Organization and Summary of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Organization and Summary of Significant Accounting Policies [Abstract]

Nature of Operations

Southwestern Energy Company (including its subsidiaries, collectively, “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production. The Company engages in natural gas and oil exploration and production, natural gas gathering and natural gas marketing through its subsidiaries. Southwestern’s exploration, development and production (“E&P”) activities are principally focused within the United States on development of an unconventional natural gas reservoir located on the Arkansas side of the Arkoma Basin, which the Company refers to as the Fayetteville Shale play.  The Company is also actively engaged in exploration and production activities in Pennsylvania, where we are targeting the unconventional natural gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin.  The Company has recently commenced exploration operations in southern Arkansas and northern Louisiana testing a new unconventional horizontal oil play targeting the Lower Smackover Brown Dense formation, as well as in Colorado, Montana and Canada.  Southwestern’s natural gas gathering and marketing (Midstream Services) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania and Texas.

Basis of Presentation

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

Certain reclassifications have been made to the prior years financial statements to conform to the 2012 presentation.  The effects of the reclassifications were not material to the Company’s consolidated financial statements. 

Principles of Consolidation

The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries.  All significant intercompany accounts and transactions have been eliminated. In 2010, the Company purchased the non-controlling interest in Overton Partners, L.P. 

Revenue Recognition

Natural gas and oil sales. Natural gas sales and oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties.  Accordingly, natural gas sales and oil sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas sales and oil sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. As of December 31, 2012, the Company had overproduction of 8.4 Bcf valued at $28.4 million and underproduction of 9.4 Bcf valued at $29.9 million. At December 31, 2011, the Company had overproduction of 6.1 Bcf valued at $22.5 million and underproduction of 6.4 Bcf valued at $22.9 million.

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

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

Other. The Company maintains an underground gas storage facility and generally sells natural gas from its storage facility during the winter gas withdrawal season. Revenue is recognized on natural gas storage sales when the natural gas is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. Other revenues, a component of gas sales, include gains of $0.9 million, $0.9 million and $2.5 million in 2012, 2011 and 2010, respectively, primarily related to the sale of natural gas in underground storage.

Cash and Cash Equivalents

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

Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $12.1 million and $47.7 million as of December 31, 2012 and 2011, respectively.

Restricted Cash

Restricted cash represents proceeds deposited by the Company with a qualified intermediary to facilitate like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code. 

Inventory

Inventory recorded in current assets includes $5.6 million as of December 31, 2012 and $7.8 million at December 31, 2011, for natural gas in underground storage owned by the Company’s E&P segment, and $22.5 million as of December 31, 2012 and $38.4 million at December 31, 2011 for tubulars and other equipment used in the E&P segment.

The Company has one natural gas storage facility. The current portion of the natural gas is classified in inventory and carried at the lower of cost or market. The non-current portion of the natural gas is classified in property and equipment and carried at cost. The carrying value of the non-current natural gas is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Withdrawals of current natural gas in underground storage are accounted for by a weighted average cost method whereby natural gas withdrawn from storage is relieved at the weighted average cost of current natural gas remaining in the facility.

Other assets include $13.8 million as of December 31, 2012 and $19.5 million at December 31, 2011 for inventory held by the Midstream Services segment consisting primarily of pipe that will be used to construct gathering systems.

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

Property, Depreciation, Depletion and Amortization

Natural Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-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% (standardized measure) plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense.  The expense may not be reversed in future periods, even though higher natural gas and oil prices may subsequently increase the ceiling. Full cost companies must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.76 per MMBtu and $91.21 per barrel for West Texas Intermediate oil, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling amount and resulted in a ceiling test impairment as of December 31, 2012. The Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $510.4 million (net of tax) as of December 31, 2012 and resulted in a non-cash ceiling test impairment in addition to other ceiling test impairments in 2012 (see below).  Cash flow hedges of natural gas production in place increased this ceiling amount by approximately $257.6 million as of December 31, 2012.  At December 31, 2011, the ceiling value of the Company’s reserves was calculated based upon average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.12 per MMBtu for Henry Hub natural gas and $92.71 per barrel for West Texas Intermediate oil, and at December 31, 2010, the ceiling value of the Company’s reserves was calculated based upon average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.38 per MMBtu for Henry Hub natural gas and $75.96 per barrel for West Texas Intermediate oil.  Using the first-day-of-the-month prices of natural gas for the first two months of 2013 and NYMEX strip prices for the remainder of 2013, as applicable, the prices required to be used to determine the ceiling limit could result in a ceiling test write-down in 2013.  Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.

At September 30, 2012, the net capitalized costs of our natural gas and oil properties exceeded the ceiling by approximately $185.7 million (net of tax) and resulted in a non-cash ceiling test impairment in the third quarter of 2012.  At June 30, 2012, the net capitalized costs of our natural gas and oil properties exceeded the ceiling by approximately $496.4  million (net of tax) and resulted in a non-cash ceiling test impairment in the second quarter of 2012. 

All of our costs directly associated with the acquisition and evaluation of properties in Canada relating to our exploration program as of December 31, 2012 were unproved and did not exceed the ceiling amount.  If our exploration program in Canada is unsuccessful on all or a portion of these properties, or if further extensions are not granted, if requested, a ceiling test impairment may result in the future.

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

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

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

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes.  A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

Derivative Financial Instruments

The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity swaps and options contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges are reported in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item.  In contrast, gains and losses from the ineffective portion of swaps and option contacts as well as basis swap and call option contracts that do not qualify for hedge accounting treatment are recognized currently in gas sales in the consolidated statements of operations.  Changes in the fair value of derivative instruments designated as fair value hedges as well as the offsetting gain or loss on the hedged item are recognized in earnings immediately.  See Note 5 for a discussion of the Company’s hedging activities.

Earnings Per Share

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

As we recognized a net loss for the year ended December 31, 2012, the unvested stock options were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive.  Options for 1,716,109 shares were excluded from the calculation of diluted shares because they would have had an antidilutive effect.  For the year ended December 31, 2011, outstanding options for 3,577,104 shares with an average exercise price of $11.78 were included in the calculation of diluted shares. Options for 881,254 shares were excluded from the calculation because they would have had an antidilutive effect. For the year ended December 31, 2010, outstanding options for 4,753,530shares with an average exercise price of $9.42 were included in the calculation of diluted shares.  Options for 548,160 shares were excluded from the calculation because they would have had an antidilutive effect. 

As we recognized a net loss for the year ended December 31, 2012, the unvested share-based payments were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive.  The calculation of diluted shares excluded 602,429 shares of restricted because they would have had an antidilutive effect.  For the year ended December 31, 2011, 241,044 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 135,352 shares of restricted stock because they would have had an antidilutive effect. For the year ended December 31, 2010, 700,512 shares of restricted stock were included in the calculation of diluted shares. The calculation excluded 39,600 shares of restricted stock because they would have had an antidilutive effect.

Supplemental Disclosures of Cash Flow Information

Supplemental disclosures of cash flow information (in thousands):

	For the years ended December 31,
	2012		2011		2010
	(in thousands)
Cash paid during the year for interest, net of amounts capitalized	$	17,311	$	19,159	$	24,049
Cash paid during the year for income taxes		818		4,198		14,368
Increase (decrease) in noncash property additions	$	(26,240)	$	30,389	$	46,588

Stock-Based Compensation

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

Treasury Stock

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liability of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and are presented as treasury stock and carried at cost. As of December 31, 2012, 64,715 shares were accounted for as treasury stock, compared to 98,889 shares at December 31, 2011.

Foreign Currency Translation

We have designated the Canadian dollar as the functional currency for our operations in Canada.  The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.

New Accounting Standards Implemented in this Report

In May 2011, the FASB issued guidance on fair value measurement and disclosure requirements outlined in Accounting Standards Update No. 2011-04, Fair Value Measurement (Topic 820)–Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (“Update 2011-04”).  Update 2011-04 expands existing fair value disclosure requirements, particularly for Level 3 inputs, including: quantitative disclosure of the unobservable inputs and assumptions used in the measurement; description of the valuation processes in place and sensitivity of the fair value to changes in unobservable inputs and interrelationships between those inputs; the level of items (in the fair value hierarchy) that are not measured at fair value in the balance sheet but whose fair value must be disclosed; and the use of a nonfinancial asset if it differs from the highest and best use assumed in the fair value measurement. The amendments in Update 2011-04 must be applied prospectively and are effective during interim and annual periods beginning after December 15, 2011. The implementation of these changes did not have an impact on the Company’s consolidated results of operations, financial position or cash flows.

In July 2011, the FASB issued Accounting Standards Update No. 2011-05, Presentation of Comprehensive Income (“Update 2011-05”), which amends Topic 200, Comprehensive Income . Update 2011-05 eliminates the option to present components of other comprehensive income (“OCI”) in the statement of changes in stockholders’ equity, and requires presentation of total comprehensive income and components of net income in a single statement of comprehensive income, or in two separate, consecutive statements. Update 2011-05 requires presentation of reclassification adjustments for items transferred from OCI to net income on the face of the financial statements where the components of net income and the components of OCI are presented. The amendments do not change current treatment of items in OCI, transfer of items from OCI, or reporting items in OCI net of the related tax impact. Update 2011-05 is effective for fiscal years and interim periods beginning after December 15, 2011.  The Company early adopted all disclosure requirements of 2011-05 for the year-end December 31, 2011, except those items which were deferred by Accounting Standards Update No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The implementation of these changes did not have an impact on the Company’s results of operations, financial position or cash flows.

Accounting Standards Not Yet Implemented

In February 2013, the FASB issued Accounting Standards Update No. 2013-02,  Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“Update 2013-02”), which finalizes Proposed ASU No. 2012-240, and seeks to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. Update 2013-02 replaces the presentation requirements in ASU No. 2011-05,Comprehensive Income (Topic 220): Presentation of Comprehensive Income, and ASU No. 2011-12,Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. Update 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income. For public entities, Update 2013-02 is effective prospectively for reporting periods beginning after December 15, 2012, with early adoption permitted.  The implementation of the disclosure requirement is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

In January 2013, the FASB issued Accounting Standards Update No. 2013-01,Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”), which finalizes Proposed ASU No. 2012-250 and clarifies the scope of transactions that are subject to disclosures concerning offsetting. Update 2013-01 addresses implementation issues regarding the scope of ASU No. 2011-11,Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, issued in December 2011. Update 2013-01 clarifies that the scope of the disclosures under U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are offset either in accordance with FASB ASC Section 210-20-45,Balance Sheet—Offsetting—Other Presentation Matters, or FASB ASC Section 815-10-45,Derivatives and Hedging—Overall—Other Presentation Matters, or are subject to a master netting arrangement or similar agreement.  Update 2013-01 requires an entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to provide the required disclosures retrospectively for all comparative periods presented.  The implementation of the disclosure requirement is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.