SOUTHWESTERN ENERGY CO
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:
(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:
Drilling and Other Exploratory and Development Activities:
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Present Activities
Wells in progress as of December 31, 2009:
Production, Average Sales Price and Average Production Cost:
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.
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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
Steven L. Mueller
President and Chief Executive Officer
Greg D. Kerley
Executive Vice President and Chief Financial Officer
Mark K. Boling
Executive Vice President, General Counsel and Secretary
Gene A. Hammons
President, Southwestern Midstream Services Company
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.
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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.
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
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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.”
(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.
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(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
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 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.
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.
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
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Equity for the fiscal years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements, December 31, 2009, 2008 and 2007
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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
(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
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
(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
(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)
(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:
(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:
The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2009.
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:
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:
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:
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:
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:
(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:
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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:
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:
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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:
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:
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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:
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):
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:
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(7) DEBT
The components of debt as of December 31, 2009 and 2008 consisted of the following:
The following is a summary of scheduled long-term debt maturities by year as of December 31, 2009 (in thousands):
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:
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:
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The components of the Company’s net deferred tax liability as of December 31, 2009 and 2008 were as follows:
The net deferred tax liability at December 31, 2009 was comprised of net long-term deferred income tax liabilities of $811.9 million, partially offset by a net current deferred income tax asset of $19.2 million. The net deferred tax liability at December 31, 2008 was comprised of net long-term deferred income tax liabilities of $721.7 million in addition to a net current deferred income tax liability of $122.5 million. In 2009, the Company paid $0.3 million in state income taxes and received a $41.8 million income tax refund. There were $107.5 million in income tax payments made in 2008 and none in 2007. The Company’s net operating loss carryforward at December 31, 2009 was $627.0 million and has expiration dates of 2027 through 2029. The Company also had an alternative minimum tax credit carryforward of $59.7 million and a statutory depletion carryforward of $12.1 million at December 31, 2009.
Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises in 2009. Some exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the grant (“windfalls”). Although these additional tax benefits or “windfalls” are reflected in net operating loss carryforwards, pursuant to GAAP, the additional tax benefit associated with the windfall is not recognized until the deduction reduces tax payable. Accordingly, since the tax benefit does not reduce our current taxes payable in 2009 due to net operating loss carryforwards, these “windfall” tax benefits are not reflected in our net operating losses in deferred tax assets for 2009. Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2009 were $85.3 million.
For the three months ended March 31, 2009, the Company recognized an increase of approximately $50.0 million in unrecognized tax benefits related to alternative minimum taxes associated with uncertain tax positions. These unrecognized benefits were subsequently reduced during the three months ended September 30, 2009. As of December 31, 2009, the Company has no unrecognized tax benefits. The income tax years 2006-2008 remain open to examination by the major taxing jurisdictions to which the Company is subject.
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(10) ASSET RETIREMENT OBLIGATIONS
The following table summarizes the Company’s 2009 and 2008 activity related to asset retirement obligations:
(11) RETIREMENT AND EMPLOYEE BENEFIT PLANS
401(k) Defined Contribution Plan
The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $0.8 million, $1.1 million and $1.1 million of contribution expense in 2009, 2008 and 2007, respectively. Additionally, the Company capitalized $3.3 million, $2.4 million and $1.7 million of contributions in 2009, 2008 and 2007, respectively, 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.
Defined Benefit Pension and Other Postretirement Plans
Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.
The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.
Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.
As a result of the sale of Arkansas Western Gas on July 1, 2008, the Company transferred pension and other postretirement plan assets and liabilities related to the employees of Arkansas Western Gas to the purchaser. The Company also incurred a net curtailment and settlement cost of $4.4 million resulting from the transfer of certain pension and other postretirement plan assets and liabilities to the purchaser of Arkansas Western Gas. Accordingly, the net curtailment and settlement cost was included as an offset to the gain recognized on the sale of Arkansas Western Gas.
The amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during the next fiscal year are $0.3 million for prior service costs, $0.7 million net loss and $0.1 million for transition obligation costs.
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The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets, and funded status as of December 31, 2009 and 2008:
The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded status for each period as presented above.
The change in accumulated other comprehensive income related to the pension plans was a gain of $0.4 million ($0.2 million after tax) for the year ended December 31, 2009 and a loss of $0.3 million ($0.2 million after tax) for the year ended December 31, 2008. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a loss of less than $0.1 million for the year ended December 31, 2009 and was a gain of $0.4 million ($0.2 million after tax) for the year ended December 31, 2008. Included in accumulated other comprehensive income at December 31, 2009 and 2008 was a $17.8 million loss ($11.0 million net of tax) and an $18.2 million loss ($11.2 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans.
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The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2009 and 2008 are as follows:
Pension and other postretirement benefit costs include the following components for 2009, 2008 and 2007:
(1) Related to the sale of Arkansas Western Gas and the resulting transfer of certain pension and other postretirement assets and liabilities to the purchaser. Accordingly, the net curtailment and settlement cost was included as an offset to the gain recognized on the sale of Arkansas Western Gas.
Amounts recognized in other comprehensive income for the year ended December 31, 2009 were as follows:
The weighted average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2009 and 2008 are as follows:
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The weighted average assumptions used in the measurement of the Company’s net periodic benefit cost for 2009, 2008 and 2007 are as follows:
The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee Retirement Income Security Act and with a prudent level of diversification.
For measurement purposes, the following trend rates were assumed for 2009 and 2008:
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
As a result of the sale of Arkansas Western Gas on July 1, 2008, the Company transferred all other postretirement plan assets to the purchaser.
Pension Payments and Asset Management
In 2009, the Company contributed $9.0 million to its pension plans and less than $0.1 million to its other postretirement benefit plan. The Company expects to contribute $9.6 million to its pension plans and $0.1 million to its other postretirement benefit plan in 2010. No plan assets are expected to be returned to the Company during the next twelve months.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
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The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth of plan assets and to ensure adequate liquidity exists for the near-term benefit payment of obligations to participants, retirees and beneficiaries. The Retirement Committee of the Company’s Board of Directors (“Retirement Committee”) administers the Company’s pension plan assets. The Retirement Committee believes long-term investment performance is a function of asset-class mix and restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets, international equity markets or investment grade fixed income assets.
The table below presents the allocations targeted by the Retirement Committee and the actual weighted-average asset allocation of the Company’s pension plan at December 31, 2009, by asset category. The asset allocation targets are subject to change and the Retirement Committee allows for its actual allocations to deviate from target as a result of current and anticipated market conditions. Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range.
Utilizing GAAP’s fair value hierarchy, the Company’s fair value measurement of pension plan assets at December 31, 2009 are as follows:
(1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3) Mutual fund that seeks to replicate the Standards & Poor’s 500 index by investing at least 80% of assets in S&P 500 stocks.
(4) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(5) Mutual fund that seeks to invest in a diversified portfolio of stocks and fixed income securities with at least 80% of its investments in securities issued in Europe or the Pacific Basin.
(6) Mutual fund that seeks to invest in a diversified portfolio of bonds with investment grade quality United States (“U.S.”) dollar-denominated securities of U.S. issuers.
The Company’s pension plan assets are classified as Level 1 due to the fact the all of the pension plan’s investments are comprised of either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fair value measurement as Level 1. No concentration of risk arising within or across categories of plan assets exists due to any significant investments in a single entity, industry, country or investment fund.
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(12) EQUITY
Common Stock Purchase Rights
On April 8, 2009, the Company’s Board of Directors approved and the Company entered into, a Second Amended and Restated Rights Agreement (“Rights Agreement”), dated as of April 9, 2009, between the Company and Computershare Trust Company, N.A., which amended, restated, superseded and replaced the Amended and Restated Rights Agreement dated as of April 12, 1999, as amended. The Rights Agreement extends the term of the agreement until April 8, 2019 and amends each Right (which initially represented the right to purchase one share of the Common Stock) to represent the right to purchase, when exercisable, a unit consisting of one one-thousandth of a share (“Unit”) of Series A Junior Participating Preferred Stock, par value $0.01 per share (“Series A Preferred Stock”) at a purchase price of $150.00 per Unit (“Purchase Price”), subject to adjustment.
In connection with the Rights Agreement, the Board of Directors approved the Certificate of Designation, Preferences and Rights (“Certificate of Designation”) establishing the Series A Preferred Stock, which was filed with the Secretary of State of the State of Delaware on April 9, 2009, and reserved 1,000,000 shares for issuance under the Rights Agreement. Pursuant to the Certificate of Designation, when issued, each share of the Series A Preferred Stock entitles the holder thereof to 1,000 votes, subject to adjustment, on all matters submitted to a vote of the stockholders of the Company. Except as otherwise set forth in the Certificate of Designation or provided by law, the holders of shares of the Series A Preferred Stock and the holders of shares of the Common Stock will vote together as one class on all matters submitted to a vote of stockholders of the Company.
On February 24, 2010, the Company's Board of Directors approved, and the Company and Computershare Trust Company, N.A., as rights agent, entered into, an amendment to the Rights Agreement pursuant to which the Final Expiration Date of the Rights (each as defined in the Rights Agreement) was advanced from April 8, 2019 to February 26, 2010. As a result of the amendment, as of 5:00 p.m. E.S.T. on February 26, 2010, the rights will no longer be outstanding and will not be exercisable.
Treasury Stock
The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liability of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and are presented as treasury stock and carried at cost. As of December 31, 2009, 203,830 shares were accounted for as treasury stock, compared to 225,050 shares at December 31, 2008.
(13) STOCK-BASED COMPENSATION
The Southwestern Energy Company 2004 Stock Incentive Plan (2004 Plan) was adopted in February 2004 and approved by stockholders in May 2004. The 2004 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2004 Plan replaced the Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan) and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (2002 Plan) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The awards under the prior plans have been adjusted for stock splits as permitted under such plans.
The 2004 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units to employees, officers and directors that in the aggregate do not exceed 16,800,000 shares. The types of incentives that may be awarded are comprehensive and are intended to enable the Company’s board of directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2004 Plan.
As initially adopted, the 2000 Plan provided for the grant of options, stock appreciation rights, shares of phantom stock, and shares of restricted stock to employees, officers and directors that in the aggregate did not exceed 1,250,000 shares of common stock. As initially adopted, the 2002 Plan provided for grants of options, stock appreciation rights, shares of phantom stock and shares of restricted stock that in the aggregate did not exceed 300,000 shares to employees who are not officers or directors of the Company under provisions of Section 16 of the Securities Exchange Act of 1934, as amended.
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The Company may utilize treasury shares, if available, or authorized but unissued shares when a stock option is exercised or when restricted stock is granted.
The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. All options are issued at fair market value at the date of grant and expire seven years from the date of grant for awards under the 2004 Plan and ten years from the date of grant for awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three years from the grant date. The Company issues shares of restricted stock to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards granted to participants who have reached retirement age or will reach retirement age during the vesting period. Restricted stock and stock options granted to participants on or after December 8, 2005 immediately vest upon death, disability or retirement (subject to a minimum of five years of service).
Stock Options
For the years ended December 31, 2009, 2008 and 2007, the Company recorded compensation costs of $5.1 million, $3.6 million and $2.7 million, respectively, in general and administrative expense related to stock options. Additional amounts of $2.1 million, $1.1 million and $0.7 million for the same respective periods were capitalized. The Company also recorded a deferred tax benefit of $1.4 million related to stock options in 2009, compared to deferred tax benefits of $1.2 million in 2008 and $0.6 million in 2007. A total of $13.3 million of unrecognized compensation costs related to stock options not yet vested is expected to be recognized over future periods. That cost is expected to be recognized over a weighted-average period of 2.3 years.
The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on exercise of stock options, post vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant.
The following tables summarize stock option activity for the years 2009, 2008 and 2007 and provide information for options outstanding at December 31 of such years. The number of options and exercise prices have been restated, as necessary, to reflect the two-for-one stock split effected on March 25, 2008:
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The weighted-average grant-date fair value of options granted during the years 2009, 2008 and 2007 was $21.35, $15.82 and $11.16, respectively. The total intrinsic value of options exercised during 2009, 2008 and 2007 was $87.6 million, $60.0 million and $69.9 million, respectively. Associated with the exercise of stock options for 2008, the Company recorded a tax benefit of $43.1 million as an increase to additional paid-in capital.
Restricted Stock
For the years ended December 31, 2009, 2008 and 2007, the Company recorded compensation costs of $5.1 million, $4.0 million and $2.7 million, respectively, in general and administrative expense related to restricted stock grants. Additional amounts of $3.8 million, $2.8 million and $1.9 million for the same respective periods were capitalized. The Company also recorded a deferred tax liability of $0.7 million related to restricted stock for the year ended December 31, 2009, compared to deferred tax liabilities of $3.5 million for 2008 and $1.1 million for 2007. As of December 31, 2009, there was $23.3 million of total unrecognized compensation cost related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of 3.1 years.
The following table summarizes the restricted stock activity for the years 2009, 2008 and 2007 and provides information for restricted stock outstanding at December 31 of such years. The number of shares and the grant date fair values have been restated, as necessary, to reflect the two-for-one stock split effected on March 25, 2008:
The fair values of the grants were $12.5 million for 2009, $14.0 million for 2008 and $7.8 million for 2007. The total fair value of shares vested were $14.9 million for 2009, $9.3 million for 2008 and $11.3 million for 2007.
(14) SEGMENT INFORMATION
The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and crude oil. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced gas volumes and through gathering fees associated with the transportation of natural gas to market. The Company’s Natural Gas Distribution segment, which generated revenue from the transportation and sale of natural gas at retail, ceased with the July 1, 2008, sale of the utility.
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Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs and expenses. Income before income taxes, for the purpose of reconciling the operating income (loss) amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, interest and other income (loss), and gain on sale of utility assets. The “Other” column includes items not related to the Company’s reportable segments including real estate and corporate items.
(1) Interest and other income (loss), interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as cash equivalents, debt and income tax expense are incurred at the corporate level.
(2) Includes capital investments for office, technology, drilling rigs and other ancillary equipment not directly related to gas and oil property acquisition, exploration and development activities.
(3) Capital investments include an increase of $12.2 million for 2009, an increase of $36.2 million for 2008 and a reduction of $20.6 million for 2007 related to the change in accrued expenditures between years.
(4) Includes $195.1 million of the remaining cash proceeds generated from the Company’s 2008 asset sales, as described in Note 2.
Included in intersegment revenues of the Midstream Services segment are $0.9 billion, $1.3 billion and $0.6 billion for 2009, 2008 and 2007, respectively, for marketing of the Company’s E&P sales. Prior to the sale of the utility, intersegment sales by the E&P segment and Midstream Services segment to the Natural Gas Distribution segment were priced in accordance with terms of the existing contracts and market conditions. Corporate assets include cash and cash equivalents, furniture and fixtures, prepaid debt and other costs. Parent company general and administrative costs,
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depreciation expense and taxes other than income are allocated to segments. All of the Company’s operations are located within the United States.
(15) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the years ended December 31, 2009 and 2008:
(1) Includes a non-cash ceiling test impairment of our natural gas and oil properties of $907.8 million, before taxes.
(2) Includes a non-cash ceiling test impairment of our natural gas and oil properties of $558.3 million, net of taxes, or $1.62 per basic and diluted earnings per share.
(3) Includes an after-tax gain on the sale of the Company’s utility segment of $35.4 million, or $0.10 per basic and diluted earnings per share.
(16) CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The Company is providing condensed consolidating financial information for SEECO, SEPCO and SES, its subsidiaries that are guarantors of the Company’s registered public debt, and for its other subsidiaries that are not guarantors of such debt. These wholly owned subsidiary guarantors have jointly and severally, fully and unconditionally guaranteed the Company’s 7.625% Senior Notes and 7.21% Senior Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated to any future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors.
The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees. The following condensed consolidating financial information summarizes the results of operations, financial position and cash flows for the Company’s guarantor and non-guarantor subsidiaries.
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(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.
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(17) SUBSEQUENT EVENTS
The Company evaluates subsequent events through the date the financial statements are issued, which for the annual period ended December 31, 2009, is February 25, 2010. No additional subsequent event, other than the amendment to the Rights Agreement discussed in Note 12, requiring disclosure was identified by the Company.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act). Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2009. There were no changes in our internal control over financial reporting during the three months ended December 31, 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting is included on page 65 of this Form 10-K.
ITEM 9B. OTHER INFORMATION
There was no information required to be disclosed in a current report on Form 8-K during the fourth quarter of the fiscal year ended December 31, 2009, that was not reported on such form.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The definitive Proxy Statement to holders of our common stock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Stockholders to be held on or about May 18, 2010 (“2010 Proxy Statement”), is hereby incorporated by reference for the purpose of providing information about our directors, and for discussion of our audit committee and our audit committee financial expert. We refer you to the sections “Proposal No. 1: Election of Directors” and “Share Ownership of Management, Directors and Nominees” in the 2010 Proxy Statement for information concerning our directors. We refer you to the section “Corporate Governance - Committees of the Board of Directors” in the 2010 Proxy Statement for discussion of our audit committee and our audit committee financial expert. Information concerning our executive officers is presented in Part I of this Form 10-K. We refer you to the section “Section 16(a) Beneficial Ownership Reporting Compliance” in the 2010 Proxy Statement for information relating to compliance with Section 16(a) of the Exchange Act.
The Company has adopted a code of ethics that applies to the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.swn.com, and is available free of charge in print to any stockholder who requests it. Requests for copies should be addressed to the Secretary at 2350 N. Sam Houston Parkway East, Suite 125, Houston TX, 77032.
ITEM 11. EXECUTIVE COMPENSATION
The 2010 Proxy Statement is hereby incorporated by reference for the purpose of providing information about executive compensation, compensation committee interlocks and insider participation as well as the Compensation Committee Report. We refer you to the sections “Compensation Discussion & Analysis,” “Executive Compensation,” “Outside Director Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the 2010 Proxy Statement.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The 2010 Proxy Statement is hereby incorporated by reference for the purpose of providing information about securities authorized for issuance under our equity compensation plans and security ownership of certain beneficial owners and our management. For information about our equity compensation plans, refer to “Equity Compensation Plans” in our 2010 Proxy Statement. Refer to the sections “Security Ownership of Certain Beneficial Owners” and “Share Ownership of Management, Directors and Nominees” in our 2010 Proxy Statement for information about security ownership of certain beneficial owners and our management and directors.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The 2010 Proxy Statement is hereby incorporated by reference for the purpose of providing information about certain relationships, related transactions and board independence. Refer to the sections “Transactions with Related Persons,” “Share Ownership of Management, Directors and Nominees,” and “Compensation Discussion and Analysis” for information about transactions with our executive officers, directors or management and to “Corporate Governance - Director Independence” and “ - Committees of the Board of Directors” for information about director independence.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The 2010 Proxy Statement is hereby incorporated by reference for the purpose of providing information about fees paid to the principal accountant and the audit committee’s pre-approval policies and procedures. We refer you to the section “Relationship with Independent Registered Public Accounting Firm” in the 2010 Proxy Statement and to Exhibit A thereto for information concerning fees paid to our principal accountant and the audit committee’s pre-approval policies and procedures and other required information.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) (1)
The consolidated financial statements of Southwestern Energy Company and its subsidiaries and the report of independent registered public accounting firm are included in Item 8 of this Form 10-K.
(2) The consolidated financial statement schedules have been omitted because they are not required under the related instructions, or are not applicable.
(3)
The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Form 10-K.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused the report to be signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHWESTERN ENERGY COMPANY
Dated: February 25, 2010
BY:
/s/ GREG D. KERLEY
Greg D. Kerley
Executive Vice President
And Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 25, 2010.
/s/ HAROLD M. KORELL
Director, Executive Chairman
Harold M. Korell
/s/ STEVEN L. MUELLER
Director, President and Chief Executive Officer
Steven L. Mueller
/s/ GREG D. KERLEY
Executive Vice President and Chief Financial Officer
Greg D. Kerley
/s/ ROBERT C. OWEN
Controller and Chief Accounting Officer
Robert C. Owen
/s/ LEWIS E. EPLEY, JR.
Director
Lewis E. Epley, Jr
/s/ ROBERT L. HOWARD
Director
Robert L. Howard
/s/ VELLO A. KUUSKRAA
Director
Vello A. Kuuskraa
/s/ KENNETH R. MOURTON
Director
Kenneth R. Mourton
/s/ CHARLES E. SCHARLAU
Director
Charles E. Scharlau
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EXHIBIT INDEX
Exhibit Number
Description
3.1
Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
3.2*
Amended and Restated Bylaws of Southwestern Energy Company, effective February 24, 2010.
4.1
Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.2
Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock, dated April 9, 2009. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 9, 2009)
4.3
Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First National Bank of Chicago, as trustee. (Incorporated by reference to Exhibit 4 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (File No. 33-63895) filed on November 17, 1995)
4.4
First Supplemental Indenture between Southwestern Energy Company and J.P. Morgan Trust Company, N.A. (as successor to the First National Bank of Chicago) dated June 30, 2006. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.5
Second Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee (as successor to J.P. Morgan Trust Company, N.A.), dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
4.6
Indenture dated June 1, 1998 by and among NOARK Pipeline Finance, L.L.C. and The Bank of New York. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)
4.7
First Supplemental Indenture dated May 2, 2006 by and among Southwestern Energy Company, NOARK Pipeline Finance, L.L.C., and UMB Bank, N.A., as trustee (as successor to the Bank of New York). (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)
4.8
Second Supplemental Indenture between Southwestern Energy Company and UMB Bank, N.A., as trustee, dated June 30, 2006. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.9
Third Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and UMB Bank, N.A., as trustee, dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
4.10
Second Amended and Restated Rights Agreement, dated as of April 9, 2009, between Southwestern Energy Company and Computershare Trust Company, N.A., as Rights Agent. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on April 9, 2009)
4.11
Guaranty dated June 1, 1998 by Southwestern Energy Company in favor of The Bank of New York, as trustee, under the Indenture dated as of June 1, 1998 between NOARK Pipeline Finance L.L.C. and such trustee. (Incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2005)
4.12
Second Amended and Restated Credit Agreement dated February 9, 2007 among Southwestern Energy Company, JPMorgan Chase Bank, NA, SunTrust Bank, The Royal Bank of Scotland PLC, Royal Bank of Canada, Bank of America, N.A., and the other lenders named therein, JPMorgan Chase Bank, NA, as administrative agent, SunTrust Bank as syndication agent. (Incorporated by reference to Exhibit 4.11 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2006)
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4.13
First Amendment dated October 12, 2007 to Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as Administrative Agent, and a lender under the facility, SunTrust Bank as Syndication Agent, Bank of America, N.A., Royal Bank of Canada and Royal Bank of Scotland plc. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2007)
4.14
Second Amendment to Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as Administrative Agent, and a lender under the facility, SunTrust Bank as Syndication Agent, Bank of America, N.A., Royal Bank of Canada and Royal Bank of Scotland plc. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2008)
4.15
Indenture dated January 16, 2008 among Southwestern Energy Company, the Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 16, 2008)
4.16
Policy on Confidential Voting of Southwestern Energy Company. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2006 Annual Meeting of Stockholders)
10.1
Form of Second Amended and Restated Indemnity Agreement between Southwestern Energy Company and each Executive Officer and Director of the Registrant. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
10.2
Form of Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company, effective February 17, 1999. (Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.3
Form of Amendment to Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.4
Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.2(b) to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.5
Amendment to Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.6*
Second Amendment to Southwestern Energy Company Incentive Compensation Plan.
10.7
Southwestern Energy Company Supplemental Retirement Plan as amended. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.8
Southwestern Energy Company Non-Qualified Retirement Plan as amended. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.9*
Amendment One to the Southwestern Energy Company Non-Qualified Retirement Plan.
10.10
Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2000 Annual Meeting of Stockholders)
10.11
Southwestern Energy Company 2002 Employee Stock Incentive Plan, effective October 23, 2002. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
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10.12
Southwestern Energy Company 2002 Performance Unit Plan, as amended, effective December 31, 2008. (Incorporated by reference to Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.13
Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)
10.14
Form of Incentive Stock Option Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.15
Form of Restricted Stock Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.16
Form of Non-Qualified Stock Option Agreement for non-employee directors for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.17
Form of Incentive Stock Option for awards granted on or after December 8, 2005 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.18
Form of Restricted Stock Agreement for awards granted on or after December 8, 2005 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.19
Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8, 2005 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.20
Master Lease Agreement by and between Southwestern Energy Company and SunTrust Leasing Corporation dated December 29, 2006. (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2006)
10.21
Guaranty by and between Southwestern Energy Company and Texas Gas Transmission, LLC, dated as of October 27, 2008. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2008)
10.22*
Guaranty by and between Southwestern Energy Company and Fayetteville Express Pipeline, LLC dated September 30, 2008.
10.23
Amended and Restated Project Services Agreement by and between SEECO, Inc., a wholly-owned subsidiary of Southwestern Energy Company, and Schlumberger Technology Corporation dated February 16, 2009. (Incorporated by reference to Exhibit 10.24 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
21.1*
List of Subsidiaries.
23.1*
Consent of PricewaterhouseCoopers LLP.
23.2*
Consent of Netherland, Sewell & Associates, Inc.
31.1*
Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*
Certification of CEO and CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*
Reserve Audit Report of Netherland, Sewell & Associates, Inc., dated February 10, 2010.
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101.INS*
Interactive Data File Instance Document
101.SCH*
Interactive Data File Schema Document
101.CAL*
Interactive Data File Calculation Linkbase Document
101.LAB*
Interactive Data File Label Linkbase Document
101.PRE*
Interactive Data File Presentation Linkbase Document
101.DEF*
Interactive Data File Definition Linkbase Document
____________
*Filed herewith
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