Summary of Significant Accounting Policies

Edison International has two business segments for financial reporting purposes: an electric utility segment (SCE) and a competitive power generation segment (EMG). SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000 square mile area of southern California. EMG is the holding company for its principal wholly owned subsidiary, EME. EME is a holding company with subsidiaries and affiliates engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also engages in hedging and energy trading activities in competitive power markets through its Edison Mission Marketing & Trading, Inc. ("EMMT") subsidiary.

Basis of Presentation

The consolidated financial statements included Edison International and its wholly owned subsidiaries. Edison International consolidates subsidiaries in which it has a controlling interest and Variable Interest Entities ("VIEs") in which it is the primary beneficiary. In addition, Edison International generally uses the equity method to account for significant interests in (1) partnerships and subsidiaries in which it owns a significant but less than controlling interest and (2) VIEs in which it is not the primary beneficiary. Intercompany transactions have been eliminated, except EMG's profits from energy sales to SCE which are allowed in utility rates.

Edison International's accounting policies conform to accounting principles generally accepted in the United States of America, including the accounting principles for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utility Commission ("CPUC") and the Federal Energy Regulatory Commission ("FERC"). SCE applies authoritative guidance for rate-regulated enterprises to the portion of its operations in which regulators set rates at levels intended to recover the estimated costs of providing service, plus a return on capital. Regulators may also impose certain penalties or grant certain incentives. Due to timing and other differences in the collection of electric utility revenue, these principles require an incurred cost that would otherwise be charged to expense by a nonregulated entity to be capitalized as a regulatory asset if it is probable that the cost is recoverable through future rates; and conversely the principles require recording of a regulatory liability for amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred. SCE assesses, at the end of each reporting period, whether regulatory assets are probable of future recovery. See Note 14 for composition of regulatory assets and liabilities.

The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reported period. Actual results could differ from those estimates.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $1.3 billion and $1.1 billion at December 31, 2011 and 2010, respectively. Generally, the carrying value of cash equivalents equals the fair value, as these investments have maturities of three months or less.

Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $220 million and $197 million of checks issued, but not yet paid by the financial institution, from cash to accounts payable at December 31, 2011 and 2010, respectively.

Restricted Cash and Cash Equivalents, and Restricted Deposits

Restricted deposits consisted of cash balances that are restricted to pay amounts required for lease payments, debt service or to provide collateral. Included in restricted deposits was $51 million and $47 million at December 31, 2011 and 2010, respectively, related to lease payments, debt service, collateral reserves, or other. The restricted cash and cash equivalents at December 31, 2011 included $97 million of cash proceeds received from a wind financing that was held in escrow at December 31, 2011 and is expected to be released in the first quarter of 2012 when the Pinnacle project achieves certain completion milestones.

Allowance for Uncollectible Accounts

SCE records an allowance for uncollectible accounts, based upon a variety of factors, including historical amounts written-off, current economic conditions and assessment of customer collectability.

Inventory

Inventory is stated at the lower of cost or market, cost being determined by the weighted-average cost method for fuel, and the average cost method for materials and supplies. Inventory consisted of the following:



	December 31,
(in millions)	2011		2010
Coal, gas, fuel oil and other raw materials	$	211	$	184
Spare parts, materials and supplies	413		384
Total inventory	$	624	$	568

Purchased Emission Allowances, Exemptions and Offsets

Purchased emission allowances are stated at the lower of weighted-average cost or market. Purchased emission allowances are recorded at cost when purchased and then expensed at weighted-average cost as used. Cost is reduced to market value if the market value of emission allowances has declined and it is probable that revenues earned from the generation of power will not cover the amounts recorded in the ordinary course of business. Purchased emission allowances are classified as current or long-term assets based on the time the allowances are expected to be used. The following table summarizes the amount of current and noncurrent purchased emission allowances, exemptions and offsets and the line item on the consolidated balance sheets.



	December 31,
(in millions)	2011		2010
Purchased emission allowances
Current (included in other current assets)	$	20	$	29
Noncurrent(included in other long-term assets)	92		31

Renewable Energy Credits

Renewable energy certificates or credits ("RECs") represent property rights established by governmental agencies for the environmental, social, and other nonpower qualities of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.

Retail sellers of electricity obtain RECs through renewable power purchase agreements, internal generation or separate purchases in the market to comply with renewable portfolio standards established in certain such governmental agencies. RECs are the mechanism used to verify renewable portfolio standards compliance and are recognized at the lower of weighted-average cost or market when amounts purchased are in excess of the amounts needed to comply with RPS requirements. The cost of RECs is recoverable as part of the cost of purchased power by SCE.

Property, Plant and Equipment

Utility Property, Plant and Equipment

Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor and indirect costs such as construction overhead, administrative and general costs, pension and benefits, and property taxes. The CPUC authorizes a rate for each of the indirect costs which are allocated to each project based on either labor or total costs. In addition, allowance for funds used during construction ("AFUDC") is capitalized for certain projects.

Estimated useful lives (authorized by the CPUC) and weighted-average useful lives of SCE's property, plant and equipment, are as follows:



	Estimated Useful Lives	Weighted-Average Useful Lives
Generation plant	25 years to 70 years	40 years
Distribution plant	30 years to 60 years	40 years
Transmission plant	35 years to 65 years	46 years
General and Other plant	5 years to 60 years	22 years

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense stated as a percent of average original cost of depreciable utility plant was, on a composite basis, 4.3%, 4.1% and 4.2% for 2011, 2010 and 2009, respectively. Replaced or retired property costs are charged to the accumulated provision for depreciation. Cash payments for removal costs less salvage reduce the liability for asset retirement obligations ("AROs").

Nuclear fuel is recorded as utility plant (nuclear fuel in the fabrication and installation phase is recorded as construction in progress) in accordance with CPUC ratemaking procedures. Nuclear fuel is amortized using the units of production method.

AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction and is capitalized during certain plant construction. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset. AFUDC equity represents a method to compensate SCE for the estimated cost of equity used to finance utility plant additions and is recorded as part of construction in progress. AFUDC equity was $96 million, $100 million and $116 million in 2011, 2010 and 2009, respectively. AFUDC debt was $42 million, $41 million and $32 million in 2011, 2010 and 2009, respectively.

The FERC issued an order granting return on equity ("ROE") incentive adders, recovery of the return on rate base including incentive adders during the construction phase (referred to as CWIP) and recovery of abandoned plant costs, if needed, for several of SCE's transmission projects. In addition, the FERC granted an ROE incentive to SCE for California Independent System Operator ("CAISO") participation. The order permits SCE to include 100% of prudently-incurred capital expenditures in rate base during construction of the projects and earn a return on equity, rather than capitalizing AFUDC.

Competitive Power Generation and Other Property

Property, plant and equipment, including leasehold improvements and construction in progress, are capitalized at cost and are principally comprised of EMG's majority-owned subsidiaries' plants and related facilities and, prior to January 1, 2010, the plant and related facilities of VIEs consolidated by SCE. Depreciation and amortization are computed using the straight-line method over the estimated useful life of the property, plant and equipment and over the shorter of the lease term or estimated useful life for leasehold improvements. Gains and losses from sale of assets are recognized at the time of the transaction.

As part of the acquisition of the Midwest Generation plants and Homer City plant, EMG acquired emission allowances under the United States Environmental Protection Agency's (US EPA's) Acid Rain Program. EMG uses these emission allowances in the normal course of its business to generate electricity and has classified them as part of property, plant and equipment. Acquired emission allowances will be amortized on a straight-line basis.

Estimated useful lives for property, plant and equipment are as follows:



Power plant facilities		3 to 35 years
Leasehold improvements		Shorter of life of lease or estimated useful life
Emission allowances		25 to 33.75 years
Equipment, furniture and fixtures		3 to 10 years

Interest incurred on funds borrowed by EMG is capitalized during the construction period. Such capitalized interest is included in property, plant and equipment. Capitalized interest is amortized over the depreciation period of the major plant and facilities for the respective project. Capitalized interest was $27 million, $54 million and $19 million in 2011, 2010 and 2009, respectively.

Major Maintenance

Certain of Edison International's power plant facilities and equipment require periodic major maintenance. These costs are expensed as incurred.

Asset Retirement Obligations

The fair value of a liability for an ARO is recorded in the period in which it is incurred, including a liability for the fair value of a conditional ARO, if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. When an ARO liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased for accretion expense each period and the capitalized cost is depreciated over the useful life of the related asset. Settlement of an ARO liability for an amount other than its recorded amount results in an increase or decrease in expense. AROs related to decommissioning of SCE's nuclear power facilities are based on site-specific studies. Those site-specific studies are updated as part of each Nuclear Decommissioning Cost Triennial Proceeding ("NDCTP"). The initial establishment of a nuclear-related ARO is at fair value. Subsequent layers of an ARO are established for updated site-specific decommissioning cost estimates as approved by the CPUC on the NDCTP. For further discussion, see "Nuclear Decommissioning" below and Notes 4 and 15. A reconciliation of the changes in the ARO liability is as follows:



(in millions)	2011			2010
Beginning balance	$	2,561		$	3,241
Accretion expense	68			198
Revisions¹	41			(867		)
Liabilities added	19			9
Liabilities settled	(1		)	(1		)
Transfers in or out²	—			(19		)
Ending balance	$	2,688		$	2,561


¹	Revisions in 2010 represent the most recent site-specific studies approved by the CPUC.


²	Transfers in or out consist of the deconsolidation of the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson) effective January 1, 2010. For further discussion, see Note 3.

In 2003, SCE recorded the fair value of its liability for AROs related to the decommissioning of its nuclear power facilities. At that time, SCE adjusted its nuclear decommissioning obligation, capitalized the initial costs of the ARO into a nuclear-related ARO regulatory asset and also recorded an ARO regulatory liability as a result of timing differences between the recognition of costs and the recovery of costs through the ratemaking process. Once a Commission decision is rendered, a revised ARO layer reflecting the updated cost estimate is established and accreted over the lives of San Onofre and Palo Verde. The ARO liability related to San Onofre and Palo Verde was $2.5 billion at both December 31, 2011 and 2010.

Impairment of Long-Lived Assets

Edison International evaluates the impairment of its investments in projects and other long-lived assets based on a review of estimated future cash flows expected to be generated whenever events or changes in circumstances indicate that the carrying amount of such investments or assets may not be recoverable. Edison International's unit of account is at the plant level and, accordingly, the closure of a unit at a multi-unit site would not result in an impairment of property, plant and equipment unless such condition were to affect an impairment assessment on the entire plant. If the carrying amount of a long-lived asset exceeds expected future cash flows, undiscounted and without interest charges, an impairment loss is recognized in the amount of the excess of fair value over the carrying amount. Fair value is determined via market, cost and income based valuation techniques, as appropriate. SCE's impaired assets are recorded as a regulatory asset if it is deemed probable that such amounts will be recovered from customers. For further discussion, see Note 16.

Project Development Costs

Edison International capitalizes project development costs incurred in the assessment, design and construction of generating projects once it is probable that the project will be completed. Edison International determines it is probable that the project will be completed based upon management's determination that the project is economically and operationally feasible and appropriate management and regulatory approvals have been obtained or are probable. Project development costs consist of professional fees, permits and other directly related development costs incurred by Edison International. The capitalized costs are recorded in other long-term assets on Edison International's consolidated balance sheets until the start of construction, at which time the costs are transferred to construction in progress, a component of property, plant and equipment. The capitalized costs are amortized over the life of the projects once operational or charged to expense if management determines the costs to be unrecoverable.

Leases

SCE and EMG enter into power purchase agreements that may contain leases, as discussed under "Power Purchase Agreements" below. EMG leases the Homer City, Powerton and a portion of the Joliet power plants under sales leaseback arrangements as described in Note 9. Both SCE and EMG have entered into a number of agreements to lease property and equipment in the normal course of business. Minimum lease payments under operating leases for property, plant and equipment are levelized (total minimum lease payments divided by the number of years of the lease) and recorded as rent expense over the terms of the leases. Lease payments in excess of the minimum are recorded as rent expense in the year incurred.

Capital leases are reported as long-term obligations on the consolidated balance sheets in "Other deferred credits and other long-term liabilities." As a rate-regulated enterprise, SCE's capital lease amortization expense and interest expense are reflected in "Purchased power" on the consolidated statements of income.

Nuclear Decommissioning

SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by the NRC. Decommissioning is expected to begin after expiration of the plants' operating licenses. The plants' operating licenses are currently set to expire in 2022 for San Onofre Units 2 and 3, unless license renewal proves feasible, and 2045, 2046 and 2047 for Palo Verde units 1, 2 and 3, respectively. Decommissioning costs, which are recovered through nonbypassable customer rates over the term of each nuclear facility's operating license, are recorded as a component of depreciation expense, with a corresponding credit to the ARO regulatory liability. Amortization of the ARO asset (included within the unamortized nuclear investment) and accretion of the ARO liability are deferred as increases to the ARO regulatory liability account, resulting in no impact on earnings.

SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts. The cost of removal amounts, in excess of fair value collected for assets not legally required to be removed, are classified as regulatory liabilities.

Due to regulatory recovery of SCE's nuclear decommissioning expense, nuclear decommissioning activities do not affect SCE's earnings. SCE's nuclear decommissioning trust investments primarily consist of debt and equity investments that are classified as available-for-sale. Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on electric utility revenue. Unrealized gains and losses on decommissioning trust funds increase or decrease the trust assets and the related regulatory asset or liability and have no impact on electric utility revenue or decommissioning expense. SCE reviews each security for other-than-temporary impairment on the last day of each month. If the fair value on the last day of two consecutive months is less than the cost for that security, SCE recognizes a loss for the other-than-temporary impairment. If the fair value is greater or less than the cost for that security at the time of sale, SCE recognizes a related realized gain or loss, respectively.

Deferred Financing Costs

Debt premium, discount and issuance expenses incurred in connection with obtaining financing are deferred and amortized on a straight-line basis for SCE and on a basis which approximates the effective interest rate method for EMG as interest expense over the term of the related debt. Under CPUC ratemaking procedures, debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt. SCE had unamortized losses on reacquired debt of $249 million and $268 million at December 31, 2011 and 2010, respectively, reflected in "Regulatory assets" in the long-term section of the consolidated balance sheets. Edison International had unamortized debt issuance costs of $134 million and $114 million at December 31, 2011 and 2010, respectively, reflected in "Other long-term assets" on the consolidated balance sheets. Amortization of deferred financing costs charged to interest expense was $49 million, $35 million and $31 million in 2011, 2010 and 2009, respectively.

Revenue Recognition

Electric Utility Revenue

Electric utility revenue is recognized when electricity is delivered and includes amounts for services rendered but unbilled at the end of each reporting period. Rates charged to customers are based on CPUC and FERC-authorized revenue requirements. CPUC rates are implemented upon final approval, and beginning in 2012 FERC rates are based on a forecasted revenue requirement, subject to refund and settlement procedures, and will be trued-up annually based on actual amounts.

CPUC rates decouple authorized revenue from the volume of electricity sales, so that SCE earns revenue equal to amounts authorized. Differences between amounts collected and authorized levels are either collected from or refunded to customers, and therefore, such differences do not impact operating revenue.

SCE remits to the California Department of Water Resources ("CDWR"), and does not recognize as revenue the amounts that SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, as well as CDWR-bond-related costs and a portion of direct access exit fees. Power purchased by the CDWR for these long-term contracts are not considered a cost to SCE because SCE is acting as a limited agent to CDWR for these transactions. The amounts collected and remitted to CDWR were $1.1 billion, $1.2 billion, and $1.8 billion for the years ended December 31, 2011, 2010 and 2009, respectively. All power contracts that CDWR allocated to SCE had expired by the end of 2011. The bond-related charges and direct access exit fees continue until 2022.

Competitive Power Generation Revenue

Generally, revenues and related costs are recognized when electricity is generated, or services are provided, unless the transaction is accounted for as a derivative and does not qualify for the normal purchases and sales exception. EMG's subsidiaries enter into power and fuel hedging, optimization transactions and energy trading contracts, all subject to market conditions. One of EMG's subsidiaries executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, EMG's subsidiaries generally act as the principal, take title to the commodities, and assume the risks and rewards of ownership. EMG's subsidiaries record the settlement of non-trading physical forward contracts on a gross basis. EMG nets the cost of purchased power against related third-party sales in markets that use locational marginal pricing, currently PJM. Financial swap and option transactions are settled net and, accordingly, EMG's subsidiaries do not take title to the underlying commodity. Therefore, gains and losses from settlement of financial swaps and options are recorded net in operating revenues in the accompanying consolidated statements of operations.

Revenues under certain long-term power sales contracts are recognized based on the output delivered at the lower of the amount billable or the average rate over the contract term. The excess of the amounts billed over the portion recorded as revenues is reflected in deferred revenues on the consolidated balance sheets.

EMG accounts for grant income on the deferred method and, accordingly, will recognize operating revenues related to such income over the estimated useful life of the projects. In 2011, EMG received a total of $388 million of U.S. Treasury grants (cash grants, under the American Recovery and Reinvestment Act of 2009).

Power Purchase Agreements

Both SCE, generally as the purchaser, and EMG, generally as the seller, enter into power purchase agreements in the normal course of business. A power purchase agreement may be considered a variable interest in a variable interest entity. Under this classification, the power purchase agreement is evaluated to determine if SCE or EMG is the primary beneficiary in the variable interest entity, in which case, such entity would be consolidated. None of SCE's or EMG's power purchase agreements resulted in consolidation of a variable interest entity at December 31, 2011. See Note 3 for further discussion of power purchase agreements that are considered variable interests.

A power purchase agreement may also contain a lease for accounting purposes. This generally occurs when a power purchase agreement (signed or modified after June 30, 2003) designates a specific power plant in which the buyer purchases substantially all of the output and does not otherwise meet a fixed price per unit of output exception. SCE and EMG have a number of power purchase agreements that contain leases. EMG's revenue from these power sales agreements were $109 million, $81 million and $83 million in 2011, 2010 and 2009, respectively. SCE's recognition of lease expense conforms to the ratemaking treatment for SCE's recovery of the cost of electricity and are recorded in purchased power. These agreements are classified as operating leases as electricity is delivered at rates defined in power sales agreements. See Note 9 for further discussion of SCE's power purchase agreements, including agreements that are classified as capital leases for accounting purposes.

A power purchase agreement that does not contain a lease may be classified as a derivative subject to a normal purchase and sale exception, in which case the power purchase agreement is classified as an executory contract and accounted for on an accrual basis. Most of SCE's QF contracts are not required to be recorded on the consolidated balance sheets because they either do not meet the definition of a derivative or meet the normal purchase and sale exception. However, SCE purchases power from certain QFs in which the contract pricing is based on a natural gas index, but the power is not generated with natural gas. These contracts are not eligible for the normal purchase and sale exception and are recorded as a derivative on the consolidated balance sheets at fair value. See Note 6 for further information on derivatives and hedging activities.

Power purchase agreements that do not meet the above classifications are accounted for on an accrual basis.

Derivative Instruments and Hedging Activities

Edison International records derivative instruments on its consolidated balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as normal purchases or sales. The normal purchases and sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Changes in the fair value of SCE's derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no impact on purchased-power expenses or earnings. SCE does not use hedge accounting for derivative transactions due to regulatory accounting treatment.

The accounting guidance for cash flow hedges provides that the effective portion of gains or losses on derivative instruments designated and qualifying as cash flow hedges be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gains or losses on the derivative instruments, if any, must be recognized currently in earnings.

Where Edison International's derivative instruments are subject to a master netting agreement and certain criteria are met, Edison International presents its derivative assets and liabilities on a net basis on its consolidated balance sheets. In addition, derivative positions are offset against margin and cash collateral deposits. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. See Note 6 for further information on derivative and hedging activities.

Sales and Use Taxes

SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE's ability to collect from the customer, are accounted for on a gross basis and reflected in electric utility revenue and other operation and maintenance expense. SCE's franchise fees billed to customers and recorded as electric utility revenue were $101 million, $102 million and $102 million for the years ended December 31, 2011, 2010 and 2009, respectively. When SCE acts as an agent and when the tax is not required to be remitted as not having been collected from the customer, the taxes are accounted for on a net basis. Amounts billed to and collected from customers for these taxes are remitted to the taxing authorities and are not recognized as electric utility revenue.

Stock-Based Compensation

Stock options, performance shares, deferred stock units and restricted stock units have been granted under Edison International's long-term incentive compensation programs. Generally, Edison International does not issue new common stock for settlement of equity awards. Rather, a third party is used to purchase shares from the market and delivery for settlement of option exercises, performance shares and restricted stock units. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Deferred stock units granted to management are settled in cash and represent a liability. Restricted stock units are settled in common stock; however, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

Edison International recognizes stock-based compensation expense on a straight-line basis over the requisite service period. Edison International recognizes stock-based compensation expense for awards granted to retirement-eligible participants on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement.

Dividend Restrictions

The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At December 31, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.4% resulting in the capacity to pay $436 million in additional dividends.

Earnings Per Share

Edison International computes earnings per share ("EPS") using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's participating securities are stock-based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. EPS attributable to Edison International common shareholders was computed as follows:



	Years ended December 31,
(in millions)	2011				2010				2009
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax	$	(34	)		$	1,252			$	856
Participating securities dividends	—				(5		)		(6		)
Income from continuing operations available to common shareholders	$	(34	)		$	1,247			$	850
Weighted average common shares outstanding	326				326				326
Basic earnings per share – continuing operations	$	(0.10	)		$	3.83			$	2.61
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	(34	)		$	1,247			$	850
Income impact of assumed conversions	—			¹	5				1
Income from continuing operations available to common shareholders and assumed conversions	$	(34	)		$	1,252			$	851
Weighted average common shares outstanding	326				326				326
Incremental shares from assumed conversions	—			¹	3			²	1			²
Adjusted weighted average shares – diluted	326				329				327
Diluted earnings per share – continuing operations	$	(0.10	)		$	3.81			$	2.60


¹	Due to a loss for the period, there are no incremental shares in the computation because such shares would be considered antidilutive.

Stock-based compensation awards to purchase 5,981,090, and 8,547,090 shares of common stock for the years ended December 31, 2010 and 2009, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares during the respective periods and, therefore, the effect would have been antidilutive.

Income Taxes

Edison International estimates its income taxes for each jurisdiction in which it operates. This involves estimating current period tax expense along with assessing temporary differences resulting from differing treatment of items (such as depreciation) for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within Edison International's consolidated balance sheets. Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Investment tax credits are deferred and amortized to income tax expense over the lives of the properties or the term of the power purchase agreement of the respective project while production tax credits are recognized in income tax expense in the period in which they are earned. EMG's investments in wind-powered electric generation projects qualify for federal production tax credits. Such credits are allowable for production during the 10-year period after a qualifying wind energy facility is placed into service. Certain of EMG's wind projects also qualify for state tax credits, which are accounted for similarly to federal production tax credits.

Interest income, interest expense and penalties associated with income taxes are reflected in "Income tax expense" on the consolidated statements of income.

Edison International's eligible subsidiaries are included in Edison International's consolidated federal income tax and combined state tax returns. Edison International has tax-allocation and payment agreements with certain of its subsidiaries. For subsidiaries other than SCE, the right of a participating subsidiary to receive or make a payment and the amount and timing of tax-allocation payments are dependent on the inclusion of the subsidiary in the consolidated income tax returns of Edison International and other factors including the consolidated taxable income of Edison International and its includible subsidiaries, the amount of taxable income or net operating losses and other tax items of the participating subsidiary, as well as the other subsidiaries of Edison International. There are specific procedures regarding allocations of state taxes. Each subsidiary is eligible to receive tax-allocation payments for its tax losses or credits only at such time as Edison International and its subsidiaries generate sufficient taxable income to be able to utilize the participating subsidiary's losses in the consolidated income tax return of Edison International. Pursuant to an income tax-allocation agreement approved by the CPUC, SCE's tax liability is computed as if it filed its federal and state income tax returns on a separate return basis.

Related Party Transactions

Four EMG subsidiaries have 49% to 50% ownership in partnerships that sell electricity generated by their project facilities to SCE under long-term power purchase agreements with terms and pricing approved by the CPUC. Sales by these partnerships to SCE under these agreements amounted to $277 million, $367 million and $366 million in 2011, 2010 and 2009, respectively.

An indirect wholly owned affiliate of EMG has entered into operation and maintenance agreements with partnerships in which EMG has a 50% or less ownership interest. EMG recorded power generation revenue under these agreements of $23 million, $23 million and $26 million in 2011, 2010 and 2009, respectively. EMG's accounts receivable with this affiliate totaled $3 million and $5 million at December 31, 2011 and 2010, respectively.

New Accounting Guidance

Accounting Guidance Adopted in 2011

Revenue-Multiple-Deliverables

In October 2009, the Financial Accounting Standards Board ("FASB") issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenues based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is required to be applied prospectively to new or significantly modified revenue arrangements. Edison International adopted this guidance effective January 1, 2011. The adoption of this accounting standards update did not have a material impact on Edison International's consolidated income statements, financial position or cash flows.

Fair Value Measurements and Disclosures

The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements. Under these requirements, purchases and settlements for Level 3 fair value measurements are presented on a gross basis, rather than net. Edison International adopted this guidance effective January 1, 2011.

Accounting Guidance Not Adopted in 2011

Fair Value Measurement

In May 2011, the FASB issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. Edison International will adopt this guidance in the first quarter of 2012. The adoption of this accounting standards update is not expected to have a material impact on Edison International's consolidated financial position.

Presentation of Comprehensive Income

In June 2011 and December 2011, the FASB issued an accounting standards update on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. Edison International will adopt this guidance in the first quarter of 2012. Edison International currently presents the statement of comprehensive income immediately following the statement of income and will continue to do so. The adoption of this accounting standards update will not change the items that constitute net income and other comprehensive income.

Offsetting Assets and Liabilities

In December 2011, the FASB issued an accounting standards update modifying the disclosure requirements about the nature of an entity's rights of offsetting assets and liabilities in the statement of financial position under master netting agreements and related arrangements associated with financial and derivative instruments. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and narrative descriptions of setoff rights. Edison International will adopt this guidance effective January 1, 2013. Edison International does not expect the adoption of this standard to have a material impact on Edison International's consolidated statements of income, financial position or cash flows.