 7.50% used in 2009.  

 

Using the assumed rates discussed above, we recorded pension expense of $7.3 million in 2009 related to our pension and other postretirement benefit plans.  Due to the significance of the discount rate and expected long-term rate of return, the following sensitivity analysis demonstrates the effect that a 50 basis point change in those assumptions would have had on our 2009 pension expense:


 

Increase (Decrease) of Annual Pension Expense

 

50 Basis Point Increase

 

50 Basis Point Decrease

 

(in thousands)

Discount rate ………………………………………………………………………………...

$                (374)

 

$             405 

Expected long-term rate of return ………………………………………….………………

$                (187)

 

$             187 


At December 31, 2009, we recognized a liability of $13.3 million, compared to $15.4 million at December 31, 2008, related to our pension and other postretirement benefit plans. During 2009, we also made cash payments totaling $9.0 million to fund our pension and other postretirement benefit plans. In 2010, we expect to make cash payments totaling $9.7 million to fund our pension and other postretirement benefit plans and recognize pension expense of $6.1 million and a postretirement benefit expense of $1.1 million.

 

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, 2009 and 2008, the current portion of gas in storage was $9.2 million and $24.1 million, respectively. The non-current portion of gas in storage is classified in property and equipment and carried at cost.  The carrying value of the non-current gas is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable.

The gas in inventory for the E&P segment is used primarily to supplement production in meeting the segment’s contractual commitments, especially during periods of colder weather. In determining the lower of cost or market for storage gas, we utilize the 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.

 

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New Accounting Standards Implemented in this Report

 

In June 2009, we implemented the Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”).  The implementation establishes the FASB ASC as the source of authoritative accounting principles in the preparation of financial statements in conformity with GAAP. The FASB ASC does not change GAAP and its implementation did not have a material impact on our consolidated financial statements.


On January 1, 2009, we implemented certain provisions of FASB ASC Topic 810, “Consolidation,” which establish accounting and reporting standards for (1) ownership interests in subsidiaries held by others, (2) the amount of consolidated net income (loss) attributable to the controlling and noncontrolling interests, (3) changes in the controlling ownership interest, (4) the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated and (5) disclosures that clearly identify and distinguish between the interests of the controlling and noncontrolling owners.  The implementation was retrospectively applied and resulted in changes to our presentation for noncontrolling interests and did not have a material impact on our results of operations or financial condition.  


On January 1, 2009, we implemented certain provisions of FASB ASC Topic 815, “Derivatives and Hedging,” which require enhanced disclosure about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for and (3) how derivative instruments and related hedged items affect our financial position, financial performance and cash flows.  The implementation did not have a material impact on our Company’s results of operations or financial condition.


On January 1, 2009, we implemented certain provisions of FASB ASC Topic 820, “Fair Value Measurements and Disclosures,” which require the fair value application 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). Accordingly, we now apply the fair-value framework to nonfinancial assets and nonfinancial liabilities initially measured at fair value, such as asset retirement obligations. The implementation did not have a material impact on our results of operations or financial condition.

 

On June 30, 2009, we implemented certain provisions of FASB ASC Topic 825, “Financial Instruments,” which require the (1) fair value disclosures required for certain financial instruments be included in interim financial statements and (2) public companies disclose the method and significant assumptions used to estimate the fair value of those financial instruments and to discuss any changes of method or assumptions, if any, during the reporting period. The implementation did not have a material impact on our Company’s results of operations or financial condition.  


On June 30, 2009, we implemented certain provisions of FASB ASC Topic 855, “Subsequent Events,” which establish the general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  The implementation did not have a material impact on our results of operations or financial condition.


On December 31, 2009, we implemented certain provisions of FASB ASC 715, “Defined Benefit Plans,” which require enhanced disclosures about the fair value measurements of employers’ plan assets in our year ending 2009 consolidated financial statements.  These required disclosures include: (a) investment policies and strategies; (b) major categories of plan assets; (c) information about valuation techniques and inputs to those techniques, including the fair value hierarchy classifications of the major categories of plan assets; (d) the effects of fair value measurements using significant unobservable inputs on changes in plan assets; and (e) significant concentrations of risk within plan assets. The implementation did not have a material impact on our results of operations or financial condition.


On December 31, 2009, we implemented certain provisions of FASB ASC 932, “Extractive Activities-Oil and Gas,” as updated by Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932),” which (a) expanded the definition of oil- and gas-producing activities; (b) requires energy companies to value their proved reserves by averaging the price from the first day of each month from the previous 12 months instead of using a year-end price; and (c) allows for additional drilling locations to be classified as proved undeveloped reserves assuming such locations are supported by reliable technologies. We accounted for the FASB ASC 932 changes 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 will account for the change prospectively.


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

 

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Accounting Standards Not Yet Implemented

 

On January 1, 2010, we implemented certain provisions of FASB ASC Topic 810, “Consolidation,” in the first quarter of 2010. The new provisions (a) require a qualitative rather than a quantitative approach to determining the primary beneficiary of a variable interest entity (“VIE”); (b) amend certain guidance pertaining to the determination of the primary beneficiary when related parties are involved; (c) amend certain guidance for determining whether an entity is a VIE; and (d) require continuous assessments of whether an enterprise is the primary beneficiary of a VIE. We do not expect that this implementation will have a material impact on our results of operations or financial condition.


In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements” (“Update 2010-06”). Update 2010-06 requires us to (a) provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy; (b) provide a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method; and (c) provide fair value measurement disclosures for each class of financial assets and liabilities. We are required to implement the disclosures of Update 2010-06 beginning on January 1, 2011. We do not expect the implementation of Update 2010-06 will have a material impact on our results of operations or financial condition.

 

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS


All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

 

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


You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

 

·

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

·

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

·

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

·

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

·

our ability to fund our planned capital investments;

·

the impact of federal, state and local government regulation, including any legislation relating to hydraulic fracturing, the climate or over the counter derivatives;

·

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

·

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.

 

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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, 2009, approximately 46% 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.

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.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


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


Credit Risk


Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our customers and their dispersion across geographic areas. No single customer accounted for greater than 5% of accounts receivable at December 31, 2009.  See “Commodities Risk” below for discussion of credit risk associated with commodities trading.

 

Interest Rate Risk


The following table presents the principal cash payments for our debt obligations and related weighted-average interest rates by expected maturity dates as of December 31, 2009. At December 31, 2009, we had $998.7 million of total debt with a weighted average interest rate of 5.40% and we had $324.5 million of indebtedness outstanding under our Credit Facility. Interest rate swaps may be used to adjust interest rate exposures when deemed appropriate. We do not have any interest rate swaps in effect currently.


 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair

 

Expected Maturity Date

 

Value

 

2010

 

2011

 

2012

 

2013

 

2014

 

Thereafter

 

Total

 

12/31/09

 

($ in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Rate

$          1.2 

 

$          1.2 

 

$          1.2 

 

$          1.2 

 

$          1.2 

 

$      668.2 

 

$      674.2 

 

$      707.3 

Average Interest Rate

 7.15%

 

 7.15%

 

 7.15%

 

 7.15%

 

 7.15%

 

 7.47%

 

 7.47%

 

 — 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable Rate

 — 

 

 — 

 

$      324.5 

 

 — 

 

 — 

 

 — 

 

$      324.5 

 

$      324.5 

Average Interest Rate

 — 

 

 — 

 

 1.11%

 

 — 

 

 — 

 

 — 

 

 1.11%

 

 — 


Commodities Risk


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


The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major 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 have not incurred any counterparty losses 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.

 

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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, 2009, the fair value of our financial instruments related to natural gas production was a $151.8 million asset.


 

 

 

Weighted

 

Weighted

 

Weighted

 

Weighted

 

 

 

 

 

Average

 

Average

 

Average

 

Average

 

Fair value at

 

 

 

Price to be

 

Floor

 

Ceiling

 

Basis

 

December 31,

 

 

 

Swapped

 

Price

 

Price

 

Differential

 

2009

 

Volume

 

($/MMBtu)

 

($/MMBtu)

 

($/MMBtu)

 

($/MMBtu)

 

($ in millions)

Natural Gas (Bcf):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Price Swaps:

 

 

 

 

 

 

 

 

 

 

 

2010

 36.0 

 

 9.04 

 

 — 

 

 — 

 

 — 

 

 116.6 

2011

 30.0 

 

 6.69 

 

 — 

 

 — 

 

 — 

 

 10.4 

 

 

 

 

 

 

 

 

 

 

 

 

Costless-Collars:

 

 

 

 

 

 

 

 

 

 

 

2010

 30.0 

 

 — 

 

 6.80 

 

 8.43 

 

 — 

 

 38.1 

 

 

 

 

 

 

 

 

 

 

 

 

Basis Swaps:

 

 

 

 

 

 

 

 

 

 

 

2010

 46.5 

 

 — 

 

 — 

 

 — 

 

 (0.37)

 

 (11.7)

2011

 9.0 

 

 — 

 

 — 

 

 — 

 

 (0.35)

 

 (1.6)


At December 31, 2009, our basis swaps did not qualify for hedge accounting treatment. Changes in the fair value of derivatives that do not qualify as hedges are recorded in gas and oil sales. At December 31, 2009, we had outstanding fixed-price basis differential swaps on 46.5 Bcf of 2010 and 9.0 Bcf of 2011 gas production. For the year ended December 31, 2009, we recorded an unrealized loss of $15.1 million related to the differential swaps that did not qualify for hedge accounting treatment and a gain of $9.9 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.


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. 


Subsequent to December 31, 2009 and prior to February 25, 2010, we hedged an additional 7.3 Bcf of 2011 gas production using costless-collars with an average floor and ceiling price of $5.75 and $7.06 per MMBtu, respectively.  We also basis protected an additional 2.8 Bcf of 2010 and 3.0 Bcf of 2011 gas production with an average differential price of $0.08 below NYMEX spot rates for our respective basis locations.  


Midstream Services


At December 31, 2009, our Midstream Services segment had outstanding fair value hedges in place on 0.3 Bcf, 0.1 Bcf and 0.1 Bcf of gas for 2010, 2011 and 2012, 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 2010 through March 2012 and have a net fair value liability of $0.8 million as of December 31, 2009.

 

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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

65

Report of Independent Registered Public Accounting Firm

 66 

Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007

 67 

Consolidated Balance Sheets as of December 31, 2009 and 2008

68

Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007

69

Consolidated Statements of Equity for the fiscal years ended December 31, 2009, 2008 and 2007

70

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2009, 2008 and 2007

71

Notes to Consolidated Financial Statements, December 31, 2009, 2008 and 2007

72

 

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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, 2009.  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, 2009, 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, 2009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report below.

 

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Report of Independent Registered Public Accounting Firm


To the Board of Directors and Stockholders 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 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, 2009, 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.  Our responsibility is to express opinions on these financial statements, and on the Company's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.


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


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


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


/s/ PRICEWATERHOUSECOOPERS LLP


PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 25, 2010

 

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


 

For the years ended December 31,

 

2009

 

2008

 

2007

 

(in thousands, except share/per share amounts)

Operating Revenues:

 

 

 

 

 

Gas sales

$   1,578,256 

 

$     1,500,408 

 

$        875,192 

Gas marketing

 488,663 

 

 719,909 

 

 311,767 

Oil sales

 6,843 

 

 41,240 

 

 42,434 

Gas gathering

 74,281 

 

 41,748 

 

 11,627 

Other

 (2,264)

 

 8,247 

 

 14,111 

 

 2,145,779 

 

 2,311,552 

 

 1,255,131 

Operating Costs and Expenses:

 

 

 

 

 

Gas purchases – midstream services

 482,836 

 

 710,129 

 

 306,336 

Gas purchases – gas distribution

 — 

 

 61,439 

 

 85,445 

Operating expenses

 136,541 

 

 107,577 

 

 85,826 

General and administrative expenses

 122,618 

 

 101,959 

 

 80,269 

Depreciation, depletion and amortization

 493,658 

 

 414,408 

 

 293,914 

Impairment of natural gas and oil properties

 907,812 

 

 — 

 

 — 

Taxes, other than income taxes

 37,280 

 

 29,272 

 

 21,875 

 

 2,180,745 

 

 1,424,784 

 

 873,665 

Operating Income (Loss)

 (34,966)

 

 886,768 

 

 381,466 

 

 

 

 

 

 

Interest Expense:

 

 

 

 

 

Interest on debt

 55,581 

 

 61,152 

 

 36,191 

Other interest charges

 3,266 

 

 2,284 

 

 1,474 

Interest capitalized

 (40,209)

 

 (34,532)

 

 (13,792)

 

 18,638 

 

 28,904 

 

 23,873 

Other Income (Loss)

 1,449 

 

 4,404 

 

 (219)

Gain on Sale of Utility Assets

 — 

 

 57,264 

 

 — 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

 (52,155)

 

 919,532 

 

 357,374 

Provision (Benefit) for Income Taxes:

 

 

 

 

 

Current

 (64,969)

 

 122,000 

 

 — 

Deferred

 48,606 

 

 228,999 

 

 135,855 

 

 (16,363)

 

 350,999 

 

 135,855 

Net Income (Loss)

 (35,792)

 

 568,533 

 

 221,519 

Less: Net Income (Loss) Attributable to Noncontrolling Interest

 (142)

 

 587 

 

 345 

Net Income (Loss) Attributable to Southwestern Energy

$       (35,650)

 

$        567,946 

 

$        221,174 

 

 

 

 

 

 

Earnings Per Share: (1)

 

 

 

 

 

Net income (loss) attributable to Southwestern Energy stockholders-Basic

$            (0.10)

 

$              1.66 

 

$              0.65 

Net income (loss) attributable to Southwestern Energy stockholders-Diluted

$            (0.10)

 

$              1.64 

 

$              0.64 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding: (1)

 

 

 

 

 

Basic

 343,420,568 

 

 341,621,814 

 

 338,953,446 

Effect of:

 

 

 

 

 

Stock options

 — 

 

 4,237,263 

 

 8,024,198 

Restricted stock awards

 — 

 

 386,861 

 

 465,016 

Diluted

 343,420,568 

 

 346,245,938 

 

 347,442,660 


(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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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

December 31,

 

2009

 

2008

ASSETS

(in thousands)

Current Assets:

 

 

 

Cash and cash equivalents

$           13,184 

 

$          196,277 

Accounts receivable

 263,076 

 

 254,557 

Inventories

 30,009 

 

 50,377 

Hedging asset

 163,069 

 

 343,320 

Other

 95,163 

 

 38,732 

Total current assets

 564,501 

 

 883,263 

Property and Equipment:

 

 

 

Gas and oil properties, using the full cost method, including $595.4 million in 2009 and $540.6 million in 2008 excluded from amortization

 6,388,022 

 

 4,836,077 

Gathering systems

 547,637 

 

 341,474 

Gas in underground storage

 13,349 

 

 13,349 

Other

 205,013 

 

 138,014 

 

 7,154,021 

 

 5,328,914 

Less: Accumulated depreciation, depletion and amortization

 3,026,768 

 

 1,615,307 

 

 4,127,253 

 

 3,713,607 

 

 

 

 

Other Assets

 78,496 

 

 163,288 

TOTAL ASSETS

$      4,770,250 

 

$       4,760,158 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

Current Liabilities:

 

 

 

Short-term debt

$              1,200 

 

$            61,200 

Accounts payable

 404,695 

 

 451,597 

Taxes payable

 25,500 

 

 31,951 

Interest payable

 19,775 

 

 20,857 

Advances from partners

 52,406 

 

 70,603 

Hedging liability

 20,052 

 

 10,899 

Current deferred income taxes

 — 

 

 122,448 

Other

 12,788 

 

 10,842 

Total current liabilities

 536,416 

 

 780,397 

Long-Term Debt

 997,500 

 

 674,200 

Other Liabilities:

 

 

 

Deferred income taxes

 811,902 

 

 721,707 

Long-term hedging liability

 3,057 

 

 5,934 

Pension and other postretirement liabilities

 12,630 

 

 15,352 

Other

 67,764 

 

 44,605 

 

 895,353 

 

 787,598 

Commitments and Contingencies

 

 

 

 

 

 

 

Equity:

 

 

 

Southwestern Energy stockholders’ equity:

 

 

 

Common stock, $0.01 par value; authorized 540,000,000 shares, issued 346,081,210 shares in 2009 and 343,624,956 in 2008

 3,461 

 

 3,436 

Additional paid-in capital

 833,494 

 

 811,492 

Retained earnings

 1,414,327 

 

 1,449,977 

Accumulated other comprehensive income

 84,276 

 

 247,665 

Common stock in treasury, 203,830 shares in 2009 and 225,050 in 2008

 (4,333)

 

 (4,740)

Total Southwestern Energy stockholders’ equity

 2,331,225 

 

 2,507,830 

Noncontrolling interest

 9,756 

 

 10,133 

Total Equity

 2,340,981 

 

 2,517,963 

TOTAL LIABILITIES AND EQUITY

$      4,770,250 

 

$       4,760,158 

 

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

 

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


 

For the years ended December 31,

 

 

2009

 

2008

 

2007

 

 

(in thousands)

 

Cash Flows From Operating Activities

 

 

 

 

 

 

Net income (loss)

$       (35,792)

 

$        568,533 

 

$        221,519 

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

Depreciation, depletion and amortization

 495,291 

 

 416,151 

 

 295,332 

 

Impairment of natural gas and oil properties

 907,812 

 

 — 

 

 — 

 

Deferred income taxes

 48,606 

 

 228,999 

 

 135,855 

 

Gain on sale of utility assets

 — 

 

 (57,264)

 

 — 

 

Unrealized loss (gain) on derivatives

 5,309 

 

 4,644 

 

 (7,103)

 

Stock-based compensation expense

 12,749 

 

 7,952 

 

 6,377 

 

Impairment of natural gas inventory and other

 7,053 

 

 (1,521)

 

 (810)

 

Change in assets and liabilities:

 

 

 

 

 

 

Accounts receivable

 (8,519)

 

 (60,117)

 

 (76,136)

 

Inventories

 11,779 

 

 (39,475)

 

 (10,800)

 

Accounts payable

 (21,739)

 

 70,975 

 

 60,983 

 

Taxes payable

 (6,451)

 

 20,855 

 

 (3,454)

 

Interest payable

 (1,082)

 

 18,522 

 

 198 

 

Advances from partners and customer deposits

 (18,197)

 

 38,418 

 

 7,615 

 

Deferred tax benefit – stock options

 — 

 

 (43,107)

 

 — 

 

Other assets and liabilities

 (37,443)

 

 (12,756)

 

 (6,841)

 

Net cash provided by operating activities

 1,359,376 

 

 1,160,809 

 

 622,735 

 

 

 

 

 

 

 

 

Cash Flows From Investing Activities

 

 

 

 

 

 

Capital investments

 (1,780,165)

 

 (1,755,888)

 

 (1,519,433)

 

Proceeds from sale of property and equipment

 818 

 

 750,310 

 

 5,791 

 

Net proceeds from sale of utility assets

 — 

 

 213,721 

 

 — 

 

Other items

 (1,257)

 

 (221)

 

 145 

 

Net cash used in investing activities

 (1,780,604)

 

 (792,078)

 

 (1,513,497)

 

 

 

 

 

 

 

 

Cash Flows From Financing Activities

 

 

 

 

 

 

Payments on short-term debt

 (61,200)

 

 (1,200)

 

 (1,200)

 

Payments on revolving long-term debt

 (1,371,700)

 

 (1,843,600)

 

 (916,550)

 

Borrowings under revolving long-term debt

 1,696,200 

 

 1,001,400 

 

 1,758,750 

 

Proceeds from issuance of long-term debt

 — 

 

 600,000 

 

 — 

 

Debt issuance costs and revolving credit facility costs

 — 

 

 (8,895)

 

 (2,000)

 

Deferred tax benefit – stock options

 — 

 

 43,107 

 

 — 

 

Change in bank drafts outstanding

 (30,920)

 

 31,397 

 

 5,193 

 

Proceeds from exercise of common stock options

 5,755 

 

 3,505 

 

 5,474 

 

Net cash provided by (used in) financing activities

 238,135 

 

 (174,286)

 

 849,667 

 

 

 

 

 

 

 

 

Increase (decrease) in cash and cash equivalents

 (183,093)

 

 194,445 

 

 (41,095)

 

Cash and cash equivalents at beginning of year

 196,277 

 

 1,832 

(1)

 42,927 

(1)

Cash and cash equivalents at end of year

$        13,184 

 

$        196,277 

 

$            1,832 

(1)


(1) Cash and cash equivalents at the beginning of 2008 and at the beginning and end of 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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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

STATEMENTS OF EQUITY


 

Southwestern Energy Stockholders

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

Common Stock(1)

 

Additional

 

 

 

Other

 

Common

 

 

 

 

 

Shares

 

 

 

Paid-In

 

Retained

 

Comprehensive

 

Stock in

 

Noncontrolling

 

 

 

Issued

 

Amount

 

Capital(1)

 

Earnings

 

Income

 

Treasury

 

Interest

 

Total

 

(in thousands)

 


 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2006

 337,908 

 

$     3,379 

 

$ 738,920 

 

$  660,857 

 

$         31,487 

 

$          — 

 

$        11,034 

 

$   1,445,677 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 — 

 

 — 

 

 — 

 

 221,174 

 

 — 

 

 — 

 

 345 

 

 221,519 

Change in derivatives

 — 

 

 — 

 

 — 

 

 — 

 

 (16,775)

 

 — 

 

 — 

 

 (16,775)

Change in pension and other postretirement liabilities

 — 

 

 — 

 

 — 

 

 — 

 

 (1,364)

 

 — 

 

 — 

 

 (1,364)

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 345 

 

 203,380 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

 — 

 

 — 

 

 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 stock

 (50)

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

Treasury stock – non-qualified plan

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 (4,664)

 

 — 

 

 (4,664)

Distributions to noncontrolling interest in partnership

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 (809)

 

 (809)

Balance at December 31, 2007

 341,578 

 

$     3,416 

 

$ 752,369 

 

$  882,031 

 

$         13,348 

 

$   (4,664)

 

$        10,570 

 

$   1,657,070 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 — 

 

 — 

 

 — 

 

 567,946 

 

 — 

 

 — 

 

 587 

 

 568,533 

Change in derivatives

 — 

 

 — 

 

 — 

 

 — 

 

 234,259 

 

 — 

 

 — 

 

 234,259 

Change in pension and other postretirement liabilities

 — 

 

 — 

 

 — 

 

 — 

 

 58 

 

 — 

 

 — 

 

 58 

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 587 

 

 802,850 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred tax benefit – stock options

 — 

 

 — 

 

 43,107 

 

 — 

 

 — 

 

 — 

 

 — 

 

 43,107 

Stock-based compensation

 — 

 

 — 

 

 12,415 

 

 — 

 

 — 

 

 — 

 

 — 

 

 12,415 

Exercise of stock options

 1,690 

 

 17 

 

 3,488 

 

 — 

 

 — 

 

 — 

 

 — 

 

 3,505 

Issuance of restricted stock

 417 

 

 4 

 

 (4)

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

Cancellation of restricted stock

 (66)

 

 (1)

 

 1 

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

Issuance of stock awards

 6 

 

 — 

 

 116 

 

 — 

 

 — 

 

 — 

 

 — 

 

 116 

Treasury stock – non-qualified plan

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 (76)

 

 — 

 

 (76)

Distributions to noncontrolling interest in partnership

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 (1,024)

 

 (1,024)

Balance at December 31, 2008

 343,625 

 

$     3,436 

 

$ 811,492 

 

$1,449,977 

 

$       247,665 

 

$   (4,740)

 

$        10,133 

 

$   2,517,963 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 — 

 

 — 

 

 — 

 

 (35,650)

 

 — 

 

 — 

 

 (142)

 

 (35,792)

Change in derivatives

 — 

 

 — 

 

 — 

 

 — 

 

 (163,591)

 

 — 

 

 — 

 

 (163,591)

Change in pension and other postretirement liabilities

 — 

 

 — 

 

 — 

 

 — 

 

 202 

 

 — 

 

 — 

 

 202 

Total comprehensive loss

 

 

 

 

 

 

 

 

 

 

 

 

 (142)

 

 (199,181)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

 — 

 

 — 

 

 16,003 

 

 — 

 

 — 

 

 — 

 

 — 

 

 16,003 

Exercise of stock options

 2,153 

 

 22 

 

 5,733 

 

 — 

 

 — 

 

 — 

 

 — 

 

 5,755 

Issuance of restricted stock

 312 

 

 3 

 

 (3)

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

Cancellation of restricted stock

 (10)

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

Issuance of stock awards

 1 

 

 — 

 

 65 

 

 — 

 

 — 

 

 — 

 

 — 

 

 65 

Treasury stock – non-qualified plan

 — 

 

 — 

 

 204 

 

 — 

 

 — 

 

 407 

 

 — 

 

 611 

Distributions to noncontrolling interest in partnership

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 — 

 

 (235)

 

 (235)

Balance at December 31, 2009

 346,081 

 

$     3,461 

 

$ 833,494 

 

$1,414,327 

 

$         84,276 

 

$   (4,333)

 

$          9,756 

 

$   2,340,981 


(1) 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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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 

 

For the years ended December 31,

 

2009

 

2008

 

2007

 

(in thousands)

 

 

 

 

 

 

Net income (loss)

$       (35,792)

 

$         568,533 

 

$         221,519 

 

 

 

 

 

 

Change in derivatives:

 

 

 

 

 

Reclassification to earnings (1)

 (376,259)

 

 45,830 

 

 (42,956)

Ineffectiveness (2)

 (6,031)

 

 4,319 

 

 (618)

Change in fair value of derivative instruments (3)

 218,699 

 

 184,110 

 

 26,799 

Total change in derivatives

 (163,591)

 

 234,259 

 

 (16,775)

 

 

 

 

 

 

Change in pension and other postretirement liabilities:

 

 

 

 

 

Sale of utility – divestiture, curtailment and settlement (4)

 — 

 

 9,040 

 

 — 

Change in value of pension and other postretirement liabilities (5)

 202 

 

 (8,982)

 

 (1,364)

Total change in pension and other postretirement liabilities

 202 

 

 58 

 

 (1,364)

 

 

 

 

 

 

Comprehensive income (loss)

 (199,181)

 

 802,850 

 

 203,380 

 

 

 

 

 

 

Less: comprehensive income (loss) attributable to the noncontrolling interest

 (142)

 

 587 

 

 345 

 

 

 

 

 

 

Comprehensive income (loss) attributable to Southwestern Energy

$     (199,039)

 

$         802,263 

 

$         203,035 

 

(1) Net of ($234.1), $28.1 and ($26.3) million in taxes for the twelve months ended December 31, 2009, 2008 and 2007, respectively.


(2) Net of ($3.8), $2.6 and ($0.4) million in taxes for the twelve months ended December 31, 2009, 2008 and 2007, respectively.


(3) Net of $137.7, $112.8 and $16.4 million in taxes for the twelve months ended December 31, 2009, 2008 and 2007, respectively.


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


(5) Net of $0.2, ($5.6) and ($1.1) million in taxes for the twelve months ended December 31, 2009, 2008 and 2007, respectively.

 

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

 

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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


Nature of Operations


Southwestern Energy Company (including its subsidiaries, collectively, “Southwestern” or the “Company”) is an independent energy company primarily focused on the exploration and production of natural gas. The Company engages in natural gas and oil exploration and production, natural gas gathering and natural gas marketing through its subsidiaries. Southwestern’s exploration 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. In the past, the Company engaged in natural gas distribution and transmission through a wholly-owned utility subsidiary, Arkansas Western Gas Company (“Arkansas Western Gas”), which operated in northern Arkansas. Effective July 1, 2008, the Company sold all of its stock in Arkansas Western Gas and, as a result, no longer has any natural gas distribution operations.


Basis of Presentation


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


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


Certain reclassifications have been made to the prior years financial statements to conform to the 2009 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements.


Principles of Consolidation


The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries, including SEECO, Inc. (“SEECO”), 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. In accordance with GAAP, the Company recognized profit on intercompany sales of natural gas delivered to storage by its utility subsidiary, Arkansas Western Gas, prior to the sale of this segment.


In 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 controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P results and the investor’s share of the partnership activity is reported as net income (loss) attributable to noncontrolling interest in the consolidated 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.


Revenue Recognition


Natural gas and oil sales. Gas sales and oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s revenue interest of production from its properties in which sales are disproportionately allocated to owners because of marketing or other contractual arrangements. Accordingly, revenue is not recognized for deliveries in excess of the Company’s net revenue

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interest, while revenue is recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. At December 31, 2009, the Company had overproduction of 2.2 Bcf valued at $6.4 million and underproduction of 2.6 Bcf valued at $8.2 million. 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.

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

Gas gathering. The Company gathers its gas, as well as some gas produced by third parties, pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.

Other. The Company maintains an underground gas storage facility and generally sells natural gas from its storage facility during the winter gas withdrawal season. Revenue is recognized on gas storage sales when the gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. Other revenues include gains of $3.4 million, $4.8 million and $6.4 million in 2009, 2008 and 2007, respectively, primarily related to the sale of gas in underground storage.

Cash and Cash Equivalents


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


Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $34.6 million and $65.5 million at December 31, 2009 and 2008, respectively.


Inventory

Inventory recorded in current assets includes $9.2 million at December 31, 2009 and $24.1 million at December 31, 2008, for gas in underground storage owned by the Company’s E&P segment, and $20.8 million at December 31, 2009 and $26.3 million at December 31, 2008 for tubulars and other equipment used in the E&P segment.

The Company has one natural gas storage facility.  The current portion of the gas is classified in inventory and carried at the lower of cost or market. During 2009, the Company recorded a $4.3 million non-cash impairment to reduce the current portion of our natural gas inventory to the lower of cost or market. The non-current portion of the gas is classified in property and equipment and carried at cost.  The carrying value of the non-current gas is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Withdrawals of current 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 $31.2 million at December 31, 2009 and $43.8 million at December 31, 2008 for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems for the Fayetteville Shale play.

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

 

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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, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10 percent (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense.  The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.87 per MMBtu and $57.65 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2009. Cash flow hedges of gas production in place increased the ceiling value by approximately $225.9 million at December 31, 2009. Excluding the benefit of those cash flow hedges at December 31, 2009, unamortized costs would have exceeded the ceiling value by $195.7 million.  At December 31, 2008, the ceiling value of the Company’s reserves was calculated based upon year-end quoted market prices of $5.71 per Mcf for Henry Hub natural gas and $41.00 per barrel for West Texas Intermediate oil, and at December 31, 2007, the ceiling value of the Company’s reserves was calculated based upon year-end quoted market prices of $6.80 per Mcf for Henry Hub natural gas and $92.50 per barrel for West Texas Intermediate oil. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.


At March 31, 2009, the net capitalized costs of our gas and oil properties exceeded the ceiling by approximately $558.3 million (net of tax) and resulted in a non-cash ceiling test impairment in the first quarter of 2009.


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

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


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


Income Taxes


Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes.


Derivative Financial Instruments


The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity swaps and options contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item.  In contrast, gains and losses from the ineffective portion of swaps and option contacts as well as basis swap contracts that do not qualify for hedge accounting treatment are recognized currently in gas sales in the consolidated statements of operations.  Changes in the fair value of derivative instruments designated as fair value hedges as well as the offsetting

 

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gain or loss on the hedged item are recognized in earnings immediately.  See Note 5 for a discussion of the Company’s hedging activities.


Earnings Per Share


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


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


Due to the net loss for the year ended December 31, 2009, 836,861 shares of restricted stock were excluded from the calculation of diluted shares 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.

 

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


Stock-Based Compensation


The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into the Company’s full cost pool or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s gas and oil properties or directly related to the construction of the Company’s gathering systems. See Note 13 for further discussion of the Company’s stock-based compensation.


Accounting Standards Implemented in this Report


In June 2009, the Company implemented the Financial Accounting Standards Board Accounting Standards Codification (“FASB ASC”).  The implementation establishes the FASB ASC as the source of authoritative accounting principles to be applied in the preparation of financial statements in conformity with GAAP. The FASB ASC does not change GAAP and its implementation did not have a material impact on the Company’s consolidated financial statements.


On January 1, 2009, the Company implemented certain provisions of FASB ASC Topic 810, “Consolidation,” which establish accounting and reporting standards for (1) ownership interests in subsidiaries held by others, (2) the amount of consolidated net income (loss) attributable to the controlling and noncontrolling interests, (3) changes in the controlling ownership interest, (4) the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated and (5) disclosures that clearly identify and distinguish between the interests of the controlling and noncontrolling owners.  The implementation was retrospectively applied and resulted in changes to the Company’s presentation for noncontrolling interests and did not have a material impact on the Company’s results of operations or financial condition.


On January 1, 2009, the Company implemented certain provisions of FASB ASC Topic 815, “Derivatives and Hedging,” which require enhanced disclosure about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  The implementation did not have a material impact on the Company’s results of operations or financial condition.

 

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On January 1, 2009, the Company implemented certain provisions of FASB ASC Topic 820, “Fair Value Measurements and Disclosures,” which require the fair value application 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). Accordingly, the Company now applies the fair-value framework to nonfinancial assets and nonfinancial liabilities initially measured at fair value, such as asset retirement obligations. The implementation did not have a material impact on the Company’s results of operations or financial condition.

 

On June 30, 2009, the Company implemented certain provisions of FASB ASC Topic 825, “Financial Instruments,” which require the (1) fair value disclosures required for certain financial instruments be included in interim financial statements and (2) public companies disclose the method and significant assumptions used to estimate the fair value of those financial instruments and to discuss any changes of method or assumptions, if any, during the reporting period. The implementation did not have a material impact on the Company’s results of operations or financial condition.


On June 30, 2009, the Company implemented certain provisions of FASB ASC Topic 855, “Subsequent Events,” which establish the general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  The implementation did not have a material impact on the Company’s results of operations or financial condition.


On December 31, 2009, the Company implemented certain provisions of FASB ASC 715, “Defined Benefit Plans,” which require enhanced disclosures about the fair value measurements of employers’ plan assets in the Company’s 2009 consolidated financial statements.  These required disclosures include: (a) investment policies and strategies; (b) major categories of plan assets; (c) information about valuation techniques and inputs to those techniques, including the fair value hierarchy classifications of the major categories of plan assets; (d) the effects of fair value measurements using significant unobservable inputs on changes in plan assets; and (e) significant concentrations of risk within plan assets. The disclosures did not have a material impact on the Company’s results of operations or financial condition.


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

Accounting Standards Not Yet Implemented

 

On January 1, 2010, certain provisions of FASB ASC Topic 810, “Consolidation,” became effective and were implemented by the Company in the first quarter of 2010. The new provisions (a) require a qualitative rather than a quantitative approach to determining the primary beneficiary of a variable interest entity (“VIE”); (b) amend certain guidance pertaining to the determination of the primary beneficiary when related parties are involved; (c) amend certain guidance for determining whether an entity is a VIE; and (d) require continuous assessments of whether an enterprise is the primary beneficiary of a VIE. The Company does not expect that this implementation will have a material impact on the Company’s results of operations and financial condition.


In January 2010, the FASB issued Accounting Standards Update No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820)—Improving Disclosures about Fair Value Measurements” (“Update 2010-06”). Update 2010-06 requires the Company to (a) provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy; (b) provide a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method; and (c) provide fair value measurement disclosures for each class of financial assets and liabilities. The disclosures required by Update 2010-06 are effective for the Company beginning on January 1, 2011. The Company does not expect the implementation of Update 2010-06 once adopted, will have a material impact on the Company’s results of operations or financial condition.

 

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(2) DIVESTITURES AND ASSETS HELD FOR SALE


In the second quarter of 2008, the Company sold certain oil and gas properties, 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 Arkansas Western Gas for $223.5 million (net of expenses related to the sale). In order to receive regulatory approval for the sale and certain related transactions, the Company paid $9.8 million to Arkansas Western Gas for the benefit if its customers. The Company recorded a pre-tax gain on the sale of the utility of $57.3 million in the third quarter of 2008. As a result of the sale of the utility, the Company is no longer engaged in any natural gas distribution operations. The assets and liabilities of Arkansas Western Gas were previously presented as “held for sale” and the consolidated statements of cash flows include $1.1 million and $0.1 million of cash and cash equivalents in the 2008 beginning of the year and the 2007 beginning of the year cash and cash equivalents balances, respectively.


(3) PREPAID EXPENSES


The components of prepaid expenses included in other current assets as of December 31, 2009 and 2008 consisted of the following:


 

2009

 

2008

 

(in thousands)

 

 

 

 

Prepaid drilling costs

$                53,819 

 

$                  26,827 

Prepaid insurance

 6,572 

 

 4,684 

Total

$                60,391 

 

$                  31,511 


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

All of the Company’s gas and oil properties are located in the United States.

Net Capitalized Costs

The following table shows the capitalized costs of gas and oil properties and the related accumulated depreciation, depletion and amortization at December 31, 2009 and 2008:

 

2009

 

2008

 

(in thousands)

 

 

 

 

Proved properties

$      5,792,664 

 

$         4,295,449 

Unproved properties

 595,358 

 

 540,628 

 

 

 

 

Total capitalized costs

 6,388,022 

 

 4,836,077 

Less:  Accumulated depreciation, depletion and amortization

 2,916,947 

 

 1,548,728 

Net capitalized costs

$      3,471,075 

 

$         3,287,349 


The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2009.  

 

2009

 

2008

 

2007

 

Prior

 

Total

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

$         72,699 

 

$         60,577 

 

$         43,990 

 

$         59,625 

 

$     236,891 

Exploration and development costs

 192,053 

 

 51,484 

 

 60,327 

 

 4,745 

 

 308,609 

Capitalized interest

 7,725 

 

 9,810 

 

 15,219 

 

 17,104 

 

 49,858 

 

$       272,477 

 

$       121,871 

 

$       119,536 

 

$         81,474 

 

$     595,358 


Of the total net unevaluated costs excluded from amortization at December 31, 2009, approximately $134.5 million is related to unevaluated seismic costs in the Fayetteville Shale play, approximately $104.5 million is related to acquisition of undeveloped properties in the Company’s Fayetteville Shale play and approximately $88.9 million is related to acquisition of undeveloped properties in the Company’s Appalachia properties.  Additionally, the Company has

 

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approximately $161.5 million of unevaluated costs related to costs of wells in progress and $10.3 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. The timing and amount of the Fayetteville Shale play property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells to further develop the play. The timing and amount of costs to be included in future amortization computations related to Appalachia and New Ventures will depend on the results of drilling and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.

Costs Incurred in Natural Gas and Oil Exploration and Development

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

 

2009

 

2008

 

2007

 

(in thousands, except per Mcfe amounts)

 

 

 

 

 

 

Proved property acquisition costs

$           4,372 

 

$                  — 

 

$             1,540 

Unproved property acquisition costs

 115,217 

 

 97,645 

 

 72,292 

Exploration costs

 52,178 

 

 245,363 

 

 527,456 

Development costs

 1,358,109 

 

 1,216,987 

 

 769,588 

Capitalized costs incurred

 1,529,876 

 

 1,559,995 

 

 1,370,876 

Full cost pool amortization per Mcfe

$              1.51 

 

$               1.99 

 

$               2.41 


Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $40.2 million, $34.5 million and $13.8 million during 2009, 2008 and 2007, respectively, based on the Company’s weighted average cost of borrowings used to finance the expenditures.


In addition to capitalized interest, the Company also capitalized internal costs of $112.9 million, $82.4 million and $58.9 million during 2009, 2008 and 2007, 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.


Results of Operations from Natural Gas and Oil Producing Activities


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

 

2009

 

2008

 

2007

 

(in thousands)

 

 

 

 

 

 

Sales

$   1,593,231 

 

$      1,491,302 

 

$         795,944 

Production (lifting) costs

 (259,588)

 

 (194,234)

 

 (97,645)

Depreciation, depletion and amortization

 (474,014)

 

 (399,159)

 

 (281,910)

Impairment of natural gas and oil properties

 (907,812)

 

 — 

 

 — 

 

 (48,183)

 

 897,909 

 

 416,389 

Provision (benefit) for income taxes

 (15,650)

 

 342,658 

 

 157,584 

Results of operations

$       (32,533)

 

$         555,251 

 

$         258,805 


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


Natural Gas and Oil Reserve Quantities


The Company engaged the services of Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates.  NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties and accounted for approximately 88%, 83% and 81% of the present worth of the Company’s total proved reserves at December 31, 2009, 2008 and 2007, respectively. A reserve audit is not the same as a financial audit and a reserve audit is less rigorous in nature than a reserve report prepared by and independent petroleum engineering firm

 

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containing its own estimate of reserves. Reserve estimates are inherently imprecise and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.


The following table summarizes the changes in the Company’s proved natural gas and oil reserves for 2009, 2008 and 2007:

 

2009

 

2008

 

2007

 

Gas

 

Oil

 

Gas

 

Oil

 

Gas

 

Oil

 

(MMcf)

 

(MBbls)

 

(MMcf)

 

(MBbls)

 

(MMcf)

 

(MBbls)

 

 

 

 

 

 

 

 

 

 

 

 

Proved reserves, beginning of year

 2,175,528 

 

 1,507 

 

 1,396,856 

 

 8,912 

 

 978,934 

 

 7,898 

Revisions of previous estimates

 94,930 

 

 (346)

 

 100,230 

 

 (355)

 

 30,489 

 

 81 

Extensions, discoveries and other additions

 1,683,264 

 

 22 

 

 919,623 

 

 93 

 

 498,141 

 

 1,585 

Production

 (299,698)

 

 (124)

 

 (192,265)

 

 (385)

 

 (109,881)

 

 (614)

Acquisition of reserves in place

 1,795 

 

 — 

 

 — 

 

 — 

 

 204 

 

 — 

Disposition of reserves in place

 (5,516)

 

 — 

 

 (48,916)

 

 (6,758)

 

 (1,031)

 

 (38)

Proved reserves, end of year

 3,650,303 

 

 1,059 

 

 2,175,528 

 

 1,507 

 

 1,396,856 

 

 8,912 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 1,336,370 

 

 1,352 

 

 880,278 

 

 7,269 

 

 623,870 

 

 6,994 

End of year

 1,972,767 

 

 1,028 

 

 1,336,370 

 

 1,352 

 

 880,278 

 

 7,269 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 839,158 

 

 155 

 

 516,578 

 

 1,643 

 

 355,064 

 

 904 

End of year

 1,677,536 

 

 31 

 

 839,158 

 

 155 

 

 516,578 

 

 1,643 


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


Standardized Measure of Discounted Future Net Cash Flows


The following standardized measures of discounted future net cash flows relating to proved natural gas and oil reserves at December 31, 2009, 2008 and 2007 are calculated after income taxes and discounted using a 10% annual discount rate and do not purport to present the fair market value the Company’s proved gas and oil reserves:

 

2009

 

2008

 

2007

 

(in thousands)

 

 

 

 

 

 

Future cash inflows

$ 12,533,868 

 

$    11,395,056 

 

$      9,380,172 

Future production costs

 (4,488,884)

 

 (3,115,947)

 

 (2,339,465)

Future development costs

 (2,367,206)

 

 (1,491,449)

 

 (1,029,501)

Future income tax expense

 (1,569,242)

 

 (2,178,756)

 

 (1,699,787)

Future net cash flows

 4,108,536 

 

 4,608,904 

 

 4,311,419 

10% annual discount for estimated timing of cash flows

 (2,306,718)

 

 (2,499,642)

 

 (2,296,263)

Standardized measure of discounted future net cash flows

$   1,801,818 

 

$      2,109,262 

 

$      2,015,156 


Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure above were average market prices of $3.87 per Mcf for gas and $57.65 per barrel for oil in 2009, year-end prices of $5.71 per Mcf for gas and $41.00 per barrel for oil in 2008, and year-end prices of $6.80 per Mcf for gas and $92.50 per barrel for oil in 2007.  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.

 

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Following is an analysis of changes in the standardized measure during 2009, 2008 and 2007:

 

2009

 

2008

 

2007

 

(in thousands)

 

 

 

 

 

 

Standardized measure, beginning of year

$   2,109,262 

 

$      2,015,156 

 

$      1,042,755 

Sales and transfers of gas and oil produced, net of production costs

 (1,330,256)

 

 (1,297,068)

 

 (698,299)

Net changes in prices and production costs

 (1,321,404)

 

 (325,300)

 

 431,780 

Extensions, discoveries, and other additions, net of future production and development costs

 978,327 

 

 1,400,044 

 

 1,027,946 

Acquisition of reserves in place

 — 

 

 — 

 

 565 

Sales of reserves in place

 (4,430)

 

 (246,223)

 

 (3,906)

Revisions of previous quantity estimates

 88,261 

 

 161,956 

 

 59,687 

Accretion of discount

 302,439 

 

 259,163 

 

 130,872 

Net change in income taxes

 413,399 

 

 (338,661)

 

 (310,500)

Changes in estimated future development costs

 204,005 

 

 (1,101)

 

 102,760 

Previously estimated development costs incurred during the year

 218,625 

 

 178,444 

 

 134,149 

Changes in production rates (timing) and other

 143,590 

 

 302,852 

 

 97,347 

Standardized measure, end of year

$   1,801,818 

 

$      2,109,262 

 

$      2,015,156 


(5) DERIVATIVES AND RISK MANAGEMENT


The Company is exposed to commodity price risk which impacts the predictability of its cash flows related to the sale of natural gas and oil.  The primary risk managed by the Company’s use of certain derivative financial instruments is commodity price risk.  These derivative financial instruments allow the Company to limit its price exposure to a portion of its projected natural gas sales.  At December 31, 2009 and 2008, the Company’s derivative financial instruments consisted of price swaps, costless-collars and basis swaps. A description of the Company’s derivative financial instruments is provided below:


Fixed price swaps  

The Company receives a fixed price for the contract and pays a floating market price to the counterparty.

 

Floating price swaps

The Company receives a floating market price from the counterparty and pays a fixed price.

 

Costless-collars  

Arrangements that contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.


Basis swaps

Matched and unmatched arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.   


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


The Company utilizes counterparties for its derivative instruments that it believes are credit-worthy at the time the transactions are entered into and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the recent events in the financial markets demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.

 

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None of the Company’s derivative instruments that were outstanding during 2009 and 2008 contained credit-risk-related contingent features except for a certain derivative instrument which expired in December 2009. The credit-risk-related contingent feature required the posting of cash collateral when a net liability owed to that counterparty exceeded a threshold amount.  The required cash collateral amount was equal to the net liability owed to the counterparty less the threshold amount. No collateral amounts were required or remitted to the counterparty.  The Company has not incurred any credit-related losses associated with its derivative activities and believes that its counterparties will continue to be able to meet their obligations under these transactions.


The balance sheet classification of the assets and liabilities related to derivative financial instruments are summarized below at December 31, 2009 and 2008:


 

 

Derivative Assets

 

 

 2009

 

2008

 

 

Balance Sheet Classification

 

Fair Value

 

Balance Sheet Classification

 

Fair Value

 

 

(in thousands)

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

Fixed and floating price swaps

 

Hedging asset

 

$         117,553 

 

Hedging asset

 

$         174,985 

Costless-collars

 

Hedging asset

 

45,516 

 

Hedging asset

 

165,671 

Fixed and floating price swaps

 

Other Assets

 

11,756 

 

Other Assets

 

66,349 

Costless-collars

 

Other Assets

 

 — 

 

Other Assets

 

 26,202 

 

 

 

 

 

 

 

 

 

Total derivatives designated as hedging instruments

 

 

 

$         174,825 

 

 

 

$         433,207 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

Basis swaps

 

Hedging asset

 

$                  — 

 

Hedging asset

 

$             2,664 

Basis swaps

 

Other Assets

 

 — 

 

Other Assets

 

 1,844 

 

 

 

 

 

 

 

 

 

Total derivatives not designated as hedging instruments

 

 

 

$                  — 

 

 

 

$             4,508 

 

 

 

 

 

 

 

 

 

Total derivative assets

 

 

 

$         174,825 

 

 

 

$         437,715 


 

 

Derivative Liabilities

 

 

2009

 

2008

 

 

Balance Sheet Classification

 

Fair Value

 

Balance Sheet Classification

 

Fair Value

 

 

(in thousands)

Derivatives designated as hedging instruments:

 

 

 

 

 

 

 

 

Fixed and floating price swaps

 

Hedging liability

 

$                940 

 

Hedging liability

 

$             2,679 

Costless-collars

 

Hedging liability

 

7,387 

 

Hedging liability

 

5,670 

Fixed and floating price swaps

 

Long-term hedging liability

 

1,373 

 

Long-term hedging liability

 

557 

Costless-collars

 

Long-term hedging liability

 

 — 

 

Long-term hedging liability

 

 5,142 

 

 

 

 

 

 

 

 

 

Total derivatives designated as hedging instruments

 

 

 

$             9,700 

 

 

 

$           14,048 

 

 

 

 

 

 

 

 

 

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

Basis swaps

 

Hedging liability

 

$           11,725 

 

Hedging liability

 

$             2,550 

Basis swaps

 

Long-term hedging liability

 

 1,684 

 

Long-term hedging liability

 

 235 

 

 

 

 

 

 

 

 

 

Total derivatives not designated as hedging instruments

 

 

 

$           13,409 

 

 

 

$             2,785 

 

 

 

 

 

 

 

 

 

Total derivative liabilities

 

 

 

$           23,109 

 

 

 

$           16,833 

 

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Cash Flow Hedges

 

The reporting of gains and losses on cash flow derivative hedging instruments depends on whether the gains or losses are effective at offsetting changes in the cash flows of the hedged item. The effective portion of the gains and losses on the derivative hedging instruments are recorded in other comprehensive income until recognized in earnings during the period that the hedged transaction takes place. The ineffective portion of the gains and losses from the derivative hedging instrument is recognized in earnings immediately.


As of December 31, 2009, the Company had cash flow hedges on the following volumes of gas production:


Natural Gas (Bcf):

 

 

 

Fixed price swaps:

 

2010

 36.0 

2011

 30.0 

 

 

Costless-collars:

 

2010

 30.0 


As of December 31, 2009, the Company has recorded a $95.3 million net gain in accumulated other comprehensive income related to its hedging activities. These amounts are net of a deferred income tax liability recorded as of December 31, 2009 of $58.4 million.  The amount recorded in other comprehensive income will be relieved over time and recognized in earnings as the physical transactions being hedged occur. Assuming the market prices of gas futures as of December 31, 2009 remain unchanged, the Company would expect to transfer an aggregate after-tax net gain of approximately $90.1 million from accumulated other comprehensive income to earnings during the next 12 months.  Gains or losses from derivative instruments designated as cash flow hedges are reflected as adjustments to gas sales in the consolidated statements of operations. Gas sales included a realized gain from settled contracts of $610.4 million for the twelve-month period ended December 31, 2009 compared to a realized loss of $73.1 million during the twelve-month period ended December 31, 2008.  Volatility in earnings and other comprehensive income may occur in the future as a result of the Company’s derivative activities.


The following tables summarize the before tax effect of all cash flow hedges on the consolidated statements of operations for the twelve-month periods ended December 31, 2009 and 2008:


 

 

 

Gain (Loss) Recognized in Other Comprehensive Income

(Effective Portion)

 

 

 

For the twelve months ended

December 31,

Derivative Instrument

 

 

2009

 

2008

 

 

 

(in thousands)

Fixed price swaps

 

 

$                234,775 

 

$                130,937 

Costless-collars

 

 

$                121,597 

 

$                160,713 

Matched-basis swaps

 

 

$                         — 

 

$                    6,135 



 

 

Classification of Gain (Loss) Reclassified from Accumulated Other

 

 

Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Earnings

(Effective Portion)

 

 

Comprehensive Income

 

 

For the twelve months ended

 

 

into Earnings

 

 

December 31,

Derivative Instrument

 

(Effective Portion)

 

 

2009

 

2008

 

 

 

 

 

(in thousands)

Fixed price swaps

 

Gas Sales

 

 

$               345,839 

 

$             (92,369)

Costless-collars

 

Gas Sales

 

 

$              264,528 

 

$              13,002 

Matched-basis swaps

 

Gas Sales

 

 

$                       — 

 

$                6,282 

 

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Gain (Loss) Recognized in Earnings

(Ineffective Portion)

 

 

 

Classification of Gain (Loss)

 

For the twelve months ended

 

 

 

Recognized in Earnings

 

December 31,

 

Derivative Instrument

 

(Ineffective Portion)

 

2009

 

2008

 

 

 

 

 

(in thousands)

 

Fixed price swaps

 

Gas Sales

 

$                 8,424 

 

$               (1,753)

 

Costless-collars

 

Gas Sales

 

$                 1,437 

 

$               (5,214)

 


Fair Value Hedges

 

For fair value hedges, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately.  As of December 31, 2009, the Company had no material fair value hedges.


Other Derivative Contracts


Although the Company’s basis swaps meet the objective of managing commodity price risk, these trades are typically not entered into concurrent with the Company’s derivative instruments that qualify as cash flow hedges and therefore do not generally qualify as cash flow or fair value hedges. Basis swap derivative instruments that do not qualify as cash flow hedges are recorded on the balance sheet at their fair values under hedging assets, other assets and hedging liabilities, and all realized and unrealized gains and losses related to these contracts are recognized immediately in the consolidated statements of operations as a component of gas sales. For the twelve-month period ended December 31, 2009, gas sales included an unrealized loss of $15.1 million for non-qualifying basis swaps. For the twelve-month period ended December 31, 2008, gas sales included an unrealized gain of $2.5 million for non-qualifying basis swaps.  


As of December 31, 2009, the Company had basis swaps on the following volumes of gas production that did not qualify for hedge treatment:


Natural Gas (Bcf):

 

 

 

Basis Swaps:

 

2010

 46.5 

2011

 9.0 


The following table summarizes the before tax effect of basis swaps that did not qualify for hedge accounting on the consolidated statements of operations for the twelve months ended December 31, 2009 and 2008:


 

 

Income Statement Classification

 

Unrealized Gain (Loss) Recognized in Earnings

 

Realized Gain (Loss) Recognized in Earnings

Derivative Instrument

 

of Gain (Loss)

 

2009

 

2008

 

2009

 

2008

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Basis swaps

 

Gas Sales

 

$      (15,133)

 

$         2,452 

 

 $       (9,339)

 

$       40,340 

 

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(6) FAIR VALUE MEASUREMENTS


The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2009 and December 31, 2008 were as follows:


 

2009

 

2008

 

Carrying

 

Fair

 

Carrying

 

Fair

 

Amount

 

Value

 

Amount

 

Value

 

(in thousands)

 

 

 

 

 

 

 

 

Cash and cash equivalents

$           13,184 

 

$           13,184 

 

$         196,277 

 

$         196,277 

Total debt

$         998,700 

 

$      1,031,826 

 

$         735,400 

 

$         648,616 

Derivative instruments

$         151,716 

 

$         151,716 

 

$         420,882 

 

$         420,882 


At December 31, 2009, the carrying values of cash and cash equivalents, accounts receivable, accounts payable, other current assets and current liabilities on the consolidated balance sheets approximate fair value because of their short term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

 

Debt: The fair values of the Company’s 7.5% Senior Notes due 2018, 7.35% Senior Notes due 2017, 7.125% Senior Notes due 2017 and 7.15% Senior Notes due 2018 were based on the market for the Company’s publicly-traded debt as determined based on the December 31, 2009 yield of the Company’s 7.5% Senior Notes due 2018, which was 6.7%. Borrowings of $324.5 million under the Company’s unsecured revolving credit facility at December 31, 2009 approximate fair value.


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


Effective January 1, 2008, the Company partially implemented certain provisions of FASB ASC 820, “Fair Value Measurements and Disclosures,” which defines fair value, provides a framework for measuring fair value under GAAP and expands the required disclosures about fair value measurements. Additionally, on January 1, 2008, the Company implemented certain provisions of FASB ASC 825, “Financial Instruments,” which allow an entity the irrevocable option to elect to use fair value as 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 for any of its financial instruments that are not currently measured at fair value.


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


Level 1 valuations -

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


Level 2 valuations -

Consist of quoted market information for the calculation of fair market value.


Level 3 valuations -

Consist of internal estimates and have the lowest priority.

 

Pursuant to GAAP, the Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s fixed-price and floating-price swaps are estimated using internal discounted cash flow calculations using the NYMEX futures index and are designated as Level 2. The fair values of costless-collars and basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves or quotes obtained from counterparties to the derivative agreements and are designated as Level 3.

 

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


 

December 31, 2009

 

 

 

 

 

Fair Value Measurements Using:

 

 

 

Quoted Prices

 

Significant

 

 

 

 

 

in Active

 

Other

 

Significant

 

 

 

Markets

 

Observable Inputs

 

Unobservable Inputs

 

Assets/Liabilities

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

at Fair Value

Derivative assets

$                         — 

 

$                    129,309 

 

$                        45,516 

 

$                 174,825 

Derivative liabilities

 — 

 

 (2,313)

 

 (20,796)

 

 (23,109)

Total

$                         — 

 

$                    126,996 

 

$                        24,720 

 

$                 151,716 


 

December 31, 2008

 

 

 

 

 

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 table below presents reconciliations for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the twelve-month periods ended December 31, 2009 and December 31, 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 table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect the assumptions a marketplace participant would have used at December 31, 2009 and at December 31, 2008.


Total net gains and losses for Level 3 derivatives for the twelve-month periods ended December 31, 2009 and December 31, 2008 are provided below:


 

For the twelve months ended December 31,

 

2009

 

2008

 

(in thousands)

 

 

 

 

Balance at beginning of period

$              182,823 

 

$                32,767 

Total gains or losses (realized/unrealized):

 

 

 

Included in earnings

 243,806 

 

 58,143 

Included in other comprehensive income (loss)

 (144,368)

 

 152,778 

Purchases, issuances and settlements

 (257,541)

 

 (60,865)

Transfers into/out of Level 3

 — 

 

 — 

Balance at end of period

$                24,720 

 

$              182,823 

Change in unrealized gains (losses) included in earnings relating to derivatives still held as of December 31

$              (13,735)

 

$                (2,722)

 

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(7) DEBT


The components of debt as of December 31, 2009 and 2008 consisted of the following:


 

2009

 

2008

 

(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

 1,200 

 

 61,200 

 

 

 

 

Long-term debt:

 

 

 

Variable rate (1.106% at December 31, 2009) unsecured revolving credit facility, expires February 2012

 324,500 

 

 — 

7.5% Senior Notes due 2018

 600,000 

 

 600,000 

7.35% Senior Notes due 2017

 15,000 

 

 15,000 

7.125% Senior Notes due 2017

 25,000 

 

 25,000 

7.15% Senior Notes due 2018

 33,000 

 

 34,200 

Total long-term debt

 997,500 

 

 674,200 

 

 

 

 

Total debt

$              998,700 

 

$                735,400 


The following is a summary of scheduled long-term debt maturities by year as of December 31, 2009 (in thousands):


2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . .

$             1,200 

2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . .

1,200 

2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . .

 325,700 

2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . .

 1,200 

2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . .

 1,200 

Thereafter. . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . .

 668,200 

 

$         998,700 

 

Issuance of Notes and Subsidiary Guarantees  


On January 16, 2008, the Company completed an offering of $600 million Senior Notes with a coupon rate of 7.5% (“7.5% Senior Notes”), a maturity in February 2018 and semi-annual interest payments. Upon a “change of control,” as defined in the indenture, holders have the option to require the Company to purchase all or any portion of the notes at a purchase price equal to 101% of the principal amount plus accrued and unpaid interest before the change of control date. Payment obligations with respect to the 7.5% Senior Notes were guaranteed at issuance by the Company’s subsidiaries, SEECO, 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 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 the trustees under the indentures relating to the Company’s 7.625% Senior Notes, 7.125% Senior Notes, 7.35% Senior Notes and 7.15% Senior Notes, pursuant to which SEECO, SEPCO and SES became guarantors of such notes to the same extent to which such subsidiaries have guaranteed the Company’s 7.5% Senior Notes. All of these guarantees are currently in place. Please refer to Note 16, “Condensed Consolidating Financial Information” in this Form 10-K for additional information.


The indentures governing the Company’s senior notes contain covenants that, among other things, restrict the ability of the Company and/or its subsidiaries’ ability to incur liens, to engage in sale and leaseback transactions and to merge, consolidate or sell assets.


Optional Redemption of Notes


On May 1, 1997, the Company completed an offering of $60.0 million Senior Notes with a coupon rate of 7.625% (“7.625% Senior Notes”), a maturity date of May 1, 2027 and semi-annual interest payments. The 7.625% Senior Notes were putable at the holders’ option on May 1, 2009 and, as a result, were previously classified as short-term debt at December 31, 2008. In the second quarter of 2009, the 7.625% Senior Notes were put to the Company and the Company

 

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paid the note holders $62.1 million in principal and accrued interest with borrowings from the Company’s Credit Facility (as defined below).

Credit Facility  


On February 9, 2007, the Company amended its unsecured revolving credit facility (as further amended, the “Credit Facility”) with a syndicate of banks for which JPMorgan Chase Bank acts as the Administrative Agent. The Credit Facility expires in February 2012 and has a borrowing capacity of $1.0 billion, which may be increased to up 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 weighted average interest rate related to outstanding borrowings under the Credit Facility was 1.106% at December 31, 2009.


The 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 Credit Facility also contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company must keep total debt (as defined in the Credit Facility) at or below 60% of its total capital (as defined in the Credit Facility), must maintain a certain level of stockholders’ equity (as defined in the Credit Facility), and must maintain a ratio of earnings before interest, taxes, depreciation and amortization (as defined in the Credit Facility) to interest expense of 3.5 or above. There are also restrictions on the ability of the Company’s subsidiaries to incur debt. At December 31, 2009, the Company was in compliance with the covenants of its debt agreements. The credit status of the financial institutions participating in the Company’s Credit Facility could adversely impact its ability to borrow funds under the facility. While the Company believes all of the lenders under the Credit Facility have the ability to provide funds, it cannot predict whether each will be able to meet its obligation under the facility.


Interest Payments


Total cash interest payments made by the Company were $56.7 million in 2009, $42.5 million in 2008 and $36.0 million in 2007.

 

(8) COMMITMENTS AND CONTINGENCIES


Operating Commitments and Contingencies


The E&P and Midstream Services segments have commitments to third parties for demand transportation charges. At December 31, 2009, future payments under non-cancelable demand charges for the E&P and Midstream Services segments are approximately $106.8 million in 2010, $163.4 million in 2011, $195.3 million in 2012, $195.0 million in 2013, $194.5 million in 2014 and $991.9 million thereafter.


Southwestern leases drilling rigs and equipment for its E&P operations under leases that expire on January 1, 2015. The Company’s current aggregate annual payment under the leases is approximately $19.4 million. The lease payments for the drilling rigs and equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to 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 leases compressors, aircraft, office space and equipment under non-cancelable operating leases expiring through 2018.  At December 31, 2009, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $51.3 million in 2010, $49.3 million in 2011, $47.0 million in 2012, $43.7 million in 2013, $39.8 million in 2014 and $32.2 million thereafter.  The Company also has commitments for compression services related to its Midstream Services and E&P segments. At December 31, 2009, future minimum payments under these non-cancelable agreements are approximately $25.4 million in 2010, $21.9 million in 2011, $14.8 million in 2012, $6.2 million in 2013 and $0.2 million in 2014.


At December 31, 2009, the Company had purchase obligations consisting of outstanding purchase orders under existing agreements for approximately $71.5 million.  Included in this amount is $46.4 million of purchase obligations relating to compression units for the Company’s Midstream Services segment.

 

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Environmental Risk


The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or reported results of operations of the Company.


Litigation


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.

 

(9) INCOME TAXES


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


 

2009

 

2008

 

2007

 

(in thousands)

Federal:

 

 

 

 

 

Current

$       (65,309)

 

$         122,000 

 

$                  — 

Deferred

 48,308 

 

 183,601 

 

 120,200 

State:

 

 

 

 

 

Current

 340 

 

 — 

 

 — 

Deferred

 298 

 

 45,445 

 

 15,757 

Investment tax credit amortization

 — 

 

 (47)

 

 (102)

Provision (benefit) for income taxes

$       (16,363)

 

$         350,999 

 

$         135,855 


The provision for income taxes was an effective rate of 31.5% in 2009, 38.2% in 2008 and 38.1% in 2007. 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:  


 

2009

 

2008

 

2007

 

(in thousands)

 

 

 

 

 

 

Expected provision (benefit) at federal statutory rate of 35%

$       (18,205)

 

$         321,631 

 

$         124,960 

Increase (decrease) resulting from:

 

&nb