Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Significant Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy and its wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on inland waters and onshore oil and natural gas reserves in Louisiana and Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.

Discontinued Operations

Discontinued Operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to Swift Energy’s continuing operations. Information related to discontinued operations is included in Note 8 and in some instances, where appropriate, is included as a separate disclosure within the individual footnotes.

Subsequent Events

Subsequent Events. We have evaluated subsequent events of our consolidated financial statements. There were no material subsequent events requiring additional disclosure in these financial statements.

Use of Estimates

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:

• the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and the related present value of estimated future net cash flows there-from,

• estimates related to the collectability of accounts receivable and the credit worthiness of our customers,

• estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,

• estimates of future costs to develop and produce reserves,

• accruals related to oil and gas sales, capital expenditures and lease operating expenses,

• estimates of insurance recoveries related to property damage, and the solvency of insurance providers,

• estimates in the calculation of share-based compensation expense,

• estimates of our ownership in properties prior to final division of interest determination,

• the estimated future cost and timing of asset retirement obligations,

• estimates made in our income tax calculations, and

• estimates in the calculation of the fair value of hedging assets.

While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs.

Property and Equipment

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years 2011, 2010, and 2009, such internal costs capitalized totaled $29.3 million, $24.6 million, and $24.5 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. For the years 2011, 2010, and 2009, capitalized interest on unproved properties totaled $7.7 million, $7.4 million, and $6.1 million, respectively. Interest not capitalized and general and administrative costs related to production and general corporate overhead are expensed as incurred.

The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances.

Property and Equipment (in thousands)	December 31, 2011			December 31, 2010
Property and Equipment
Proved oil and gas properties	$	4,343,867		$	3,835,173
Unproved oil and gas properties		84,146			78,429
Furniture, fixtures, and other equipment		38,832			37,505
Less – Accumulated depreciation, depletion, and amortization		(2,599,079	)		(2,378,262	)
Property and Equipment, Net	$	1,867,766		$	1,572,845

No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

Future development costs are estimated property-by-property based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized.

We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties—including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties—by an overall rate determined by dividing the physical units of oil and natural gas produced during the period by the total estimated units of proved oil and natural gas reserves at the beginning of the period. This calculation is done on a country-by-country basis, and the period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between 2 and 20 years. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are directly associated with specific unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.

Full-Cost Ceiling Test

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials and the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). Our hedges in place at year-end 2011 and 2010 consisted of price floors that did not materially affect prices used in these calculations. This calculation is done on a country-by-country basis.

The calculation of the Ceiling Test and provision for DD&A is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

In 2009, as a result of low oil and natural gas prices at March 31, 2009, we reported a non-cash write-down on a before-tax basis of $79.3 million on our oil and natural gas properties.

Given the volatility of oil and natural gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could continue to change in the near term. If oil and natural gas prices decline from our prices used in the Ceiling Test, it is reasonably possible that non-cash write-downs of oil and natural gas properties would occur in the future. If we have significant declines in our oil and natural gas reserves volumes, which also reduce our estimate of discounted future net cash flows from proved oil and natural gas reserves, non-cash write-downs of our oil and natural gas properties would occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties if a decrease in oil and/or natural gas prices were to occur.

Revenue Recognition

Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Swift Energy uses the entitlement method of accounting in which we recognize our ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets. Natural gas balancing receivables are reported in “Other current assets” on the accompanying consolidated balance sheets when our ownership share of production exceeds sales. As of December 31, 2011 and 2010, we did not have any material natural gas imbalances.

Reclassification of Prior Period Balances

Reclassification of Prior Period Balances. Certain reclassifications have been made to prior period amounts to conform to the current year presentation.

Accounts Receivable

Accounts Receivable. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2011 and 2010, we had an allowance for doubtful accounts of approximately $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts Receivable” balance on the accompanying consolidated balance sheets.

At December 31, 2011 our “Accounts Receivable” balance included $54.7 million for oil and gas sales, $4.2 million for joint interest owners and $5.6 million for other receivables. At December 31, 2010 our “Accounts Receivable” balance included $43.3 million for oil and gas sales, $2.3 million for joint interest owners and $1.4 million for other receivables.

Debt Issuance Costs

Debt Issuance Costs. Legal fees, accounting fees, underwriting fees, printing costs, and other direct expenses associated with extensions of our bank credit facility and public debt offerings were capitalized and are amortized on an effective interest basis over the life of each of the respective note offerings and credit facility.

The 7-1/8% senior notes due 2017 mature on June 1, 2017, and the balance of their issuance costs at December 31, 2011, was $2.6 million, net of accumulated amortization of $1.5 million. The 8-7/8% senior notes due 2020 mature on January 15, 2020, and the balance of their issuance costs at December 31, 2011, was $4.3 million, net of accumulated amortization of $0.7 million. The 7-7/8% senior notes due 2022 mature on March 1, 2022, and the balance of their issuance costs at December 31, 2011, was $4.7 million, net of accumulated amortization of less than $0.1 million. The issuance costs associated with our revolving credit facility, which was revised and extended in May 2011, have been capitalized and are being amortized over the life of the facility. The balance of revolving credit facility issuance costs at December 31, 2011, was $3.5 million, net of accumulated amortization of $4.0 million.

Price-Risk Management Activities

Price-Risk Management Activities. The Company follows FASB ASC 815-10, which requires that changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The guidance also establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the consolidated balance sheets as either an asset or a liability measured at its fair value. Hedge accounting for a qualifying hedge allows the gains and losses on derivatives to offset related results on the hedged item in the statement of operations and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Changes in the fair value of derivatives that do not meet the criteria for hedge accounting, and the ineffective portion of the hedge, are recognized currently in income.

We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, mainly through the purchase of price floors and collars. During 2011, 2010, and 2009, we recognized net gains (losses) of ($0.9) million, $0.7 million, and ($1.4) million, respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying consolidated statements of operations. Had these gains (losses) been recognized in the oil and gas sales account they would not have materially changed our per unit sales prices received. At December 31, 2011, the Company did not have any derivative gains (losses) in “Accumulated other comprehensive loss, net of income tax” on the accompanying consolidated balance sheets. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for 2011, 2010 and 2009 was not material.

At December 31, 2011, we had one oil price floor in effect that covers production of 81,500 barrels of oil for January 2012 with a strike price of $96.80.

When we entered into these transactions discussed above, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of oil and natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in “Accumulated other comprehensive loss, net of income tax.” When the hedged transactions are recorded upon the actual sale of the oil and natural gas, these gains or losses are reclassified from “Accumulated other comprehensive loss, net of income tax” on the accompanying consolidated balance sheets and are recorded in “Price-risk management and other, net” on the accompanying consolidated statements of operations. The fair values of our derivatives are computed using the Black-Scholes-Merton option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2011 and 2010, was $0.1 million and $0.3 million, respectively, and was recognized on the accompanying consolidated balance sheets in “Other current assets.” At December 31, 2010, we had less than $0.1 million in receivables for settled gas hedges covering January 2011 production which are recognized on the accompanying balance sheet in “Accounts Receivables” and were subsequently collected in January 2011.

Supervision Fees

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees, to the extent they do not exceed actual costs incurred, are recorded as a reduction to “General and administrative, net.” Our supervision fees are based on COPAS guidelines. The amount of supervision fees charged for 2011 and 2010 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operate was $12.9 million in 2011, $12.5 million in 2010, and $11.4 million in 2009.

Inventories

Inventories. Inventories consist primarily of tubulars and other equipment that we expect to place in service in production operations. Inventories carried at cost (weighted average method) are included in “Other current assets” on the accompanying consolidated balance sheets totaling $3.6 million and $12.8 million at December 31, 2011 and 2010, respectively.

During 2011 we recorded a charge of $2.1 million related to inventory obsolescence in “Price-risk management and other, net” on the accompanying condensed statement of operations.

Income Taxes

Income Taxes. Under guidance contained in FASB ASC 740-10, deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.

We follow the recognition and disclosure provisions under guidance contained in FASB ASC 740-10-25. Under this guidance, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As a result of adopting this guidance on January 1, 2007, we reported a $1.0 million decrease to our January 1, 2007 retained earnings balance and a corresponding increase to other long-term liabilities. If recognized, these tax benefits would fully impact our effective tax rate.

We do not believe the total of unrecognized tax positions will significantly increase or decrease during the next 12 months.

Our policy is to record interest and penalties relating to income taxes in income tax expense. As of December 31, 2011, we did not have any amount accrued for interest and penalties on uncertain tax positions.

Our U.S. Federal income tax returns for 2002 forward, our Louisiana income tax returns from 1998 forward, our New Zealand income tax returns after 2004, and our Texas franchise tax returns after 2006 remain subject to examination by the taxing authorities. There are no material unresolved items related to periods previously audited by these taxing authorities. No other state returns are significant to our financial position.

Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities. The “Accounts Payable and Accrued Liabilities” balances on the accompanying consolidated balance sheets are summarized below for presentation purposes. The following is a detailed breakout of certain items within “Accounts Payable and Accrued Liabilities” in the corresponding periods:

(in thousands)	December 31, 2011		December 31, 2010
Trade accounts payable (1)	$	42,080	$	22,459
New Zealand deferred revenue		—		10,000
Accrued operating expenses		15,833		11,044
Accrued payroll costs		14,345		14,298
Asset retirement obligation – current portion		9,279		8,708
Accrued taxes		7,604		7,198
Other payables		6,825		1,887
Total accounts payable and accrued liabilities	$	95,966	$	75,594

(1) Included in “trade accounts payable” are liabilities of approximately $18.7 million and $8.1 million at December 31, 2011 and December 31, 2010, respectively, for outstanding checks. This represents the amounts by which checks were issued, but not presented by vendors to the Company’s banks for collection, exceeded balances in the applicable disbursement bank accounts.

Cash and Cash Equivalents

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents.

Credit Risk Due to Certain Concentrations

Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners’ receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guaranties, if applicable, to reduce risk of loss. During 2011, 2010 and 2009, Shell Oil Company and affiliates accounted for 49%, 52% and 48% of our total oil and gas gross receipts, respectively. Flint Hills Resources accounted for approximately 14% of our total oil and gas gross receipts in 2011. No other purchasers accounted for more than 10% of our total oil and gas gross receipts for the past three years. Credit losses in each of the last three years were immaterial.

Restricted Cash

Restricted Cash. These balances primarily include amounts held in escrow accounts to satisfy domestic plugging and abandonment obligations. As of December 31, 2011 and 2010 these assets include approximately $1.3 million. These amounts are restricted as to their current use, and will be released when we have satisfied all plugging and abandonment obligations in certain fields. Restricted cash balances are reported in “Other long-term assets” on the accompanying consolidated balance sheets.

Accumulated Other Comprehensive Loss, Net of Income Tax

Accumulated Other Comprehensive Loss, Net of Income Tax. We follow the guidance contained in FASB ASC 220-10, which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At December 31, 2011, the Company had no gains or losses in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying consolidated balance sheet. The components of accumulated other comprehensive loss and related tax effects for 2011 were as follows (in thousands):

	Gross Value			Tax Effect			Net of Tax Value
Other comprehensive gain (loss) at December 31, 2010	($	218	)	$	80		($	138	)
Change in fair value of cash flow hedges		(520	)		190			(330	)
Effect of cash flow hedges settled during the period		738			(270	)		468
Other comprehensive gain (loss) at December 31, 2011	$	—		$	—		$	—

Total comprehensive income (loss) was $99.0 million, $46.4 million and ($39.6) million for 2011, 2010, and 2009, respectively.

Asset Retirement Obligation

Asset Retirement Obligation. We record these obligations in accordance with the guidance contained in FASB ASC 410-20. This guidance requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis over the estimated oil and natural gas reserves of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and equipment” balance on our accompanying consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.

The following provides a roll-forward of our asset retirement obligation (in thousands):

Asset Retirement Obligation as of December 31, 2008	$	48,785
Accretion expense		2,906
Liabilities incurred for new wells and facilities construction		3,400
Reductions due to sold and abandoned wells		(1,380	)
Revisions in estimates		10,525
Asset Retirement Obligation as of December 31, 2009	$	64,236
Accretion expense		3,956
Liabilities incurred for new wells and facilities construction		1,287
Reductions due to sold and abandoned wells		(749	)
Revisions in estimates		10,149
Asset Retirement Obligation as of December 31, 2010	$	78,879
Accretion expense		4,570
Liabilities incurred for new wells and facilities construction		590
Reductions due to sold and abandoned wells		(28,194	)
Revisions in estimates		20,548
Asset Retirement Obligation as of December 31, 2011	$	76,393

During 2011 we performed our annual revaluation of the asset retirement obligation, increasing the liability as a result of an increase in the expected abandonment costs for some of our wells and facilities and a decrease in the expected timing of abandonment activities for wells and facilities in certain fields. This revaluation increase is shown above as “Revisions in estimates.”

In 2011 we sold our interests in six fields in South Louisiana, two in Texas and one in Alabama which included the buyer’s assumption of approximately $27.7 million of asset retirement obligations related to these properties. This decrease is shown above in “Reductions due to sold and abandoned wells.”

At December 31, 2011 and 2010, approximately $9.3 million and $8.7 million, respectively, of our asset retirement obligation are classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

Public Stock Offerings

Public Stock Offerings. In November 2010, we issued 4.04 million shares of our common stock in an underwritten public offering at a price of $36.60 per share. The gross proceeds from these sales were approximately $147.8 million, before deducting underwriting commissions and issuance costs totaling $7.7 million.

In August 2009, we issued 6.21 million shares of our common stock in an underwritten public offering at a price of $18.50 per share. The gross proceeds from these sales were approximately $114.9 million, before deducting underwriting commissions and issuance costs totaling $6.1 million.

New Accounting Pronouncements

New Accounting Pronouncements. In June 2011, the FASB issued ASU No. 2011-05, which changes the required presentation of other comprehensive income. Under the new guidelines, entities will be required to present net income and other comprehensive income, along with the components of net income and other comprehensive income, in either one continuous statement of comprehensive income or in two separate but consecutive statements of net income and comprehensive income. The accounting standards update eliminates the option of presenting the components of other comprehensive income within the statement of changes in stockholders’ equity. We will adopt this guidance for the period ending March 31, 2012, although early adoption is permitted, and do not expect the guidance to have a material impact on our financial position or results of operations.

In May 2011, the FASB issued ASU No. 2011-04 to provide additional guidance related to fair value measurements and disclosures. The guidance, which is incorporated into FASB ASC 820-10, generally provides clarifications to existing fair value measurement and disclosure requirements and also creates or modifies other fair value measurement and disclosure requirements. We will adopt this guidance, as required, for the period ending March 31, 2012 and do not expect the guidance to have a material impact on our financial position or results of operations.

In January 2010, the FASB issued ASU 2010-03 to amend oil and gas reserve accounting and disclosure guidance that aligns the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries – Oil and Gas”) with the requirements of SEC Release No. 33-8995. This release is effective for financial statements issued on or after January 1, 2010. We have adopted this guidance for all reporting periods ending on or after December 31, 2009. This release changes the accounting and disclosure requirements surrounding oil and natural gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The most significant changes include:

• Changes to prices used in reserves calculations, for use in both disclosures and accounting impairment tests. Prices will no longer be based on a single-day, period-end price. Rather, they will be based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.

• Disclosure of probable and possible reserves is allowed.

• The estimation of reserves will allow the use of reliable technology that was not previously recognized by the SEC.

• Numerous changes in reserves disclosures mandated by SEC Form 10-K.

• Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

These new requirements did not have a material impact upon our reserves estimation or earnings in the current period. These changes could have a material impact upon our financial statements in future periods due to the uncertainty of oil and gas prices.

Share-based Compensation

Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted EPS for the year ended December 31, 2011 assumes, as of the beginning of the period, exercise of stock options using the treasury stock method. As we recognized a net loss for the year ended December 31, 2009, the unvested share-based payments and stock options were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. Certain of our stock options that would potentially dilute Basic EPS in the future were also antidilutive for the years ended December 31, 2011 and 2010, and are discussed below.

Fair value measurements

FASB ASC 820-10 defines fair value, establishes guidelines for measuring fair value and expands disclosure about fair value measurements. It does not create or modify any current GAAP requirements to apply fair value accounting. However, it provides a single definition for fair value that is to be applied consistently for all prior accounting pronouncements. The adoption of this guidance did not have a material impact on our financial position or results of operations.

Earnings Per Share

The Company computes earnings per share in accordance with FASB ASC 260-10. Under the guidance, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are participating securities and, therefore, are included in computing basic earnings per share (EPS) pursuant to the two-class method. The two-class method determines earnings per share for each class of common stock and participating securities according to dividends or dividend equivalents and their respective participation rights in undistributed earnings.