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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-Q

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(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended June 30, 2009
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from            to

Commission File Number 1-9936

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EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)

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(626) 302-2222
(Registrant's telephone number, including area code)

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        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer" in Rule 12b-2 of the Exchange Act.

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

        Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

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EDISON INTERNATIONAL

INDEX

							Page No.
Part I. Financial Information
			Item 1.		Financial Statements:		1
					Consolidated Statements of Income (Loss) – Three and Six Months Ended June 30, 2009 and 2008		1
					Consolidated Statements of Comprehensive Income (Loss) – Three and Six Months Ended June 30, 2009 and 2008		2
					Consolidated Balance Sheets – June 30, 2009 and December 31, 2008		3
					Consolidated Statements of Cash Flows – Six Months Ended June 30, 2009 and 2008		5
					Notes to Consolidated Financial Statements		7
			Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations		49
			Item 3.		Quantitative and Qualitative Disclosures About Market Risk		112
			Item 4.		Controls and Procedures		113
Part II. Other Information
			Item 1.		Legal Proceedings		114
			Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		115
			Item 4.		Submission of Matters to a Vote of Security Holders		116
			Item 6.		Exhibits		118
			Signature				119

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GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

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GLOSSARY (Continued)

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GLOSSARY (Continued)

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EDISON INTERNATIONAL

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

		Three Months Ended June 30,						Six Months Ended June 30,
In millions, except per-share amounts		2009			2008			2009			2008
		(Unaudited)
Electric utility		$	2,272		$	2,849		$	4,460		$	5,230
Competitive power generation			557			612			1,168			1,330
Financial services and other			5			16			18			31
Total operating revenue			2,834			3,477			5,646			6,591
Fuel			328			554			715			1,090
Purchased power			583			1,026			1,124			1,721
Other operation and maintenance			1,074			1,113			2,043			2,076
Depreciation, decommissioning and amortization			347			334			688			645
Lease terminations and other			866			(56	)		888			(73	)
Total operating expenses			3,198			2,971			5,458			5,459
Operating income (loss)			(364	)		506			188			1,132
Interest and dividend income			17			22			27			36
Equity in income (loss) from partnerships and unconsolidated subsidiaries – net			6			9			(2	)		9
Other nonoperating income			30			23			58			49
Interest expense – net of amounts capitalized			(182	)		(165	)		(369	)		(336	)
Other nonoperating deductions			(17	)		(14	)		(25	)		(26	)
Income (loss) from continuing operations before income taxes			(510	)		381			(123	)		864
Income tax expense (benefit)			(524	)		83			(402	)		244
Income from continuing operations			14			298			279			620
Loss from discontinued operations – net of tax			(7	)		(1	)		(4	)		(6	)
Net income			7			297			275			614
Less: Net income attributable to noncontrolling interests			23			36			41			55
Net income (loss) attributable to Edison International		$	(16	)	$	261		$	234		$	559
Amounts attributable to Edison International common shareholders:
Income (loss) from continuing operations, net of tax		$	(9	)	$	262		$	238		$	565
Loss from discontinued operations, net of tax			(7	)		(1	)		(4	)		(6	)
Net income (loss) attributable to Edison International common shareholders		$	(16	)	$	261		$	234		$	559
Weighted-average shares of common stock outstanding			326			326			326			326
Basic earnings (loss) per common share attributable to Edison International common shareholders:
Continuing operations		$	(0.03	)	$	0.79		$	0.73		$	1.72
Discontinued operations			(0.02	)		—			(0.01	)		(0.02	)
Total		$	(0.05	)	$	0.79		$	0.72		$	1.70
Weighted-average shares, including effect of dilutive securities			327			329			327			330
Diluted earnings (loss) per common share attributable to Edison International common shareholders:
Continuing operations		$	(0.03	)	$	0.79		$	0.73		$	1.71
Discontinued operations			(0.02	)		—			(0.01	)		(0.02	)
Total		$	(0.05	)	$	0.79		$	0.72		$	1.69
Dividends declared per common share		$	0.31		$	0.305		$	0.62		$	0.61

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

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EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

				Three Months Ended June 30,						Six Months Ended June 30,
In millions				2009			2008			2009			2008
				(Unaudited)
Net income				$	7		$	297		$	275		$	614
Other comprehensive income (loss), net of tax:
	Foreign currency translation adjustments – net				4			—			4			(3	)
Pension and postretirement benefits other than pensions:
		Net gain arising during the period-net			1			—			1			—
Amortization of net loss included in net income – net					1			—			3			—
	Unrealized gain (loss) on cash flow hedges:
		Unrealized gain (loss) arising during the period – net of income tax expense (benefit) of $(50) and $(212) for the three months and $48 and $(304) for the six months ended June 30, 2009 and 2008, respectively			(90	)		(316	)		61			(454	)
		Reclassification adjustment for gain (loss) included in net income – net of income tax expense (benefit) of $9 and $95 for the three months and $(23) and $89 for the six months ended June 30, 2009 and 2008, respectively			17			143			(32	)		134
Other comprehensive income (loss)					(67	)		(173	)		37			(323	)
Comprehensive income (loss)					(60	)		124			312			291
Less: Comprehensive income attributable to noncontrolling interests					23			36			41			55
Comprehensive income (loss) attributable to Edison International				$	(83	)	$	88		$	271		$	236

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

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EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS

In millions			June 30, 2009			December 31, 2008
			(Unaudited)
ASSETS
Cash and equivalents			$	2,701		$	3,916
Short-term investments				5			7
Receivables, less allowances of $41 and $39 for uncollectible accounts at respective dates				946			1,006
Accrued unbilled revenue				505			328
Inventory				545			553
Derivative assets				377			327
Restricted cash				188			3
Margin and collateral deposits				133			105
Regulatory assets				334			605
Deferred income taxes – net				—			104
Other current assets				189			399
Total current assets				5,923			7,353
Nonutility property – less accumulated depreciation of $2,161 and $2,019 at respective dates				5,352			5,374
Nuclear decommissioning trusts				2,673			2,524
Investments in partnerships and unconsolidated subsidiaries				207			229
Investments in leveraged leases				166			2,467
Other investments				99			89
Total investments and other assets				8,497			10,683
Utility plant, at original cost:
	Transmission and distribution			20,863			20,006
	Generation			1,900			1,819
Accumulated depreciation				(5,573	)		(5,570	)
Construction work in progress				2,308			2,454
Nuclear fuel, at amortized cost				273			260
Total utility plant				19,771			18,969
Derivative assets				632			244
Restricted cash				48			43
Rent payments in excess of levelized rent expense under plant operating leases				990			878
Regulatory assets				4,852			5,414
Other long-term assets				1,168			1,031
Total long-term assets				7,690			7,610
Total assets			$	41,881		$	44,615

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

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EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS

In millions, except share amounts		June 30, 2009			December 31, 2008
		(Unaudited)
LIABILITIES AND EQUITY
Short-term debt		$	77		$	2,143
Long-term debt due within one year			382			174
Accounts payable			833			1,031
Accrued taxes			212			590
Accrued interest			219			187
Customer deposits			239			228
Book overdrafts			177			224
Derivative liabilities			140			178
Regulatory liabilities			948			1,111
Deferred income taxes – net			132			—
Other current liabilities			721			831
Total current liabilities			4,080			6,697
Long-term debt			11,276			10,950
Deferred income taxes – net			4,269			5,717
Deferred investment tax credits			198			109
Customer advances			126			137
Derivative liabilities			556			776
Pensions and benefits			2,952			2,860
Asset retirement obligations			3,131			3,042
Regulatory liabilities			2,635			2,481
Other deferred credits and other long-term liabilities			1,886			1,137
Total deferred credits and other liabilities			15,753			16,259
Total liabilities			31,109			33,906
Commitments and contingencies (Note 6)
Common stock, no par value (325,811,206 shares outstanding at each date)			2,285			2,272
Accumulated other comprehensive income			204			167
Retained earnings			7,101			7,078
Total Edison International's common shareholders' equity			9,590			9,517
Noncontrolling interests – other			275			285
Preferred and preference stock of utility not subject to mandatory redemption			907			907
Total equity			10,772			10,709
Total liabilities and equity		$	41,881		$	44,615

Authorized common stock is 800 million shares at each reporting period

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

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EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Six Months Ended June 30,
In millions		2009			2008
		(Unaudited)
Cash flows from investing activities:
Capital expenditures		$	(1,540	)	$	(1,460	)
Purchase of interest in acquired companies			(7	)		(7	)
Proceeds from termination of leases			1,420			—
Proceeds from sale of property and interests in projects			—			112
Proceeds from nuclear decommissioning trust sales			1,310			1,501
Purchases of nuclear decommissioning trust investments and other			(1,415	)		(1,560	)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment			12			30
Maturities and sales of short-term investments			3			70
Purchase of short-term investments			(1	)		(2	)
Customer advances for construction and other investments			(60	)		(232	)
Net cash used by investing activities			(278	)		(1,548	)
Net decrease in cash and equivalents			(1,215	)		(371	)
Cash and equivalents, beginning of period			3,916			1,441
Cash and equivalents, end of period		$	2,701		$	1,070

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

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EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management's Statement

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 2009 are not necessarily indicative of the operating results for the full year.

This quarterly report should be read in conjunction with Edison International's Annual Report to Shareholders incorporated by reference into Edison International's Annual Report on Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission.

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

Edison International's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements" included in its 2008 Annual Report on Form 10-K. Edison International follows the same accounting policies for interim reporting purposes.

The December 31, 2008 condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Certain prior-year reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of SFAS No. 160 and the elimination of the previously reported income statement caption "Provision for regulatory adjustment clauses – net" through classifications within relevant captions including "Operating revenue," "Purchased power," "Other operation and maintenance" and "Depreciation, decommissioning and amortization." Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.

Edison International has performed an evaluation of subsequent events through August 7, 2009, the date the financial statements were issued.

Cash and Equivalents

Cash and cash equivalents as of June 30, 2009 and December 31, 2008 consisted of the following:

In millions		June 30, 2009			December 31, 2008
		(Unaudited)
Cash		$	234		$	178
Money market funds		$	2,456		$	3,543
U.S. government agency securities			—			164
Commercial paper			—			30
Time deposits (certificates of deposit)			11			1
Total cash equivalents		$	2,467		$	3,738
Total cash and cash equivalents		$	2,701		$	3,916

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Cash equivalents, with the exception of money market funds, were stated at amortized cost plus accrued interest. The carrying value of cash equivalents equals the fair value as all investments have maturities of less than three months. For further discussion of money market funds, see Note 10. Additionally, cash and equivalents of $81 million and $89 million at June 30, 2009 and December 31, 2008, respectively, are included for four projects that Edison International is consolidating under an accounting interpretation for VIEs.

Earnings (Loss) Per Common Share

Edison International computes 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. Stock options awarded prior to 2002 and after 2006 were granted without a dividend equivalent feature. As a result of meeting a performance trigger, the options granted in 1998 and 1999 began earning dividend equivalents in 2006. EPS attributable to Edison International common shareholders was computed as follows:

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2009			2008			2009			2008
		(Unaudited)
Basic earnings (loss) per share – continuing operations:
Income (loss) from continuing operations, net of tax		$	(9	)	$	262		$	238		$	565
Gain on redemption of preferred stock			—			—			—			2
Participating securities dividends			—			(3	)		—			(6	)
Income (loss) from continuing operations available to common shareholders		$	(9	)	$	259		$	238		$	561
Weighted average common shares outstanding			326			326			326			326
Basic earnings (loss) per share – continuing operations		$	(0.03	)	$	0.79		$	0.73		$	1.72
Diluted earnings (loss) per share – continuing operations:
Income (loss) from continuing operations available to common shareholders		$	(9	)	$	259		$	238		$	561
Income impact of assumed conversions			—			1			—			3
Income (loss) from continuing operations available to common shareholders and assumed conversions		$	(9	)	$	260		$	238		$	564
Weighted average common shares outstanding			326			326			326			326
Incremental shares from assumed conversions			1			3			1			4
Adjusted weighted average shares – diluted			327			329			327			330
Diluted earnings (loss) per share – continuing operations		$	(0.03	)	$	0.79		$	0.73		$	1.71

Stock-based compensation awards to purchase 8,641,695 and 108,901 shares of common stock for the three months ended June 30, 2009 and 2008, respectively, and 8,641,695 and 108,901 shares of common

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stock for the six months ended June 30, 2009 and 2008, 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; and therefore, the effect would have been antidilutive.

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 at June 30, 2009 and December 31, 2008 consisted of the following:

In millions		June 30, 2009			December 31, 2008
		(Unaudited)
Coal, gas, fuel oil and raw materials		$	187		$	163
Spare parts, materials and supplies			358			390
Total		$	545		$	553

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers and cash received from counterparties and brokers (reflected in "Other current liabilities" on the consolidated balance sheets) as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the value of the positions. In accordance with FIN No. 39-1, "Amendment of FASB Interpretation No. 39," Edison International presents a portion of its margin and cash collateral deposits net with its derivative positions on its consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against derivative liabilities totaled $113 million and $123 million at June 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral received from others that have been offset against derivative assets totaled $275 million and $225 million at June 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral provided to others that have not been offset against derivative liabilities totaled $133 million and $105 million at June 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral received from others that have not been offset against derivative assets totaled $7 million and $8 million at June 30, 2009 and December 31, 2008 respectively.

New Accounting Pronouncements

Accounting Pronouncements Adopted

In May 2009, the FASB issued SFAS No. 165, "Subsequent Events." SFAS No. 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize these events or transactions; and the disclosures that an entity should make. Edison International adopted SFAS No. 165, effective April 1, 2009. The adoption of this standard had no impact on Edison International's consolidated results of operations, financial position or cash flows.

In April 2009, the FASB issued FSP SFAS No. 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that Are Not Orderly." FSP SFAS No. 157-4 affirms the objective of a fair value measurement, which is to identify the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction at the measurement date between market participants ("exit price") under current market conditions. FSP SFAS No. 157-4 includes guidance on identifying circumstances that indicate when

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there is no active market or transactions where the price inputs being used represent distressed or forced sales. If either of these conditions exists, FSP SFAS No. 157-4 provides additional direction for estimating fair value and requires disclosure of a change in valuation technique (and the related inputs) resulting from the application of this position and to quantify its effects, if practicable. This position also requires disclosures on a more disaggregated basis for investments in debt and equity securities measured at fair value. Edison International adopted FSP SFAS No. 157-4, effective April 1, 2009. The adoption of this position did not have an impact on Edison International's consolidated results of operations, financial position or cash flows. See Note 10.

In April 2009, the FASB issued FSP SFAS No. 115-2 and SFAS 124-2, "Recognition and Presentation of Other-Than-Temporary Impairments." This position amends existing guidance for determining whether impairment is other than temporary for debt securities. Under this position, an entity writes down to fair value through earnings, impaired debt securities that it currently intends to sell or for which it is more likely than not it will be required to sell before the anticipated recovery. If an entity does not intend and will not be required to sell a debt security but it is probable that the entity will not collect all amounts due, the entity will separate the other-than-temporary impairment into two components: 1) the amount due to credit loss would be recognized in earnings, and 2) the remaining portion would be recognized in other comprehensive income. Edison International adopted this position, effective April 1, 2009, resulting in increased disclosures. The adoption of this position did not have an impact on Edison International's consolidated results of operations, financial position or cash flows. See Note 10.

In April 2009, the FASB issued FSP SFAS No. 107-1 and APB No. 28-1, "Interim Disclosures about Fair Value of Financial Instruments." This position requires disclosures about the fair value of all financial instruments, for which it is practicable to estimate that fair value, for interim reporting periods as well as annual statements. Edison International adopted this position, effective April 1, 2009. Since FSP SFAS No. 107-1 and APB No. 28-1 impacts disclosure only, the adoption of this position did not have an impact on Edison International's consolidated results of operations, financial position or cash flows. See Note 10.

Effective January 1, 2009, Edison International adopted SFAS No. 157 for nonrecurring fair value measurements of nonfinancial assets and liabilities. The adoption of SFAS No. 157 for nonrecurring fair value measurements did not have a material impact on Edison International's consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning on or after January 1, 2009. Adoption of this pronouncement had no impact on consolidated results of operations, financial position or cash flows because there were no business combinations during the first six months of 2009.

In April 2009, the FASB issued FSP SFAS No. 141(R)-1, "Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies" to amend guidance in SFAS No. 141(R). FSP SFAS No. 141(R)-1 addresses the initial recognition, measurement and subsequent accounting for assets and liabilities arising from contingencies in a business combination, and requires that such assets acquired or liabilities assumed be initially recognized at fair value at the acquisition date if fair value can be determined during the measurement period. If the acquisition-date

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fair value cannot be determined, the asset acquired or liability assumed arising from a contingency is recognized only if certain criteria are met. This position also requires that a systematic and rational basis for subsequently measuring and accounting for the assets or liabilities be developed depending on their nature. This position was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after fiscal years beginning January 1, 2009. Adoption of this standard had no impact on Edison International's consolidated results of operations, financial position or cash flows because there were no business combinations during the first six months of 2009.

In December 2007, the FASB issued SFAS No. 160, which requires an entity to present noncontrolling interests that reflect the ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the entity's equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interests to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interests to be accounted for similarly as equity transactions; and when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary to be measured at fair value. Edison International adopted this pronouncement effective January 1, 2009 and retrospectively applied this standard as of December 31, 2008. In accordance with this standard, Edison International reclassified "Noncontrolling interests – other" of $285 million and "Preferred and preference stock of utility not subject to mandatory redemption" of $907 million to a component of equity. For additional information, see Note 7.

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. Edison International adopted this pronouncement effective January 1, 2009. Since SFAS No. 161 impacts disclosures only, the adoption of this standard did not have an impact on Edison International's consolidated results of operations, financial position or cash flows. For additional information regarding the adoption, see Note 2.

In April 2008, the FASB issued FSP FAS No. 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, "Goodwill and Other Intangible Assets." The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other GAAP. Edison International adopted this pronouncement effective, January 1, 2009. The adoption of this position had no impact on Edison International's consolidated results of operations, financial position or cash flows.

In November 2008, the FASB ratified the consensus in EITF Issue No. 08-6, "Equity Method Investment Accounting Considerations." This issue clarifies the accounting for certain transactions and impairment considerations involving equity method investments. Effective January 1, 2009, Edison International adopted this issue prospectively. The adoption had no impact on its consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In December 2008, the FASB issued FSP FAS 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets." This position requires additional plan asset disclosures about the major categories of assets, the inputs and valuation techniques used to measure fair value, the level within the fair value

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hierarchy, the effect of using significant unobservable inputs (Level 3) and significant concentrations of risk. This position is effective for years ending after December 15, 2009 and, therefore, Edison International will adopt FSP FAS 132(R)-1 at year-end 2009. FSP FAS 132(R)-1 will impact disclosures only and will not have an impact on Edison International's consolidated results of operations, financial position or cash flows.

In June 2009, the FASB issued SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)." SFAS No. 167 changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance. Edison International will adopt SFAS No. 167 on January 1, 2010 and is currently evaluating the impact, if any, that the adoption of this standard will have on its consolidated financial statements.

In June 2009, the FASB issued SFAS No. 168, "The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles." This Statement establishes the Codification to become the source of authoritative, nongovernmental U.S. GAAP superseding existing FASB, American Institute of Certified Public Accountants (AICPA), Emerging Issues Task Force (EITF) and related literature. Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions or EITF Abstracts. Instead, the FASB will issue Accounting Standards Updates. Two levels of U.S. GAAP will exist: authoritative and non-authoritative. Codification is not intended to change U.S. GAAP or guidance issued by the SEC. However, Codification will affect the way Edison International researches accounting issues and references U.S. GAAP in its notes to consolidated financial statements and MD&A. Edison International will adopt this Statement in the third quarter of 2009.

Restricted Cash

Cash balances that are restricted to pay amounts required for EMG lease payments, margining, or to provide collateral are classified as restricted cash. Cash balances that are restricted under margining agreements are classified as short-term as such amounts change frequently based on forward market prices.

Related Party Transactions

During the first quarter of 2008, a subsidiary of EME was awarded, through a competitive bidding process, a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. Deliveries under the power sales agreement are expected to commence in 2013. The project is subject to resolution of uncertainty regarding the availability of required emission credits.

Note 2. Derivative Instruments and Hedging Activities

Electric Utility

Commodity Price Risk

SCE is exposed to commodity price risk from its purchases of capacity and ancillary services to meet peak energy requirements and from exposure to natural gas prices that affect costs associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including SCE's Mountainview and peaker plants. Contract energy prices for most nonrenewable QFs are based in large part on the monthly index price of natural gas delivered at the Southern California border. SCE also has power contracts, referred to as tolling arrangements, in which SCE has agreed to provide

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the natural gas needed for generation under those power contracts or pay for the natural gas based on published index prices. In addition to SCE's Mountainview and peaker plants, approximately 44% of SCE's purchased power supply is subject to natural gas price volatility. Fair value changes in SCE's derivative instruments are expected to be recovered from or refunded to ratepayers and therefore, fair value changes have no impact on earnings, but may temporarily affect cash flows.

Natural Gas and Electricity Price Risk

SCE has an active hedging program in place to minimize ratepayer exposure to variability in market prices; however, to the extent that SCE does not mitigate the exposure to commodity price risk, the unhedged portion is subject to the risks and benefits of spot-market price movements, which are ultimately passed-through to ratepayers.

To mitigate SCE's exposure to variability in market prices, SCE enters into energy options, tolling arrangements, forward physical contracts and transmission congestion revenue rights (CRRs). SCE also enters into contracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure to increases in natural gas and electricity pricing. These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans.

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale. The derivative instrument fair values are marked to market at the end of each reporting period. Any fair value changes 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 expense or earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment.

Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging activities at June 30, 2009:

(1)

In September 2007 and November 2008, the CAISO allocated CRRs for the period April 2009 through December 2017 based on SCE's load requirements. In addition, SCE participated in CAISO auctions for the procurement of additional CRRs. The CRRs meet the definition of a derivative under SFAS No. 133.

(2)

In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new Southern California generating resources. SCE has entered into a number of contracts, of which five received regulatory approval in the fourth quarter of 2008 and are recorded as derivative instruments. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives.

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Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at June 30, 2009:

			Derivative Assets									Derivative Liabilities
In millions			Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Liability
			(Unaudited)
Non-trading activities
	Economic hedges		$	155		$	467		$	622		$	201		$	524		$	725		$	103
Netting and collateral				(1	)		—			(1	)		(68	)		—			(68	)		(67	)
Total			$	154		$	467		$	621		$	133		$	524		$	657		$	36

Income Statement Impact of Derivative Instruments

SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and recovers these costs from ratepayers. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased-power expense until realized. As a result, realized and unrealized gains and losses do not affect earnings, but may temporarily affect cash flows. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows. Realized losses on economic hedging activities were $96 million and $194 million for the three- and six-month periods ended June 30, 2009, respectively, compared to realized gains on economic hedging activities of $28 million and $26 million for the comparable periods in 2008, respectively. Unrealized gains on economic hedging activities were $293 million and $626 million for the three- and six-month periods ended June 30, 2009, respectively, compared to $333 million and $486 million for the comparable periods in 2008, respectively.

Contingent Features/Credit Related Exposure

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. These requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments, and other factors.

Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a "credit-risk-related contingent feature." If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features as of June 30, 2009, was $82 million, for which SCE has posted collateral of less than $1 million to its counterparties. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2009, SCE would be required to post an additional $32 million of collateral.

Competitive Power Generation

EME uses derivative instruments to reduce EME's exposure to market risks that arise from fluctuations in electricity, capacity and fuel prices, emission allowances and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. To the extent that EME does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks

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and benefits of spot market price movements. Hedge transactions are primarily entered into using derivative instruments including:

•

futures contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange or executed bilaterally with counterparties,

•

forward sales transactions entered into on a bilateral basis with third parties, including electric utilities, power marketing companies and financial institutions,

•

full requirements services contracts or load requirements services contracts for the procurement of power for electric utilities' customers, with such services providing for the delivery of a bundled product including, but not limited to, energy, transmission, capacity, and ancillary services, generally for a fixed unit price,

•

capacity transactions, and

•

interest rate swaps entered into on a bilateral basis with counterparties.

The extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine if forward market prices are sufficiently attractive compared to the risks associated with the fluctuating spot market. Second, EME evaluates the sufficiency of its credit capacity at EME and Midwest Generation and whether the forward sales markets have sufficient liquidity to enable EME to identify appropriate counterparties for hedge transactions. Hedge transactions entered into by EME are accounted for under SFAS No. 133.

SFAS No. 133, as amended and interpreted by accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires a company to record derivatives on its balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as a normal sale and purchase. Under SFAS No. 133, all changes in the fair value of derivative instruments are recognized currently in earnings, unless specific hedge criteria are met, which requires that EME formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

SFAS No. 133 sets forth the accounting requirements for cash flow hedges. SFAS No. 133 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.

Many of the derivative instruments entered into for risk management purposes (also referred to as non-trading purposes) meet the requirements for hedge accounting under SFAS No. 133. However, not all derivative instruments entered into for risk management purposes will qualify for hedge accounting treatment. Furthermore, EME utilizes derivative contracts that are designed to adjust financial and/or physical positions that reduce costs or increase gross margin. Accordingly, risk management positions may not be designated as cash flow hedges and are thus marked to market through current period earnings (derivatives that are entered into for risk management, but which are not designated as cash flow hedges, are referred to as economic hedges).

SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on the

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settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from commodity contracts in competitive power generation revenues or fuel expenses based on the item being hedged. In addition, the results of derivative activities are recorded in cash flows from operating activities in the consolidated statements of cash flows.

Derivative instruments that are utilized for trading purposes are measured at fair value and included in the balance sheet as derivative assets or liabilities. In the absence of quoted market prices, derivative instruments are valued at fair value as determined through the methodology outlined in Note 10—Fair Value Measurements. Resulting gains and losses are recognized in competitive power generation revenues in the accompanying consolidated income statements in the period of change in accordance with EITF No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities."

Where EME's derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation (FIN) No. 39 "Offsetting of Amounts Related to Certain Contracts" are met, EME presents its derivative assets and liabilities on a net basis in its balance sheet.

Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging and trading activities at June 30, 2009:

								Hedging Activities
Commodity		Instrument		Classification		Unit of Measure		Cash Flow Hedges			Economic Hedges			Trading Activities
								(Unaudited)
Electricity		Forwards		Sales		GWh			16,809	(1)		20,215	(3)		21,651
Electricity		Forwards		Purchases		GWh			—			19,088	(3)		23,238
Electricity		Capacity		Sales		MW-Day (in thousands)			386	(2)		—			91	(2)
Electricity		Capacity		Purchases		MW-Day (in thousands)			25	(2)		5	(2)		554	(2)
Electricity		Congestion		Sales		GWh			—			136	(4)		7,570	(4)
Electricity		Congestion		Purchases		GWh			—			3,328	(4)		171,875	(4)
Natural gas		Forwards		Sales		billion cubic feet			—			9.8			42.0
Natural gas		Forwards		Purchases		billion cubic feet			—			—			44.8
Fuel oil		Forwards		Sales		Barrels			—			—			90,000
Fuel oil		Forwards		Purchases		Barrels			—			600,000			140,000

(1)

EME's hedge products include forward and futures contracts that qualify for hedge accounting under SFAS No. 133. This category excludes power contracts for the Illinois Plants which meet the normal sales and purchase exception under SFAS No. 133 and are accounted for on the accrual method.

(2)

EME's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM RPM auction is not accounted for as a derivative under SFAS No. 133.

(3)

EME also entered into transactions that adjust financial and physical positions, or day-ahead and real-time positions to reduce costs or increase gross margin. These positions largely offset each other. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow hedges under SFAS No. 133.

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(4)

Congestion contracts are financial transmission rights, transmission congestion contracts or congestion revenue rights. These positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly day-ahead price differences between two locations.

In addition, Viento Funding II, Inc., an EME subsidiary, in conjunction with the closing of its wind portfolio financing, entered into seven-year amortizing interest rate swaps accounted for as cash flow hedges with a total notional amount of approximately $170 million at June 30, 2009. The interest rate swaps entitle Viento Funding II to receive a floating (six-month LIBOR) rate and pay a fixed rate of 3.175%. The interest rate swap agreements expire in June 2016.

Fair Value of Derivative Instruments

The following table summarizes the gross fair value of derivative instruments at June 30, 2009:

			Derivative Assets									Derivative Liabilities
In millions			Short- term			Long- term			Subtotal			Short- term			Long- term			Subtotal			Net Assets
			(Unaudited)
Non-trading activities
	Cash flow hedges		$	346		$	125		$	471		$	15		$	17		$	32		$	439
	Economic hedges			245			80			325			232			63			295			30
Trading activities				485			178			663			432			103			535			128
			$	1,076		$	383		$	1,459		$	679		$	183		$	862		$	597
Netting and collateral received				(853	)		(218	)		(1,071	)		(672	)		(170	)		(842	)		(229	)
Total			$	223		$	165		$	388		$	7		$	13		$	20		$	368

Income Statement Impact of Derivative Instruments

The following table provides the activity of accumulated other comprehensive income for the six months ended June 30, 2009, containing the information about the changes in the fair value of cash flow hedges and reclassification from accumulated other comprehensive income into results of operations:

In millions		Cash Flow Hedge Activity(1)			Income Statement Location
		(Unaudited)
Accumulated other comprehensive income derivative gain at December 31, 2008		$	398
Effective portion of changes in fair value			109
Reclassification from accumulated other comprehensive income to net income			(55	)	Competitive power generation revenues(2)
Accumulated other comprehensive income derivative gain at June 30, 2009		$	452

(1)

Unrealized derivative gains are before income taxes. The after-tax amounts recorded in accumulated other comprehensive income at June 30, 2009 and December 31, 2008 were $269 million and $240 million, respectively.

(2)

Represents reclassification of unrealized gains to competitive power generation revenues.

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Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net gains (losses) of $5 million and $(18) million during the second quarters of 2009 and 2008, respectively, and $5 million and $(31) million during the six months ended June 30, 2009 and 2008, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues in the income statement.

The effect of realized and unrealized gains from derivative instruments used for economic hedging and trading purposes on the consolidated statement of income for the periods ended June 30, 2009 is presented below:

In millions
Type		Income Statement Location		Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
				(Unaudited)
Economic hedges		Competitive power generation revenue		$	3		$	16
		Fuel expense		$	14		$	14
Trading activities		Competitive power generation revenue		$	17		$	27

Contingent Features/Credit Related Exposure

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses and unrealized gains in connection with derivative activities. Certain derivative contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT also has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position on June 30, 2009 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.

Financial Services and Other

A subsidiary of Edison Capital has a foreign currency swap to hedge foreign currency and interest rate risks of debt obligations with a notional amount of 56 million British pounds. The fair value of the foreign currency swap at June 30, 2009 is $18 million and is classified as a long-term derivative liability on the consolidated balance sheet. The effective portion of the change in the fair value of this derivative and related debt recorded in accumulated other comprehensive income for the six months ended June 30, 2009 was less than $1 million and the amount reclassified from accumulated other comprehensive income into income was $4 million.

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Note 3. Liabilities and Lines of Credit

Long-Term Debt

In March 2009, SCE issued $500 million of 6.05% and $250 million of 4.15% first and refunding mortgage bonds due in 2039 and 2014, respectively. The bond proceeds were used for general corporate purposes and to finance fuel inventories.

In February 2009, SCE repaid $150 million of its first and refunding mortgage bonds. In March 2009, SCE purchased two issues of its tax-exempt pollution control bonds totaling $219 million and converted the issues to a variable rate structure. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse portfolio financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The portfolio financing included a $189 million seven-year term loan and a $13 million letter of credit facility which replaced project letters of credit previously issued under the EME corporate credit facility.

Short-Term Debt

At June 30, 2009, Edison International (parent) had $77 million of short-term debt outstanding under its $1.4 billion credit facility at a weighted average interest rate of 0.68%.

Credit Agreements

On March 17, 2009, SCE entered into a new $500 million 364-day revolving credit facility, terminating on March 16, 2010. The additional liquidity provided by the facility will be used to support SCE's ongoing power procurement-related needs.

In June 2009, SCE amended its $2.5 billion five-year credit facility, reducing the commitment to $2.4 billion, and Edison International amended its $1.5 billion revolving credit facility, reducing the commitment to $1.4 billion. Both amendments were made to remove a subsidiary of Lehman Brothers Holding as a lender.

The following table summarizes the status of the credit facilities at June 30, 2009:

In millions		SCE			EMG			Edison International (parent)			Total
		(Unaudited)
Commitment		$	2,894		$	1,100		$	1,426		$	5,420
Less: Unfunded commitment from Lehman Brothers subsidiary			—			(36	)		—			(36	)
		$	2,894		$	1,064		$	1,426		$	5,384
Outstanding borrowings			—			(826	)		(77	)		(903	)
Outstanding letters of credit			(88	)		(128	)		—			(216	)
Amount available		$	2,806		$	110		$	1,349		$	4,265

Note 4. Income Taxes

Edison International's composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International's

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effective tax rate was 98% and 244% for the three- and six-month periods ended June 30, 2009, respectively, as compared to 24% and 30% for the respective periods in 2008. The 2009 effective tax rates were higher when compared to both the 2008 effective rate and the 2009 statutory rate due to the benefit recorded as a result of the Global Settlement discussed below.

The American Recovery and Reinvestment Act of 2009 ("ARRA") included a number of provisions that provide tax incentives to stimulate the economy, including incentives for energy-related investments and activities. ARRA extended for 1 year the 50% bonus depreciation provision to eligible property placed in service prior to January 1, 2010, provided for an option to claim cash grants in lieu of investment tax credits, including the solar energy investment tax credit and provided for an option to claim cash grants or an investment tax credit in lieu of production tax credits, including the wind production tax credit. Cash grants would be obtained separately from the tax return under rules and regulations published by the U. S. Treasury Department. SCE anticipates utilizing the solar energy investment tax credit for its investment in its PV Solar Rooftop facilities. EME has placed the Elkhorn Ridge, Phase II of the Goat Wind and High Lonesome wind projects in service during 2009. EME and its partner in the Elkhorn Ridge project have agreed to continue to claim production tax credits. EME is currently planning to claim investment tax credits for Phase II of the Goat Wind and High Lonesome wind projects. Both SCE and EME plan to review their plans based on rules and regulations regarding the grant payments in lieu of tax credits recently issued by the U. S. Treasury Department and based on tax planning activities during the second part of 2009. Edison International accounts for investment tax credits on the deferred method and, accordingly, will recognize tax benefits related to such credits over the estimated useful life of the projects.

Accounting for Uncertainty in Income Taxes

The following table provides a reconciliation of unrecognized tax benefits from January 1 to June 30:

In millions				2009			2008
				(Unaudited)
Balance at January 1				$	2,237		$	2,114
	Tax positions taken during the current year
		Increases			87			55
		Decreases			—			—
	Tax positions taken during a prior year
		Increases			148			84
		Decreases			(26	)		(97	)
Decreases for settlements during the period					(1,807	)		—
Reductions for lapses of applicable statute of limitations					—			—
Balance at June 30				$	639		$	2,156

Unrecognized tax benefits were reduced by $1.8 billion during the second quarter of 2009 as a result of consummating the Global Settlement discussed below.

Edison International believes it is reasonably possible that unrecognized tax benefits could be reduced by up to $104 million within the next twelve months from settlement of state tax matters for periods through 2002.

As of June 30, 2009 and December 31, 2008, respectively, if recognized, $256 million and $210 million of the unrecognized tax benefits would impact the effective tax rate.

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Accrued Interest and Penalties

The total amount of accrued interest and penalty related to Edison International's income tax reserve was $351 million and $200 million as of June 30, 2009 and December 31, 2008, respectively. After-tax interest income, recognized in income tax expense, was $113 million and $109 million for the three- and six-month periods ended June 30, 2009, respectively, and after-tax interest expense, recognized in income tax expense, was $5 million and $13 million for the three- and six-month periods ended June 30, 2008, respectively.

Tax Years Subject to Examination

Edison International's federal income tax returns are subject to examination by the IRS for tax years 2003 to present. Consummation of the Global Settlement, discussed below, effectively closed the examination for tax years 1986 – 2002 and resolved federal tax disputes related to Edison Capital's cross- border, leveraged leases in their entirety.

In addition to the IRS audits, Edison International's California and other state income tax returns are open for examination by the California Franchise Tax Board and the other state tax authorities for tax years 1986 to present. The Franchise Tax Board is currently examining tax years through 2002.

Global Settlement

As previously disclosed, Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolves federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002. Pursuant to the Global Settlement, Edison Capital terminated its interests in the cross-border leases and received net proceeds of $1.385 billion, including $121 million in the first quarter of 2009. See Note 14 for further discussion of the termination of the cross-border leases.

The Global Settlement and termination of the Edison Capital cross-border leases resulted in the following impacts:

•

Edison International recorded a consolidated after-tax earnings charge of $274 million through the second quarter of 2009 ($11 million of which was recorded in the first quarter of 2009) and expects that the Global Settlement together with the termination of the Edison Capital cross-border leases will result in a positive cash impact over time of approximately $380 million. The cash impacts of the Global Settlement will occur over the next few years.

•

The Global Settlement and related lease terminations resulted in a loss of $628 million, after tax, for Edison Capital through the second quarter of 2009, reflected in "Lease termination and other" ($920 million pre-tax), and "Income tax expense (benefit)" on the consolidated statements of income (loss). Edison Capital's overall net cash outflow from the Global Settlement will be approximately $300 million over time.

•

The Global Settlement also resolves all of SCE's federal income tax disputes and affirmative claims through tax year 2002. During the second quarter of 2009, SCE recorded after-tax earnings of $300 million reflected in "Income tax expense (benefit)" on the consolidated statements of income (loss) primarily related to settlement of two affirmative claims associated with the taxation of balancing account overcollections and taxation of proceeds received in consideration for transferring control of SCE's transmission and distribution system to the ISO as part of California's deregulation process. Both claims created tax timing differences that resulted in an interest refund from the IRS

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for prior period tax overpayments, but did not result in a permanent reduction in Edison International's and SCE's federal income tax liability. SCE expects an overall positive cash impact resulting from the Global Settlement of approximately $640 million over time, including the cash benefit of prior tax deposits of approximately $200 million.

•

On a combined basis, all other federal tax disputes involving the Edison International consolidated group for tax years 1986 – 2002 resulted in after-tax earnings of $54 million and expected positive cash flow over time of approximately $40 million. The earnings are attributable to miscellaneous net income tax benefits arising from the Global Settlement.

As a consequence of the cross-border lease terminations and Global Settlement, Edison Capital may be required to pay outstanding medium-term loans in the amount of $92 million (at June 30, 2009) and purchase certain affordable housing projects for approximately $20 million (at June 30, 2009) under existing guarantees. Edison International does not expect such payments to have a material adverse impact on its results of operations, financial position, or cash flows.

Edison International is addressing the impacts of the Global Settlement with state tax authorities and is awaiting receipt of final interest calculations from the IRS. Resolution of such matters with such authorities may change the estimated cash and earnings impacts described above.

Note 5. Compensation and Benefits Plans

Pension Plans

As of June 30, 2009, Edison International had made less than $1 million in contributions related to 2008 and $29 million related to 2009 and estimates to make $22 million of additional contributions in the last six months of 2009.

Net pension cost recognized is calculated under the actuarial method used for ratemaking. The difference between pension costs calculated for accounting and ratemaking is deferred.

Expense components are:

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2009			2008			2009			2008
		(Unaudited)
Service cost		$	32		$	32		$	63		$	63
Interest cost			52			50			103			100
Expected return on plan assets			(42	)		(65	)		(83	)		(131	)
Amortization of prior service cost			4			4			8			8
Amortization of net loss			14			—			28			1
Expense under accounting standards		$	60		$	21		$	119		$	41
Regulatory adjustment – deferred			(37	)		—			(73	)		—
Total expense recognized		$	23		$	21		$	46		$	41

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Postretirement Benefits Other Than Pensions

As of June 30, 2009, Edison International had made no contributions related to 2008 and $9 million related to 2009 and estimates to make $117 million of additional contributions in the last six months of 2009.

Expense components are:

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2009			2008			2009			2008
		(Unaudited)
Service cost		$	11		$	12		$	22		$	23
Interest cost			36			35			72			69
Expected return on plan assets			(21	)		(31	)		(42	)		(62	)
Amortization of prior service cost (credit)			(8	)		(8	)		(15	)		(15	)
Amortization of net loss			16			4			31			9
Total expense recognized		$	34		$	12		$	68		$	24

Stock-Based Compensation

During the first quarter of 2009, Edison International granted its 2009 stock-based compensation awards, which included stock options, performance shares, deferred stock units and restricted stock units. Total stock-based compensation expense (reflected in the caption "Other operation and maintenance" on the consolidated statements of income (loss)) was $10 million and $12 million for the three months ended June 30, 2009 and 2008, respectively, and was $16 million and $19 million for the six months ended June 30, 2009 and 2008, respectively. The income tax benefit recognized in the consolidated statements of income (loss) was $4 million and $5 million for the three months ended June 30, 2009 and 2008, respectively, and was $6 million and $8 million for the six months ended June 30, 2009 and 2008, respectively. Total stock-based compensation cost capitalized was $1 million and $2 million for the three- and six-month periods ended June 30, 2008. Consistent with SCE's 2009 GRC, no stock-based compensation was capitalized in 2009.

Stock Options

A summary of the status of Edison International stock options is as follows:

					Weighted-Average
		Stock Options			Exercise Price			Remaining Contractual Term (Years)			Aggregate Intrinsic Value
		(Unaudited)
Outstanding at December 31, 2008			13,441,835		$	34.22
Granted			4,941,647		$	24.93
Expired			(30,997	)	$	40.39
Forfeited			(233,157	)	$	32.54
Exercised			(176,485	)	$	23.62
Outstanding at June 30, 2009			17,942,843		$	31.78			6.79
Vested and expected to vest at June 30, 2009			17,226,430		$	31.74			6.69		$	75,026,638
Exercisable at June 30, 2009			10,154,314		$	30.31			5.16		$	52,413,898

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The amount of cash used to settle stock options exercised was $1 million and $27 million for the three months ended June 30, 2009 and 2008, respectively, and was $6 million and $40 million for the six months ended June 30, 2009 and 2008, respectively. Cash received from options exercised was $1 million and $13 million for the three months ended June 30, 2009 and 2008, respectively, and was $4 million and $20 million for the six months ended June 30, 2009 and 2008, respectively. The estimated tax benefit from options exercised was less than $1 million and $5 million for the three months ended June 30, 2009 and 2008, respectively, and was $1 million and $8 million for the six months ended June 30, 2009 and 2008, respectively.

The following is a summary of the status of Edison International nonvested performance shares classified as equity awards:

		Performance Shares			Weighted- Average Grant-Date Fair Value
		(Unaudited)
Nonvested at December 31, 2008			175,177		$	49.95
Granted			175,066		$	21.00
Forfeited			(10,706	)	$	31.16
Paid out			—		$	—
Nonvested at June 30, 2009			339,537		$	35.36

The following is a summary of the status of Edison International nonvested performance shares classified as liability awards (the current portion is reflected in the caption "Other current liabilities" and the long-term portion is reflected in "Pensions and benefits" on the consolidated balance sheets):

		Performance Shares			Weighted- Average Fair Value
		(Unaudited)
Nonvested at December 31, 2008			175,177
Granted			175,066
Forfeited			(10,706	)
Paid out			—
Nonvested at June 30, 2009			339,537		$	20.39

Note 6. Commitments and Contingencies

The following is an update to Edison International's commitments and contingencies. See Note 6 of "Notes to Consolidated Financial Statements" included in Edison International's 2008 Annual Report on Form 10-K for a detailed discussion.

Lease Commitments

Edison International has operating leases for power contracts and other operating leases for office space, vehicles, property and other equipment (with varying terms, provisions and expiration dates). SCE also has power purchase contracts which meet the requirements for capital leases and are reflected in "Utility plant" on the consolidated balance sheets. The gross amount of assets recorded in "Utility plant" for capital leases was $25 million at both June 30, 2009 and December 31, 2008. The asset carrying amount, net of amortization, was $15 million and $16 million at June 30, 2009 and

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December 31, 2008, respectively. The related obligations are reflected on the consolidated balance sheets as "Other current liabilities" and "Other deferred credits and other long-term liabilities." In addition, SCE has power purchase contracts which meet the requirements for capital leases, but are not reflected on the consolidated balance sheets since the lease terms begin in 2010 and 2011. There are no sublease rentals and the contingent rentals for capital leases were less than $1 million for both the six months ended June 30, 2009 and 2008. For additional discussion of these lease commitments, see Note 1 and 6 of "Notes to Consolidated Financial Statements" included in Edison International's 2008 Annual Report on Form 10-K. The following are the estimated remaining commitments (the majority of "other operating leases" are related to EME's long-term leases for the Illinois power facilities and Homer City facilities) for noncancelable operating leases and all contracts that meet the requirements for capital leases (whether or not recorded on the consolidated balance sheets):

In millions		Power Contracts Operating Leases			Other Operating Leases			Capital Leases
		(Unaudited)
Year ending December 31,
2009 (remaining six months)		$	435		$	176		$	3
2010			626			404			37
2011			498			378			120
2012			361			369			120
2013			356			357			120
Thereafter			2,186			2,178			2,526
Total future commitments		$	4,462		$	3,862		$	2,926
Amount representing executory costs			—			—			(710	)
Amount representing interest			—			—			(994	)
Net commitments		$	4,462		$	3,862		$	1,222

The minimum commitments above do not include EME's contingent rentals with respect to the wind projects which may be paid under certain leases on the basis of a percentage of sales calculation if this is in excess of the stipulated minimum amount.

Operating lease expense was $127 million and $133 million for the three months ended June 30, 2009 and 2008, respectively, and was $236 million and $244 million for the six months ended June 30, 2009 and 2008, respectively.

Other Commitments

At June 30, 2009, EME's subsidiaries had firm commitments to spend approximately $110 million during the remainder of 2009 and $14 million in 2010 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects and non-environmental improvements at both the Illinois Plants and the Homer City facilities. These expenditures are planned to be financed by cash on hand and cash generated from operations.

EME had entered into various turbine supply agreements with vendors to support its wind development efforts. At June 30, 2009, EME had secured the rights to 484 wind turbines (942 MW) for use in future projects for an aggregate purchase price of $1.2 billion, with remaining commitments of $596 million in 2009 and $242 million in 2010. At June 30, 2009, EME had recorded wind turbine deposits of $410 million, included in other long-term assets on its consolidated balance sheet. EME has executed non-binding letter agreements with two of its vendors to provide vendor financing. EME and such vendors are in the process of negotiating definitive agreements based on the non-binding letter

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agreements, but there is no assurance that final binding agreements will be executed or executed on terms that conform to the letter agreements. If definitive agreements are executed substantially in accordance with the terms of the letter agreements, turbine commitments would be reduced to approximately $191 million in 2009, $229 million in 2010, and $210 million in 2011, and the remaining $206 million due based on specified conditions (expected during the time period of 2011 and 2014). These commitments would be further reduced during this period if a third turbine supplier agrees to provide vendor financing. Furthermore, EME can elect under the existing turbine supply agreement with this supplier to terminate the agreement for convenience which would further reduce turbine commitments to $9 million in 2009 and $49 million in 2010 (in such case, EME would write off approximately $90 million in previously made non-refundable deposits).

At June 30, 2009, Midwest Generation and EME Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices subject to adjustment clauses, these minimum commitments are currently estimated to aggregate $417 million, summarized as follows: remainder of 2009 – $230 million, 2010 – $177 million, and 2011 – $10 million.

In July 2009, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments, together with the estimated transportation costs under the existing agreements through 2011, are currently estimated to be $136 million for 2010, $264 million for 2011 and $134 million for 2012.

During the second quarter of 2009, SCE extended its power purchase agreement with Midway Sunset which resulted in additional commitments estimated to be: remainder of 2009 – $13 million, 2010 – $18 million, 2011 – $18 million, 2012 – $18 million and thereafter – $129 million. See Note 12 for additional information related to the terms of the extended agreement.

Guarantees and Indemnities

Edison International's subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts included performance guarantees, guarantees of debt and indemnifications.

Tax Indemnity Agreements

In connection with the sale-leaseback transactions related to the Homer City facilities in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities.

Indemnities Provided as Part of the Acquisition of the Illinois Plants

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to

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such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV discussed below under "—Contingencies—Midwest Generation New Source Review Notice of Violation" and potential litigation by private groups related to the NOV. Except as discussed below, EME has not recorded a liability related to the environmental indemnity specified in the acquisition agreement.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company, LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2010. There were approximately 214 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2009. Midwest Generation had recorded a $51 million liability at June 30, 2009 related to this matter.

The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. For discussion of the NOV received by EME Homer City and associated indemnity claims, see "—Contingencies—EME Homer City New Source Review Notice of Violation." EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale Agreements

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2009, EME had recorded a liability of $97 million (of which $52 million is classified as a current liability) related to these matters.

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In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the asset prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2009, EME had recorded a liability of $3 million related to these matters.

Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

Mountainview Filter Cake Indemnity

Mountainview owns and operates a power plant in Redlands, California. The plant utilizes water from on-site groundwater wells and City of Redlands (City) recycled water for cooling purposes. Unrelated to the operation of the plant, this water contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant's wastewater treatment "filter cake." Use of this impacted groundwater for cooling purposes was mandated by Mountainview's California Energy Commission permit. Mountainview has indemnified the City for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this guarantee.

Other Edison International Indemnities

Edison International provides other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified environmental indemnities and income taxes with respect to assets sold. Edison International's obligations under these agreements may be limited in terms of time and/or amount, and in some instances Edison International may have recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. Edison International has not recorded a liability related to these indemnities.

Contingencies

In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes the outcome of these other proceedings will not materially affect its results of operations, financial position or liquidity.

EME Homer City New Source Review Notice of Violation

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former owners of the Homer City facilities) performed repair or

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replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant Deterioration requirements of the CAA. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. On June 30, 2009, the US EPA issued a request for information to EME Homer City under Section 114 of the CAA. EME Homer City is working on a response to the request. EME Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. EME Homer City cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

EME Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which EME Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting a portion of defense costs related to the claims.

EME Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, have sought indemnification and defense from EME Homer City for costs and liability associated with the EME Homer City NOV. EME Homer City responded by undertaking the indemnity obligation and defense of the claims.

Environmental Remediation

Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

Possible future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that additional costs would be recovered from customers or that Edison International's results of operations, financial position or cash flow would not be materially affected.

Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International records the lower end of this reasonably likely range of costs (classified as "Other long-term liabilities") at undiscounted amounts.

As of June 30, 2009, Edison International's recorded estimated minimum liability to remediate its 30 identified sites at SCE (24 sites) and EME (6 sites primarily related to Midwest Generation) was $43 million, $39 million of which was related to SCE including $6 million related to San Onofre. Edison International's other subsidiaries have no identified remediation sites. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the

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time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $178 million, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 31 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $29 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $39 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $11 million to $30 million. Recorded costs were $2 million and $7 million for the three months ended June 30, 2009 and 2008, respectively, and were $5 million and $10 million for the six months ended June 30, 2009 and 2008, respectively.

Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flow. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Federal and State Income Taxes

Edison International remains subject to examination by the IRS for tax years 2003 to present. As discussed in the section "Global Settlement" in Note 4, the Global Settlement was finalized on May 5, 2009 and effectively closed the examination for tax years 1986 – 2002 and resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases in their entirety.

2009 FERC Rate Case

On March 1, 2009, SCE implemented, subject to refund, proposed revisions to its base transmission rates initially accepted by the FERC. SCE and the parties to the FERC rate case reached a settlement on the 2009 base transmission rates and on July 1, 2009, SCE filed the proposed settlement. The settlement provides for a revenue requirement of $448 million, which increases SCE's revenue requirement by $136 million over the previously authorized base transmission revenue requirement. SCE expects that the FERC will issue an order approving the proposed settlement during the third quarter of 2009. If approved by the FERC, the proposed settlement rates will become retroactively effective as of March 1, 2009. As of June 30, 2009, SCE had collected revenue, subject to refund, of

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$21 million that, upon final approval of the settlement agreement, will be refunded to ratepayers. SCE did not recognize this refund in revenue and implementation of the settlement agreement will not impact earnings.

FERC Transmission Incentives

The Energy Policy Act of 2005 established incentive-based rate treatments for the transmission of electric energy in interstate commerce by public utilities. Pursuant to this act, in November 2007, the FERC issued an order granting incentives on three of SCE's largest proposed transmission projects. These include an incentive above SCE's otherwise-authorized return on equity of 125 basis points for SCE's DPV2 and Tehachapi transmission projects and 75 basis points for SCE's Rancho Vista Substation Project ("Rancho Vista"), as well as 50 basis points on SCE's cost of capital for its entire transmission rate base for SCE's participation in the CAISO. In addition, the order on incentives permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, of all three projects mentioned above and 100% recovery of prudently-incurred abandoned plant costs for DPV2 and Tehachapi, if either or both of these projects are cancelled due to factors beyond SCE's control. The CPUC is appealing the FERC incentives order at the DC Circuit Court of Appeals but the appeal has been deferred until a final FERC order is issued in the 2008 CWIP case.

FERC Construction Work in Progress Mechanism (CWIP)

2008 CWIP

In February 2008, the FERC approved, subject to refund, SCE's revision to its tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects, as authorized by FERC in its transmission incentives order discussed above which resulted in base transmission revenue billed of $37 million. In March 2008, the CPUC filed a petition for rehearing with the FERC on the FERC's acceptance of SCE's proposed ROE for CWIP and in another 2008 protest to an SCE compliance filing, requested an evidentiary hearing to be set to further review SCE's costs. SCE cannot predict the outcome of the matters in this proceeding.

2009 CWIP

In December 2008, the FERC approved SCE's CWIP rate adjustment which resulted in a CWIP revenue requirement of $39 million, effective on January 1, 2009, subject to refund as well as subject to the outcome of the pending 2008 FERC CWIP proceeding.

Four Corners CPUC Emissions Performance Standard Ruling

The emission performance standards adopted by the CPUC and CEC pursuant to SB 1368 prohibit SCE and other California load-serving entities from entering into long-term financial commitments with generators that do not meet the emission performance standards, which would include most coal-fired plants. In January 2008, SCE filed a petition with the CPUC seeking clarification that the emission performance standard would not apply to capital expenditures required by existing agreements among the owners at Four Corners. The CPUC issued a proposed decision finding that the emission performance standard was not intended to apply to capital expenditures at Four Corners requested by SCE in its GRC for the period 2007 – 2011. In October 2008, the Assigned Commissioner and Administrative Law Judge issued a ruling withdrawing the proposed decision and seeking additional comment on whether the finding in the proposed decision should be changed and whether SCE should be allowed to recover such capital expenditures. SCE estimates that its share of capital expenditures approved by the owners at Four Corners since the GHG emission performance standard decision was issued in January 2007 is approximately $43 million, of which approximately $10 million had been expended through June 30, 2009. The ruling also directs SCE to explain why certain information was

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not included in its petition and why the failure to include such information should not be considered misleading in violation of CPUC rules. SCE cannot predict whether any amounts will be disallowed.

ISO Disputed Charges

The FERC issued an order that has been subject to continuing legal proceedings concerning a dispute between the ISO and the cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. On July 16, 2009, the FERC issued an order, subject to appeal, denying a request for rehearing made by the cities and reaffirmed its previous decision that certain transmission service related charges should be allocated to the cities. The cities have 60 days to file an appeal. If a subsequent regulatory decision changes the allocation of responsibility for these charges and SCE is required to pay these charges as a transmission owner, estimated to be a net amount of approximately $20 million to $25 million, including interest, SCE may seek recovery in its reliability service rates. SCE cannot predict either the outcome of any appeal or whether recovery of these charges in its reliability service rates would be permitted in rates if SCE is required to pay these charges.

Leveraged Lease Investments

At June 30, 2009, Edison Capital had a net leveraged lease investment, before deferred taxes, of $47 million in three aircraft leased to American Airlines. American Airlines reported net losses in the first and second quarters of 2009 and previously reported losses for 2008. A default in the leveraged lease by American Airlines could result in a loss of some or all of Edison Capital's lease investment. At June 30, 2009, American Airlines was current in its lease payments to Edison Capital.

Midwest Generation New Source Review Notice of Violation

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install best available control technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV.

On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by several Chicago-based environmental action groups stating that, in light of the NOV, the groups are examining the possibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumably on the same or similar theories advanced by the US EPA in the NOV. On July 28, 2009, Midwest Generation received a sixty-day Notice of Intent to Sue signed by the same groups, stating their intent to file a citizen suit alleging exceedances of CAA opacity limits and violations of permit requirements related to monitoring and reporting.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison

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may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

Midwest Generation cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.

Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 against SCE, among other defendants, arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things, violations of the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion. In March 2001, the Hopi Tribe was permitted to intervene as an additional plaintiff but has not yet identified a specific amount of damages claimed. The case was stayed at the request of the parties in October 2004, but was reinstated to the active calendar in March 2008. In April 2009, in a related case filed in December 1993 against the U.S. Government, the U.S. Supreme Court found that the Navajo Nation did not have a claim for compensation.

SCE cannot predict the outcome of the Tribes' complaints against SCE or the ultimate impact of the April 2009 U.S. Supreme Court decision on these complaints.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $12.5 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($300 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site.

Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. Beginning October 29, 2008, the maximum deferred premium for each nuclear incident is approximately $118 million per reactor, but not more than approximately $18 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear incident is adjusted for inflation at least once every five years. The most recent inflation adjustment took effect on October 29, 2008. Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by utilities with nuclear facilities issues these policies. If losses at any

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nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $45 million per year. Insurance premiums are charged to operating expense.

Procurement of Renewable Resources

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010.

It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by 2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules, such as banking of past surplus and earmarking of future deliveries from executed contracts. SCE continues to engage in several renewable procurement activities including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives.

Under current CPUC decisions, potential penalties for SCE's inability to achieve its renewable procurement objectives for any year will be considered by the CPUC in the context of the CPUC's review of SCE's annual compliance filings. Under the CPUC's current rules, the maximum penalty for inability to achieve renewable procurement targets is $25 million per year. SCE does not believe it will be assessed penalties for 2008 or the prior years and cannot predict whether it will be assessed penalties for future years.

RPM Buyers' Complaint

On May 30, 2008, a group of entities referring to themselves as the "RPM Buyers" filed a complaint at the FERC asking that PJM's RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust and unreasonable capacity prices. On September 19, 2008, the FERC dismissed the RPM Buyers' complaint, finding that the RPM Buyers had failed to allege or prove that any party violated PJM's tariff and market rules, and that the prices determined during the transition period were determined in accordance with PJM's FERC-approved tariff. On October 20, 2008, the RPM Buyers requested rehearing of the FERC's order dismissing their complaint. On June 18, 2009, the FERC denied rehearing of the order.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre (approximately $24 million, plus interest). SCE has also been paying a required quarterly fee equal to 0.1¢ per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. The trial was completed in April 2009. SCE cannot predict the outcome of this proceeding or when a decision will be issued by the Court.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Such interim storage for San Onofre is on-site.

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APS, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel at Palo Verde. Palo Verde plans to add storage capacity incrementally to maintain full core off-load capability for all three units. In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed an independent spent fuel storage facility.

Note 7. Consolidated Statement of Changes in Equity

The following table provides the changes in equity for the six months ended June 30, 2009:

		Equity Attributable to Edison International												Noncontrolling Interests
In millions		Common Stock			Accumulated Other Comprehensive Income			Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity
		(Unaudited)
Balance at December 31, 2008		$	2,272		$	167		$	7,078		$	9,517		$	285		$	907		$	10,709
Net income			—			—			234			234			16			25			275
Other comprehensive income			—			37			—			37			—			—			37
Common stock dividends declared ($ 0.62 per share)			—			—			(202	)		(202	)		—			—			(202	)
Dividends, distributions to noncontrolling interests and other			—			—			—			—			(26	)		(25	)		(51	)
Shares purchased for stock-based compensation			—			—			(6	)		(6	)		—			—			(6	)
Proceeds from stock option exercises			—			—			4			4			—			—			4
Noncash stock-based compensation and other			11			—			(7	)		4			—			—			4
Excess tax benefits related to stock-based awards			2			—			—			2			—			—			2
Balance at June 30, 2009		$	2,285		$	204		$	7,101		$	9,590		$	275		$	907		$	10,772

The following table provides the changes in equity for the six months ended June 30, 2008:

		Equity Attributable to Edison International												Noncontrolling Interests
In millions		Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity
		(Unaudited)
Balance at December 31, 2007		$	2,225		$	(92	)	$	6,311		$	8,444		$	295		$	915		$	9,654
Net income			—			—			559			559			30			25			614
Other comprehensive loss			—			(323	)		—			(323	)		—			—			(323	)
Common stock dividends declared ($ 0.61 per share)			—			—			(199	)		(199	)		—			—			(199	)
Preferred stock redeemed, net of gain			2			—			—			2			—			(8	)		(6	)
Dividends, distributions to noncontrolling interests and other			—			—			—			—			(11	)		(25	)		(36	)
Shares purchased for stock-based compensation			—			—			(51	)		(51	)		—			—			(51	)
Proceeds from stock option exercises			—			—			20			20			—			—			20
Noncash stock-based compensation and other			15			—			(11	)		4			—			—			4
Excess tax benefits related to stock-based awards			11			—			—			11			—			—			11
Balance at June 30, 2008		$	2,253		$	(415	)	$	6,629		$	8,467		$	314		$	907		$	9,688

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Note 8. Accumulated Other Comprehensive Income

Edison International's accumulated other comprehensive income consists of:

In millions		Unrealized Gains on Cash Flow Hedges			Foreign Currency Translation Adjustment			Pension and PBOP– Net Gain (Loss)			Pension and PBOP– Prior Service Cost			Accumulated Other Comprehensive Income
		(Unaudited)
Balance at December 31, 2008		$	240		$	(4	)	$	(70	)	$	1		$	167
Current period change			29			4			4			—			37
Balance at June 30, 2009		$	269		$	—		$	(66	)	$	1		$	204

The amount of commodity hedges included in unrealized gains on cash flow hedges, net of tax, at June 30, 2009 was a gain of $270 million. The amount of interest rate hedges included in unrealized gains on cash flow hedges, net of tax, at June 30, 2009 was a loss of $1 million. For further discussion regarding interest rate hedges, see Note 2—Derivative Instruments and Hedging Activities.

Unrealized gains on commodity hedges included those related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. As EME's hedged positions for continuing operations are realized, $209 million, after tax, of the net unrealized gains on cash flow hedges at June 30, 2009 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenue recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum period over which a cash flow hedge is designated is through December 31, 2011.

Note 9. Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

			Six Months Ended June 30,
In millions			2009			2008
			(Unaudited)
Cash payments for interest and taxes:
Interest – net of amounts capitalized			$	314		$	266
Tax payments			$	198		$	128
Noncash investing and financing activities:
Dividends declared but not paid:
	Common stock		$	101		$	99
	Preferred and preference stock of utility not subject to mandatory redemption		$	13		$	13

Note 10. Fair Value Measurements

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price" in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability

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should reflect the entity's non-performance risk. In addition, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under SFAS No. 157 are:

•

Level 1 – Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets and liabilities;

•

Level 2 – Pricing inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument; and

•

Level 3 – Prices or valuations that require inputs that are both significant to the fair value measurements and unobservable.

Edison International's assets and liabilities carried at fair value primarily consist of derivative contracts, SCE nuclear decommissioning trust investments and money market funds. Derivative contracts primarily relate to power and gas and include contracts for forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange traded or over-the-counter traded.

The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. The majority of EME's derivative contracts used for hedging purposes are based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub peak and AEP/Dayton) adjusted for nonperformance risks. EME obtains forward market prices from traded exchanges (ICE Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believes to provide the most liquid market for the commodity. EME considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades. The majority of the fair value of EME's derivative contracts determined in this manner are classified as Level 2. SCE's Level 2 derivatives primarily consist of financial natural gas swaps, fixed float swaps, and natural gas physical trades for which SCE obtains the applicable Henry Hub and basis forward market prices from the New York Mercantile Exchange and Intercontinental Exchange. Level 2 also includes Edison Capital's foreign currency swap contract which is valued based on bank evaluations primarily using published foreign currency rates.

Level 3 includes the majority of SCE's derivatives, including over-the-counter options, bilateral contracts, capacity contracts, and QF contracts. The fair value of these SCE derivatives is determined using uncorroborated non-binding broker quotes (from one or more brokers) and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness. SCE has Level 3 fixed float swaps for which SCE obtains the applicable Henry Hub and basis forward market prices from the New York Mercantile Exchange. However, these swaps have contract terms that extend beyond observable market data and the unobservable inputs incorporated in the fair value determination are considered significant compared to the overall swap's fair value.

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Level 3 also includes derivatives that trade infrequently (such as financial transmission rights and CRRs in the California market and over-the-counter derivatives at illiquid locations), derivatives with counterparties that have significant nonperformance risks as discussed below and long-term power agreements. For illiquid financial transmission rights and CRRs, Edison International reviews objective criteria related to system congestion and other underlying drivers and adjusts fair value when Edison International concludes a change in objective criteria would result in a new valuation that better reflects the fair value.

Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. In circumstances where Edison International cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, Edison International continues to assess valuation methodologies used to determine fair value.

In assessing nonperformance risks, Edison International reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. At June 30, 2009, Edison International reduced the fair value of derivative assets and derivative liabilities for nonperformance risks by $9 million and $16 million, respectively.

Investments in money market funds are generally classified as Level 1 as fair value is determined by observable market prices (unadjusted) in active markets.

The SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed-income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information.

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The following table sets forth assets and liabilities that were accounted for at fair value as of June 30, 2009 by level within the fair value hierarchy.

In millions				Level 1			Level 2			Level 3			Netting and collateral(1)			Total
				(Unaudited)
Assets at Fair Value
	Money market funds(2)			$	2,456		$	—		$	1		$	—		$	2,457
	Derivative contracts				21			498			885			(395	)		1,009
	Long-term disability plan				10			—			—			—			10
	Nuclear decommissioning trusts(3)
		Municipal bonds			—			618			—			—			618
		Stocks			1,435			—			—			—			1,435
		United States government issues			178			30			—			—			208
		Corporate bonds			—			378			—			—			378
		Short-term investments, primarily cash equivalents			2			19			—			—			21
		Sub-total of nuclear decommissioning trusts		$	1,615		$	1,045		$	—		$	—		$	2,660
Total assets(4)				$	4,102		$	1,543		$	886		$	(395	)	$	6,136
Liabilities at Fair Value
	Derivative contracts				—			(400	)		(529	)		233			(696	)
Net assets (liabilities)				$	4,102		$	1,143		$	357		$	(162	)	$	5,440

The following table sets forth assets and liabilities that were accounted for at fair value as of December 31, 2008 by level within the fair value hierarchy:

In millions				Level 1			Level 2			Level 3			Netting and Collateral(1)			Total
				(Unaudited)
Assets at Fair Value
	Money market funds(2)			$	3,543		$	—		$	3		$	—		$	3,546
	Derivative contracts				4			419			448			(300	)		571
	Long-term disability plan				7			—			—			—			7
	Nuclear decommissioning trusts(3)
		Municipal bonds			—			629			—			—			629
		Stocks			1,308			—			—			—			1,308
		United States government issues			172			132			—			—			304
		Corporate bonds						260			—			—			260
		Short-term investments, primarily cash equivalents			4			23			—			—			27
		Sub-total of nuclear decommissioning trusts		$	1,484		$	1,044		$	—		$	—		$	2,528
Total assets(4)				$	5,038		$	1,463		$	451		$	(300	)	$	6,652
Liabilities at Fair Value
	Derivative contracts				(2	)		(397	)		(753	)		198			(954	)
Net assets (liabilities)				$	5,036		$	1,066		$	(302	)	$	(102	)	$	5,698

(1)

Represents cash collateral and the impact of netting across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.

(2)

Included in cash and cash equivalents and short-term investments on Edison International's consolidated balance sheet.

(3)

Excludes net assets/(liabilities) of $13 million and $(4) million at June 30, 2009 and December 31, 2008, respectively, of interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases.

(4)

Excludes $32 million at both June 30, 2009 and December 31, 2008, of cash surrender value of life insurance investments for deferred compensation.

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The following table sets forth a summary of changes in the fair value of Level 3 financial instruments:

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
			(Unaudited)
Fair value, net at beginning of period			$	143		$	190		$	(302	)	$	98
Total realized/unrealized gains (losses):
	Included in earnings(1)			(49	)		59			97			92
	Included in regulatory assets and liabilities(2)			204			112			591			165
	Included in accumulated other comprehensive income			—			(4	)		—			(6	)
Purchases and settlements, net				67			36			(17	)		47
Transfers in or out of Level 3				(8	)		(7	)		(12	)		(10	)
Fair value, net at June 30			$	357		$	386		$	357		$	386
Change during the period in unrealized gains related to financial instruments held at June 30(3)			$	225		$	183		$	675		$	213

(1)

Reported in "Competitive power generation" revenue on Edison International's consolidated statement of income.

(2)

Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

(3)

Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income were $13 million and $34 million for the three months ended June 30, 2009 and 2008, respectively, and were $71 million and $37 million for the six months ended June 30, 2009 and 2008, respectively. The remainder of the unrealized gains relate to SCE. See (2) above.

Level 3 derivative contracts reflect EME's load requirements services contracts. The energy price risk related to these contracts was substantially hedged, but such hedge contracts are classified as Level 2 and, therefore, not reflected as an offsetting position in Level 3.

Nuclear Decommissioning Trusts

SCE is collecting in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.

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The following table sets forth amortized cost and fair value of the trust investments:

					Amortized Cost						Fair Value
In millions		Maturity Dates			June 30, 2009			December 31, 2008			June 30, 2009			December 31, 2008
					(Unaudited)
Municipal bonds			2009 – 2042		$	548		$	561		$	618		$	629
Stocks			–			818			839			1,435			1,308
United States government issues			2009 – 2051			191			268			208			304
Corporate bonds			2009 – 2049			316			214			378			260
Short-term investments, primarily cash equivalents			2009			34			24			34			23
Total					$	1,907		$	1,906		$	2,673		$	2,524

Note: Maturity dates as of June 30, 2009.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Realized gains were $115 million and $25 million for the three months ended June 30, 2009 and 2008, respectively and $189 million and $53 million for the six months ended June 30, 2009 and 2008, respectively. Realized losses were $77 million and $5 million for the three months ended June 30, 2009 and 2008, respectively and $140 million and $6 million for the six months ended June 30, 2009 and 2008, respectively. Proceeds from sales of securities (which are reinvested) were $652 million and $672 million for the three months ended June 30, 2009 and 2008, respectively and $1.3 billion and $1.5 billion for the six months ended June 30, 2009 and 2008, respectively. Unrealized holding gains, net of losses, were $766 million and $618 million at June 30, 2009 and December 31, 2008, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.

The following table sets forth a summary of changes in the fair value of the trust for the six months ended June 30, 2009:

In millions		2009
		(Unaudited)
Balance at beginning of period		$	2,524
Realized gains – net			49
Unrealized gains – net			148
Other-than-temporary impairments			(103	)
Interest, dividends, contributions and other			55
Balance at June 30, 2009		$	2,673

Due to regulatory mechanisms, changes in the fair value of the trust have no impact on operating revenue. SCE reviews each security for other-than-temporary impairment losses on the last day of each month compared to the last day of the previous month. If the fair value on both days is less than the cost for that security, SCE recognizes a realized 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.

Nuclear decommissioning costs are recovered in utility rates. These costs are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $46 million per year. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. These contributions are determined based on an analysis of the current value of trusts assets

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and long-term forecasts of cost escalation, the estimate and timing of decommissioning costs, and after-tax return on trust investments. Favorable or unfavorable investment performance in a period will not change the amount of contributions for that period. However, trust performance for the three years leading up to a CPUC review proceeding will provide input into future contributions. On April 3, 2009, SCE submitted its triennial nuclear decommissioning application, requesting that its trust fund contributions increase to approximately $64.5 million per year, beginning on January 1, 2011. The CPUC has set certain restrictions related to the investments of these trusts. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates.

Long-term Debt

The carrying amounts and fair values of long-term debt are:

		June 30, 2009						December 31, 2008
In millions		Carrying Amount			Fair Value			Carrying Amount			Fair Value
		(Unaudited)
Long-term debt		$	11,276		$	10,759		$	10,950		$	10,637
Long-term debt due within one year		$	382		$	382		$	174		$	175

Fair values of long-term debt are based on bank evaluations.

Note 11. Regulatory Assets and Liabilities

Regulatory assets included on the consolidated balance sheets are:

In millions		June 30, 2009			December 31, 2008
		(Unaudited)
Current:
Regulatory balancing accounts		$	214		$	455
Energy derivatives			120			138
Other			—			12
		$	334		$	605
Long-term:
Regulatory balancing accounts		$	35		$	29
Flow-through taxes – net			1,456			1,337
ARO			171			224
Unamortized nuclear investment – net			360			375
Nuclear-related ARO investment – net			268			278
Unamortized coal plant investment – net			77			79
Unamortized loss on reacquired debt			298			309
SFAS No. 158 pensions and postretirement benefits			1,898			1,882
Energy derivatives			111			723
Environmental remediation			39			40
Other			139			138
		$	4,852		$	5,414
Total Regulatory Assets		$	5,186		$	6,019

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Regulatory liabilities included on the consolidated balance sheets are:

In millions		June 30, 2009			December 31, 2008
		(Unaudited)
Current:
Regulatory balancing accounts		$	940		$	1,068
Other			8			43
		$	948		$	1,111
Long-term:
Regulatory balancing accounts		$	34		$	43
Cost of removal			2,456			2,368
Employee benefit plans			145			70
		$	2,635		$	2,481
Total Regulatory Liabilities		$	3,583		$	3,592

Note 12. Variable Interest Entities

Projects or Entities that are Consolidated

EME has purchased a majority interest in a number of wind projects under joint development agreements with third-party developers. At June 30, 2009 and December 31, 2008, EME had majority interests in 15 wind projects with a total generating capacity of 700 MW that had minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. Minority interest holders have key rights over matters such as budgets, incurrence of debt, and sale of the project, and in certain cases, receive a higher allocation of income and losses after a minimum return is earned by EME. In determining that EME was the primary beneficiary, a key factor was the conclusion that the power sales agreements did not constitute a variable interest since the agreements have a fixed unit price and do not absorb expected losses. As a result, the determination of EME as the primary beneficiary was based on the allocation of income and losses with EME expected to earn a majority of the expected gains or absorb the majority of the expected losses based on its ownership interest.

Consolidation of QFs –

SCE has variable interests in contracts with certain QFs that contain variable contract pricing provisions based on the price of natural gas. Four of these contracts are with entities that are partnerships owned in part by a related party, EME. These four contracts had 20-year terms at inception. The QFs sell electricity to SCE and steam to nonrelated parties. Under FIN 46(R), Edison International and SCE consolidate these four projects.

In determining that SCE was the primary beneficiary, SCE considered the term of the contract, percentage of plant capacity, pricing, and other variable interests. SCE performed a quantitative assessment which included the analysis of the expected losses and expected residual returns of the entity by using the various estimated projected cash flow scenarios associated with the assets and activities of that entity. The quantitative analysis provided sufficient evidence to determine that SCE

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was the primary beneficiary absorbing a majority of the entity's expected losses, receiving a majority of the entity's expected residual returns, or both.

Project		Capacity			Termination Date(1)			EME Ownership
		(Unaudited)
Kern River			300 MW			June 2011			50	%
Midway-Sunset			225 MW			May 2009			50	%
Sycamore			300 MW			December 2007			50	%
Watson			385 MW			December 2007			49	%

(1)

SCE's power purchase agreements with Sycamore and Watson expired on December 31, 2007. In addition, SCE's power purchase agreement with Midway-Sunset expired on May 7, 2009. These three projects are currently selling electricity to SCE under the terms and conditions contained in its prior long-term power purchase agreement, with revised pricing terms as mandated by the CPUC.

The following table presents summarized financial information of the SCE VIEs and EME wind projects that had non-controlling interests held by others that were consolidated at June 30, 2009 and December 31, 2008:

In millions		June 30, 2009			December 31, 2008
		(Unaudited)
Current assets		$	196		$	206
Nonutility property			1,242			1,239
Other long-term assets			3			3
Total assets		$	1,441		$	1,448
Current liabilities		$	72		$	92
Asset retirement obligation			16			15
Long-term obligations net of current maturities			22			25
Deferred revenues			20			15
Other long-term liabilities			20			18
Total liabilities		$	150		$	165
Noncontrolling interests(1)		$	265		$	268

(1)

The noncontrolling interests related to SCE's VIEs take into consideration EME's ownership in the Big 4 projects.

Assets serving as collateral for the debt obligations related to the wind projects had a carrying value of $84 million at both June 30, 2009 and December 31, 2008, and primarily consist of property, plant and equipment. The consolidated statement of income (loss) and cash flow for the six months ended June 30, 2009 includes $1 million of pre-tax loss and $32 million of operating cash flow related to variable interest entities that are consolidated.

SCE's VIE projects do not have any third party debt outstanding. SCE has no investment in, nor obligation to provide support to, these entities other than its requirement to make contract payments. Any profit or loss generated by these entities will not effect SCE's income statement, except that SCE would be required to recognize losses if these projects have negative equity in the future. These losses, if any, would not affect SCE's liquidity. Any liabilities of these projects are nonrecourse to SCE.

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Consolidation of Investments in Affordable Housing Projects –

Edison Capital is the primary beneficiary of one real estate project which has $1 million of debt guaranteed by a subsidiary of Edison Capital and nonrecourse debt of $9 million at both June 30, 2009 and December 31, 2008, respectively. Property serving as collateral for these loans had a carrying value of $10 million at both June 30, 2009 and December 31, 2008, respectively, and is classified as nonutility property on the consolidated balance sheet. Edison Capital is the primary beneficiary in these entities due to the debt guarantee. Other than the guarantee, the creditors to this project do not have recourse to the general credit of Edison Capital.

Edison Capital is the primary beneficiary of eight real estate investment partnerships that were formed to syndicate Edison Capital's interests in real estate projects. In these real estate partnerships, Edison Capital has guaranteed the third party investors yield on their investments. Such guarantees are considered a variable interest and Edison Capital is considered the primary beneficiary of such investments. At June 30, 2009, the consolidated balance sheet included investments in real estate partnerships and noncontrolling interests of $9 million and $8 million, respectively, related to interests of third parties. At December 31, 2008, the consolidated balance sheet included investments in real estate partnerships and noncontrolling interests of $14 million and $12 million, respectively, related to interests of third parties.

Projects that are not Consolidated

EME has a number of investments in power projects that are accounted for under the equity method. Under the equity method, the project assets and related liabilities are not consolidated on EME's consolidated balance sheet. Rather, EME's financial statements reflect its investment in each entity and it records only its proportionate ownership share of net income or loss.

Entities formed to own these projects are generally structured with a management committee in which EME exercises significant influence but cannot exercise unilateral control over the operating, funding or construction activities of the project entity. Two of these projects have secured long-term debt to finance the assets constructed and/or acquired by them. These financings generally are secured by a pledge of the assets of the project entity, but do not provide for any recourse to EME. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EME's project investment, but would generally not require EME to contribute additional capital. At June 30, 2009, entities which EME has accounted for under the equity method had indebtedness of $247 million, of which $111 million is proportionate to EME's ownership interest in these projects. At December 31, 2008, entities which EME has accounted for under the equity method had indebtedness of $294 million, of which $128 million is proportionate to EME's ownership interest in these projects.

As of June 30, 2009 and December 31, 2008, EME has a 50% interest in the March Point project. EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. The obligations under this indemnification agreement as of June 30, 2009 and December 31, 2008, if payment were required, would be $47 million and $56 million, respectively. EME has not recorded a liability related to the indemnity. EME's maximum exposure to loss at June 30, 2009 is $50 million. During the first quarter of 2009, EME commenced recording its share of equity in income from the March Point project. EME recorded $1 million and $3 million during the second quarter and six

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months ended June 30, 2009, respectively. To the extent that cash is received from the project in excess of EME's investment, such amount will be recorded as equity in income.

Edison Capital has a number of investments in real estate projects that are accounted for under the equity method. Under the equity method, the project assets and related liabilities are not consolidated in Edison Capital's consolidated balance sheet. Rather, Edison Capital's financial statements reflect its investment in each entity and it records only its proportionate ownership share of net income or loss.

Edison Capital's maximum exposure to loss from affordable housing investments in this category is generally limited to its net investment balance of $5 million and recapture of tax credits (estimated at $36 million as of June 30, 2009 and December 31, 2008).

Entities with Unavailable Financial Information

SCE also has seven other contracts with QFs that contain variable pricing provisions based on the price of natural gas and are potential VIEs under FIN 46(R). SCE might be considered to be the consolidating entity under this standard. SCE continues to attempt to obtain information for these projects in order to determine whether the projects should be consolidated by SCE. These entities are not legally obligated to provide the financial information to SCE and have declined to provide any financial information to SCE. Under the grandfather scope provisions of FIN 46(R), SCE is not required to apply this rule to these entities as long as SCE continues to be unable to obtain this information. The aggregate capacity dedicated to SCE for these projects is 207 MW and 263 MW at June 30, 2009 and December 31, 2008, respectively. The amounts that SCE paid to these projects were $30 million and $57 million for the three months ended June 30, 2009 and 2008, respectively, and $60 million and $98 million for the six months ended June 30, 2009 and 2008, respectively. These amounts are recoverable in utility customer rates. SCE has no exposure to loss as a result of its involvement with these projects.

Note 13. Business Segments

Edison International's reportable business segments include its electric utility operation segment (SCE), a competitive power generation segment (EME), and a financial services and other segment (Edison Capital and other EMG subsidiaries). Edison International evaluates performance based on net income.

SCE is a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and Southern California. SCE also produces electricity. EME is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from electric power generation facilities. EME also conducts hedging and energy trading activities in power markets open to competition. Edison Capital is a provider of financial services with investments worldwide.

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Segment information was:

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2009			2008			2009			2008
		(Unaudited)
Operating Revenue (Loss):
Electric utility		$	2,273		$	2,850			4,462		$	5,231
Competitive power generation			557			613			1,169			1,332
Financial services and other(4)			5			15			17			29
Parent and other(5)			(1	)		(1	)		(2	)		(1	)
Consolidated Edison International		$	2,834		$	3,477		$	5,646		$	6,591
Net Income (Loss) attributable to Edison International:
Electric utility(1)		$	499		$	157		$	707		$	307
Competitive power generation(2)			40			72			96			217
Financial services and other(3)(4)			(598	)		39			(606	)		48
Parent and other(5)(6)			43			(7	)		37			(13	)
Consolidated Edison International		$	(16	)	$	261		$	234		$	559

 

(1)

Includes earnings of $300 million for the three- and six-month periods ended June 30, 2009 related to the Global Settlement. See Note 4.

(2)

Includes losses from discontinued operations of $7 million and $1 million for the three months ended June 30, 2009 and 2008, respectively, and $4 million and $6 million for the six months ended June 30, 2009 and 2008, respectively.

(3)

Includes losses of $617 million and $628 million for the three- and six-month periods ended June 30, 2009, respectively, related to termination of Edison Capital's cross-border leases and the federal and state impacts of Global Settlement on Edison Capital. See Notes 4 and Note 14.

(4)

Includes amounts from other EMG subsidiaries that are not significant as a reportable segment.

(5)

Includes earnings of $50 million for both the three- and six-month periods ended June 30, 2009 related to the Global Settlement. See Note 4.

(6)

Includes amounts from Edison International (parent), and other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.

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Note 14. Investments in Leveraged Leases, Partnerships and Unconsolidated Subsidiaries

Leveraged Leases

As of June 30, 2009, Edison Capital was the lessor in various power generation aircraft leveraged leases. Pursuant to an agreement with the Internal Revenue Service, Edison Capital terminated its interests in cross-border leases during the first half of 2009 (see "Global Settlement" in Note 4 for further discussion.) The net proceeds and loss, before income tax, from termination of the cross-border leases were $1.385 billion and $920 million, respectively. The after-tax loss on termination of the cross-border leases, as well as the federal and state income tax impact of the Global Settlement, was $628 million. In addition, Edison Capital sold its interest in another leverage lease transaction, Midland Cogeneration Ventures, during the three months ended June 30, 2009 and recorded a pre-tax gain on sale of $33 million, $20 million after tax.

Each of Edison Capital's leveraged lease transactions was completed and accounted for in accordance with SFAS No. 13, "Accounting for Leases." All operating, maintenance, insurance and decommissioning costs are the responsibility of the lessees. The acquisition costs of these facilities were $609 million and $6.2 billion at June 30, 2009 and December 31, 2008, respectively. The equity investment in these facilities is generally 20% of the cost to acquire the facilities. The balance of the acquisition costs was funded by nonrecourse debt ($255 million as of June 30, 2009) secured by first liens on the leased property. The lenders do not have recourse to Edison Capital in the event of loan default.

The net investment in leveraged leases is:

In millions		June 30, 2009			December 31, 2008
		(Unaudited)
Rental receivables – net		$	189		$	3,227
Estimated residual value			21			42
Unearned income			(44	)		(802	)
Investments in leveraged leases		$	166		$	2,467
Deferred income taxes			(155	)		(2,313	)
Net investments in leveraged leases		$	11		$	154

Note 15. Subsequent Events

On March 12, 2009, the CPUC issued a final decision in SCE's 2009 GRC, authorizing the transfer of the assets and liabilities of Mountainview Power Company, LLC, a subsidiary of SCE, to SCE. SCE received FERC and other necessary approvals, and on July 1, 2009, terminated the FERC-approved power-purchase agreement between Mountainview Power Company, LLC and SCE, and transferred assets and liabilities valued at $705 million and $173 million, respectively. In addition, SCE recognized a one time, non-cash, accounting gain of approximately $46 million resulting from the establishment of regulatory assets to recognize differences in the accounting treatment for non-regulated and rate-regulated entities mainly related to equity AFUDC. There was no economic impact to customers from this change as compared to the FERC-approved power-purchase agreement; as these amounts would have been recognized over the life of that agreement and have no impact on cash flows.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

This MD&A for the three- and six-month periods ended June 30, 2009 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2008, and as compared to the three- and six month periods ended June 30, 2008. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2008 (the year-ended 2008 MD&A), which was included in Edison International's 2008 annual report to shareholders and incorporated by reference into Edison International's Annual Report on Form 10-K for the year ended December 31, 2008, filed with the Securities and Exchange Commission.

This MD&A contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International's current expectations and projections about future events based on Edison International's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by Edison International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact Edison International or its subsidiaries, include, but are not limited to:

•

the cost of capital and the ability to borrow funds and access to capital markets on reasonable terms, particularly in light of current credit conditions in the capital markets;

•

the effect of current economic conditions on the availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;

•

the ability to procure sufficient resources to meet expected customer needs in the event of significant counterparty defaults under power-purchase agreements;

•

changes in the fair value of investments and other assets;

•

the ability of Edison International to meet its financial obligations and to pay dividends on its common stock;

•

the ability of SCE to recover its costs in a timely manner from its customers through regulated rates;

•

decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions;

•

market risks affecting SCE's energy procurement activities;

•

changes in interest rates, rates of inflation including those rates which may be adjusted by public utility regulators, and foreign exchange rates;

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•

governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by ISOs and regional transmission organizations;

•

environmental laws and regulations, both at the state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business;

•

risks associated with operating nuclear and other power generating facilities, including operating risks, nuclear fuel storage, equipment failure, availability, heat rate, output, availability and cost of spare parts, and cost of repairs and retrofits;

•

the cost and availability of labor, equipment and materials;

•

the ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance;

•

effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;

•

creditworthiness of suppliers and other project participants and their ability to deliver goods and services under their contractual obligations to EME and its subsidiaries or to pay damages if they fail to fulfill those obligations;

•

the outcome of disputes with the IRS and other tax authorities regarding tax positions taken by Edison International;

•

the continued participation of Edison International's subsidiaries in tax-allocation and payment agreements;

•

supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which EME's generating units have access;

•

the cost and availability of coal, natural gas, fuel oil, nuclear fuel, and associated transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;

•

the cost and availability of emission credits or allowances for emission credits;

•

transmission congestion in and to each market area and the resulting differences in prices between delivery points;

•

the ability to provide sufficient collateral in support of hedging activities and purchased power and fuel;

•

the risk of counterparty default in hedging transactions or power-purchase and fuel contracts;

•

the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities and technologies;

•

the difficulty of predicting wholesale prices, transmission congestion, energy demand and other aspects of the complex and volatile markets in which EMG and its subsidiaries participate;

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•

general political, economic and business conditions;

•

weather conditions, natural disasters and other unforeseen events; and

•

the risks inherent in the development of generation projects as well as transmission and distribution infrastructure replacement and expansion including those related to siting, financing, construction, permitting, and governmental approvals.

Additional information about risks and uncertainties, including more detail about the factors described above, are discussed throughout this MD&A and in the "Risk Factors" section included in Part I, Item 1A of Edison International's Annual Report on Form 10-K. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International's business. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the Securities & Exchange Commission.

In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison International (parent) or parent company mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.

This MD&A is presented in 10 major sections. The company-by-company discussion of SCE, EMG, and Edison International (parent) includes discussions of liquidity, market risk exposures, and other matters (as relevant to each principal business segment). The remaining sections discuss Edison International on a consolidated basis. The consolidated sections should be read in conjunction with the discussion of each company's section.

		PAGE
Edison International: Management Overview			52
Southern California Edison Company			58
Edison Mission Group Inc.			66
Edison International (Parent)			87
Results of Operations			89
Historical Cash Flow Analysis			106
New Accounting Pronouncements			108
Commitments, Guarantees and Indemnities			108
Off-Balance Sheet Transactions			110
Other Developments			110

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EDISON INTERNATIONAL: MANAGEMENT OVERVIEW

Introduction

Edison International is a holding company whose principal operating subsidiaries are SCE, a rate-regulated electric utility, and EMG, the holding company of Edison International's competitive power generation (EME) and financial services (Edison Capital) segments. EME is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities, and Edison Capital provides capital and financial services, with no plans to make new investments.

Areas of Business Focus

Federal and State Income Taxes

Global Settlement

As previously disclosed, Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolves federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002. Pursuant to the Global Settlement, Edison Capital terminated its interests in the cross-border leases and received net proceeds of $1.385 billion, including $121 million in the first quarter of 2009. See "Off-Balance Sheet Transactions—Leveraged Leases" for further discussion of the termination of the cross-border leases.

The Global Settlement and termination of the Edison Capital cross-border leases resulted in the following impacts:

•

Edison International recorded a consolidated after-tax earnings charge of $274 million through the second quarter of 2009 ($11 million of which was recorded in the first quarter of 2009) and expects that the Global Settlement together with the termination of the Edison Capital cross-border leases will result in a positive cash impact over time of approximately $380 million. The cash impacts of the Global Settlement will occur over the next few years. See "Edison International (parent)—Liquidity—Intercompany Tax-Allocation Agreement" for further discussion of cash flows.

•

The Global Settlement and related lease terminations resulted in a loss of $628 million, after tax, for Edison Capital through the second quarter of 2009, reflected in "Lease termination and other" ($920 million pre-tax), and "Income tax expense (benefit)" on the consolidated statements of income (loss). Edison Capital's overall net cash outflow from the Global Settlement will be approximately $300 million over time.

•

The Global Settlement also resolves all of SCE's federal income tax disputes and affirmative claims through tax year 2002. During the second quarter of 2009, SCE recorded after-tax earnings of $300 million reflected in "Income tax expense (benefit)" on the consolidated statements of income (loss) primarily related to settlement of two affirmative claims associated with the taxation of balancing account overcollections and taxation of proceeds received in consideration for transferring control of SCE's transmission and distribution system to the ISO as part of California's deregulation process. Both claims created tax timing differences that resulted in an interest refund from the IRS for prior period tax overpayments, but did not result in a permanent reduction in Edison International's and SCE's federal income tax liability. SCE expects an overall positive cash impact resulting from the Global Settlement of approximately $640 million over time, including the cash benefit of prior tax deposits of approximately $200 million.

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•

On a combined basis, all other federal tax disputes involving the Edison International consolidated group for tax years 1986 - 2002 resulted in after-tax earnings of $54 million and expected positive cash flow over time of approximately $40 million. The earnings are attributable to miscellaneous net income tax benefits arising from the Global Settlement.

As a consequence of the cross-border lease terminations and Global Settlement, Edison Capital may be required to pay outstanding medium-term loans in the amount of $92 million (at June 30, 2009) and purchase certain affordable housing projects for approximately $20 million (at June 30, 2009) under existing guarantees. Edison International does not expect such payments to have a material adverse impact on its results of operations, financial position, or cash flows.

Edison International is addressing the impacts of the Global Settlement with state tax authorities and is awaiting receipt of final interest calculations from the IRS. Resolution of such matters with such authorities may change the estimated cash and earnings impacts described above.

Commodity Prices

Continuation of the economic recession, among other factors, contributed to declines in electrical demand for Northern Illinois and PJM West Hub locations during the six months ended June 30, 2009. The electrical load, calculated from published data by PJM, for the Northern Illinois and PJM West Hub locations declined 6% and 4%, respectively, compared to the six months ended June 30, 2008. The decline in price of natural gas, which often serves as the marginal fuel source in the region, together with lower electrical demand have resulted in significantly lower energy prices. Furthermore, spot energy prices affecting the Illinois Plants were adversely impacted, particularly during some off-peak periods, by congestion affecting the Northern Illinois control area. The average 24-hour PJM market price for energy at the Northern Illinois Hub and the PJM West Hub declined to $30.08/MWh and $41.40/MWh, respectively, during the six months ended June 30, 2009 as compared to $52.42/MWh and $72.17/MWh, respectively, during the six months ended June 30, 2008. In the first six months ended June 30, 2009, Midwest Generation's and EME Homer City's average realized energy price per MWh were higher than the average 24-hour PJM market prices due to higher hedge prices. As reflected in the net income summary below, these factors had an adverse impact on the results of operations during the second quarter and six months ended June 30, 2009. Lower electrical load has also generally decreased congestion in the eastern power grid, thereby resulting in lower trading income in the second quarter and six months ended June 30, 2009.

Fluctuations in commodity prices and demand for electricity do not impact SCE's results of operations due to the recovery of purchased power costs in rates and the decoupling of electric sales from rates. As a result of lower commodity prices, SCE projects that it will recover its under-collected purchased power costs recorded in the ERRA balancing account without an increase in rates. See "SCE: Regulatory Developments—Current Regulatory Developments—Energy Resource Recovery Account Proceedings" in the year-ended 2008 MD&A.

Business Development and Capital Commitments

SCE

SCE's growth strategy includes improving reliability and expanding the capability of its distribution and transmission infrastructure, constructing and replacing generation assets, and deploying advanced metering infrastructure. SCE continues to implement its growth strategy and revised its 2009 – 2013 capital investment plan to be consistent with the revenue requirements authorized in its 2009 GRC

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final decision, as well as other CPUC and FERC proceedings. SCE's significant planned projects are as follows:

Transmission and Distribution Projects

•

Devers-Palo Verde 2 – A transmission project that, as modified, would install a high voltage (500 kV) transmission line from Romoland, California east to Blythe, California. SCE continues its efforts to obtain the regulatory approvals necessary to construct the DPV2 project. The California portion of the project is currently expected to be placed in service in 2013, subject to licensing and regulatory approvals. Over the period 2009 – 2013, SCE expects to spend $718 million for the project (excluding the previously proposed Arizona portion of the project). As originally proposed, the project would have continued the transmission line from Romoland to a new substation near Palo Verde, west of Phoenix, Arizona. However, the line will now terminate at the Colorado River switch yard east of Blythe rather than continuing into Arizona as originally proposed. SCE is continuing to evaluate its transmission needs in western Arizona, but does not currently intend to seek regulatory approval for the Arizona portion of the project. If SCE and the relevant regulatory agencies determine that construction of the Arizona portion is in the interest of California ratepayers, SCE will seek regulatory approvals for the appropriate transmission facilities in western Arizona at that time.

•

Tehachapi Transmission Project – An eleven segment project consisting of new and upgraded transmission lines and associated substations built primarily to enable the development of renewable energy generated primarily by wind farms in remote areas of eastern Kern County, California. Tehachapi segments one through three are under construction and are expected to be placed in service at various dates over the next two years. SCE continues to seek the necessary licensing permits for Tehachapi segments four through eleven, which are expected to be placed in service between 2011 and 2013, subject to receipt of licensing and regulatory approvals. SCE expects to spend $2.1 billion over the period 2009 – 2013 on this project.

•

Rancho Vista Substation Project – A new 500 kV substation in the City of Rancho Cucamonga was completed and placed in service in May 2009. The total construction cost of the project from inception to completion was approximately $200 million.

•

Other capital investments consisting of $3.4 billion for transmission development and $9.7 billion for distribution projects to improve reliability and expand capability of its infrastructure over the period 2009 – 2013.

Generation Projects

•

San Onofre Steam Generator Replacement Project – Recently, SCE took delivery of the first two of four steam generators which are expected to be placed in service in the fourth quarter of 2009. The project is intended to enable San Onofre to operate until the end of its initial license period in 2022, and beyond if license renewal proves feasible. SCE expects to spend $457 million over the period 2009 – 2011.

•

Solar Photovoltaic Program – In June 2009, the CPUC issued a final decision approving a program to develop up to 250 MW of utility-owned Solar Photovoltaic generating facilities (generally ranging in size from 1 to 2 MW each) on commercial and industrial rooftop and other space in SCE's service territory. SCE expects to spend $790 million over the period 2009 – 2013. See "SCE: Liquidity—Capital Expenditures—Solar Photovoltaic Program" for further discussion.

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Other Projects

•

EdisonSmartConnect™ – SCE's advanced metering project that will install state-of-the-art "smart" meters in approximately 5.3 million households and small businesses throughout its service territory. SCE expects to begin full deployment of meters in 2009, and anticipates completion of the deployment in 2012. SCE estimates capital costs of $1.2 billion over the period 2009 – 2012.

SCE's 2009 – 2013 revised total capital investment plan includes capital spending in the range of $16.8 billion to $20.4 billion. See "SCE: Liquidity—Capital Expenditures" for further discussion.

EMG

At June 30, 2009, EME had 1,085 MW of wind projects in service and one project (100 MW) under construction (completed in July 2009). EME's wind projects under construction are currently funded through internally generated funds and cash on hand. During the second quarter of 2009, a subsidiary of EME completed a $202 million project financing of EME's interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. For further discussion of this financing, see "EMG: Liquidity and Capital Resources—Wind Financing."

EME is continuing to preserve capital by focusing on a selective growth strategy, primarily on completion of projects under construction and development of sites for future renewable projects deploying current turbine commitments. EME has contracts for the purchase of 942 MW of new wind turbines with scheduled payment obligations of up to $596 million in 2009 and $242 million in 2010. A significant portion of turbine payments scheduled during the first half of 2009 were deferred by agreement with certain suppliers. EME has executed non-binding letter agreements with two of its vendors to provide vendor financing. EME and such vendors are in the process of negotiating definitive agreements based on the non-binding letter agreements, but there is no assurance that final binding agreements will be executed or executed on terms that conform to the letter agreements. If definitive agreements are executed substantially in accordance with the terms of the letter agreements, turbine commitments would be reduced to approximately $191 million in 2009, $229 million in 2010, and $210 million in 2011, and the remaining $206 million due based on specified conditions (expected during the time period of 2011 and 2014). These commitments would be further reduced during this period if a third turbine supplier agrees to provide vendor financing. Furthermore, EME can elect under the existing turbine supply agreement with this supplier to terminate the agreement for convenience which would further reduce turbine commitments to $9 million in 2009 and $49 million in 2010 (in such case, EME would write off approximately $90 million in previously made non-refundable deposits).

Subject to completion of definitive agreements discussed above, EME plans to use the wind turbines currently under contract to complete the Big Sky wind project. EME plans to defer construction expenditures for other new wind projects until financing becomes available, which may require power purchase agreements. EME continues to participate in requests for proposals issued by potential customers and negotiate with potential customers for which proposals have been short-listed, but there is no assurance that these power purchase agreements will be executed or executed in a timely manner. Furthermore, delays by customers in the award of new power purchase agreements would increase the time to complete development of new wind projects, thereby delaying EME's expectation on timing of new projects. If EME is unable to obtain power purchase agreements, complete development of wind projects, and obtain project financing on acceptable terms and conditions, it may terminate a portion of the turbines on order. Such an event would likely result in a material charge. EME plans to store turbines that are delivered until needed for construction of new wind projects.

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Environmental Developments

Environmental Compliance Plans and Costs

As discussed in the 2008 Annual Report on Form 10-K, Midwest Generation is subject to various commitments with respect to environmental compliance for the Illinois Plants under the CPS. During the second quarter of 2009, Midwest Generation conducted tests of selective non-catalytic NO_X removal technologies and reagent based SO₂ removal technologies that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has preliminarily concluded that installation of selective non-catalytic NO_X removal technologies, in lieu of selective catalytic removal technologies, should meet the NO_X portion of the CPS. Testing of the flue gas desulfurization technology based on injection of dry sodium sorbent demonstrated significant reductions in SO₂; however, further analysis and evaluation are required to determine the appropriate path forward to comply with the SO₂ portion of the CPS. These technologies may be deployed at the Illinois Plants in a manner which could optimize compliance, subject to approval of construction permits by the Illinois EPA. A decision regarding whether or not to proceed with the alternative compliance program, as described above, will occur following further analysis and evaluation of results. Under current conditions, Midwest Generation cannot predict what specific method will be used or all costs that will be incurred to comply with the CPS.

Climate Change Legislation

On June 26, 2009, the American Clean Energy and Security Act was passed by the U.S. House of Representatives. The bill would establish a 20% mandatory federal combined efficiency and renewable electricity standard for retail electricity suppliers like SCE and establish a cap-and-trade system for carbon emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate greenhouse gas emissions from all covered entities would be established and decline over time. Emitters of greenhouse gases would be required to have allowances for greenhouse gas emissions emitted during a relevant measurement period. The bill would provide for stated portions of required allowances to be allocated (including allocation to merchant generators) free of charge in declining amounts over time. Emitters of greenhouse gases would have to purchase the remainder of their required allowances in the open market, although a portion may be provided by so-called offset credits (for alternative greenhouse gas conservation efforts). Legislation to regulate greenhouse gas emissions is now being considered by the U.S. Senate, and the timing, content, and potential effects on Edison International of climate change legislation, if any, that may be ultimately passed by the Congress and signed into law by the President remain uncertain.

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Earnings Performance

The table below presents Edison International's earnings for the three-and six-month periods ended June 30, 2009 and 2008, and the relative contributions by its subsidiaries.

				Three Months Ended June 30,						Six Months Ended June 30,
In millions				2009			2008			2009			2008
Earnings (Loss) from Continuing Operations:
		SCE		$	499		$	157		$	707		$	307
		EMG			(551	)		112			(506	)		271
		Edison International (parent) and other			43			(7	)		37			(13	)
Edison International Earnings (Loss) from Continuing Operations				$	(9	)	$	262		$	238		$	565
Edison International (Loss) from Discontinued Operations					(7	)		(1	)		(4	)		(6	)
Edison International Net Income (Loss)				$	(16	)	$	261		$	234		$	559

Earnings (Loss) from Continuing Operations

SCE's earnings from continuing operations were $499 million and $707 million for the three- and six-month periods ended June 30, 2009, respectively, compared to $157 million and $307 million for the respective periods in 2008. SCE's quarter and year-to-date earnings in 2009 include the impact of the Global Settlement which resulted in after-tax earnings of $300 million related primarily to tax timing differences on certain affirmative claims (see "—Areas of Business Focus—Federal and State Income Taxes" for further discussion). The quarter and year-to-date increases also reflect higher operating income associated with the 2009 GRC decision and lower operating expense mainly due to timing differences.

EMG's losses from continuing operations were $551 million and $506 million for the three- and six-month periods ended June 30, 2009, respectively, compared to earnings of $112 million and $271 million for the respective periods in 2008. The quarter and year-to-date losses in 2009 include the impact of the Global Settlement and related lease terminations which resulted in an after-tax loss of $612 million and $624 million, respectively, primarily related to losses at Edison Capital of $617 million and $628 million, respectively, (see "—Areas of Business Focus—Federal and State Income Taxes" for further discussion). The quarter and year-to-date variances also reflect lower income from Midwest Generation and gas-fired projects driven by lower energy and natural gas prices, lower trading income and lower earnings from Edison Capital, partially offset by improved earnings at EME's Homer City plant. The quarter variance also reflects a gain on the sale of Edison Capital's Midland Cogeneration Ventures lease in 2009 and a gain on the sale of Edison Capital's Beaver Valley lease included in the second quarter 2008 results. The year-to-date variance also reflects a favorable buy-out of a coal contract at Midwest Generation in 2008.

Edison International (parent) and other earnings from continuing operations were $43 million and $37 million for the three- and six-month periods ended June 30, 2009, respectively, compared to losses of $7 million and $13 million for the respective periods in 2008. The after-tax earnings in 2009 were primarily due to the impact of the Global Settlement resulting from lower combined state deferred income taxes recorded by Edison International and its subsidiaries under their respective tax allocation agreements (see "—Areas of Business Focus—Federal and State Income Taxes" for further discussion).

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SOUTHERN CALIFORNIA EDISON COMPANY

SCE: REGULATORY MATTERS

Current Regulatory Developments

This section of the MD&A describes significant regulatory issues that may impact SCE's financial condition or results of operations.

2009 General Rate Case Proceeding

On March 12, 2009, the CPUC issued a final decision in SCE's 2009 GRC, authorizing a $4.83 billion base revenue requirement for 2009. The CPUC also authorized a methodology for calculating post-test year revenue requirements that would result in an approximate base revenue requirement of $5.04 billion in 2010 and $5.25 billion in 2011. In addition, the 2009 GRC decision establishes new balancing account regulatory treatment for SCE's medical, dental, and vision expenses, and its share of Palo Verde operation and maintenance expenses, and modifies SCE's existing pension and PBOP balancing accounts to allow annual recovery or refund of the recorded year-end balances. During the first quarter of 2009, SCE implemented the updated revenue requirement retroactive to January 1, 2009 consistent with the CPUC authorization. In addition, SCE has slightly revised its capital expenditure forecasts for the period 2009 – 2013. See "SCE: Liquidity—Capital Expenditures" for further discussion.

As discussed under the heading, "SCE: Regulatory Matters—Current Regulatory Developments—2009 General Rate Case Proceeding" in the year-ended 2008 MD&A, the final decision also granted the authority to transfer the assets and liabilities of Mountainview Power Company, LLC to SCE, which was subsequently approved by the FERC and transferred in July 2009. As a result of the transfer, SCE recognized a one time, non-cash, accounting gain of approximately $46 million in July 2009 to recognize differences in the accounting treatment for non-regulated and rate-regulated entities mainly related to equity AFUDC.

FERC Rate Cases

2009

On March 1, 2009, SCE implemented, subject to refund, proposed revisions to its base transmission rates initially accepted by the FERC. SCE and the parties to the FERC rate case reached a settlement on the 2009 base transmission rates and on July 1, 2009, SCE filed the proposed settlement. The settlement provides for a revenue requirement of $448 million, which increases SCE's revenue requirement by $136 million over the previously authorized base transmission revenue requirement. SCE expects that the FERC will issue an order approving the proposed settlement during the third quarter of 2009. If approved by the FERC, the proposed settlement rates will become retroactively effective as of March 1, 2009. As of June 30, 2009, SCE had collected revenue, subject to refund, of $21 million that, upon final approval of the settlement agreement, will be refunded to ratepayers. SCE did not recognize this refund in revenue and implementation of the settlement agreement will not impact earnings.

2010

On July 31, 2009, SCE filed proposed revisions to the 2009 base transmission rates (discussed above), which would increase SCE's revenue requirement by $107 million, or 24%, over the 2009 base transmission revenue requirement and requested an effective date of October 1, 2009. This proposed revenue requirement results in an approximate 1% increase to SCE's overall system average rate. The

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proposed increase is primarily due to an increase in transmission rate base, mainly associated with transmission projects already in service or expected to enter service in 2009 and 2010.

Cost of Capital Mechanism

As discussed in the year-ended 2008 MD&A, the CPUC determines SCE's cost of capital in a multi-year proceeding occurring every three years, with a provision that allows for a potential adjustment between the cost of capital filings if certain thresholds are reached. Under the current mechanism, the existing capital structure and authorized rate of return will remain in place through December 2010, absent any potential annual adjustment. The mechanism would be subject to CPUC review in 2010 for the cost of capital set for 2011 and beyond.

SCE expects to file with the CPUC a petition to modify the current mechanism that would forgo an expected 2010 cost of capital increase under the annual adjustment provision and extend SCE's current capital structure and authorized rate of return through 2012, subject to future potential adjustments. Absent CPUC approval of SCE's petition, SCE's next potential adjustment will be submitted to the CPUC in October 2009, effective for 2010.

SCE: LIQUIDITY

Overview

As of June 30, 2009, SCE had $3.26 billion of available liquidity made up of $457 million of cash and equivalents and short-term investments ($81 million of which was held by SCE's consolidated VIEs), as well as $2.8 billion remaining under credit facilities. The following table summarizes the status of SCE's credit facilities at June 30, 2009:

In millions		Credit Facilities(1)
Commitment		$	2,894
Outstanding borrowings			—
Outstanding letters of credit			(88	)
Amount available		$	2,806

(1)

SCE has two credit facilities with various banks. In June 2009, SCE amended the $2.5 billion five-year credit facility to remove a subsidiary of Lehman Brothers Holding as a lender which resulted in a reduction of the total commitment under the facility to $2.4 billion. In March 2008, SCE amended the five-year credit facility, extending the maturity to February 2013. The March 2008 amendment also provides four extension options which, if all exercised, and agreed to by lenders, will result in a final termination in February 2017. In March 2009, SCE entered into a new $500 million 364-day revolving credit facility terminating on March 16, 2010. SCE expects to use the additional liquidity provided by the facility to address potential requirements of SCE's ongoing procurement-related needs.

As of June 30, 2009, SCE's long-term debt, including current maturities of long-term debt, was $6.74 billion. In March 2009, SCE issued $500 million of 6.05% first and refunding mortgage bonds due in 2039 and $250 million of 4.15% first and refunding mortgage bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories.

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SCE's estimated cash outflows during the 12-month period following June 30, 2009 are expected to consist of:

•

Projected capital expenditures primarily to replace and expand distribution and transmission infrastructure and construct and replace major components of generation assets (see "—Capital Expenditures" below);

•

Fuel and procurement-related costs (see "SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings" in the year-ended 2008 MD&A), including collateral requirements (see "—Margin and Collateral Deposits");

•

In December 2008 and June 2009 the Board of Directors of SCE declared two $100 million dividends to Edison International which were paid in January 2009 and July 2009, respectively. Additional dividends by SCE are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings;

•

Principal and interest payments on short- and long-term debt outstanding;

•

General operating expenses; and

•

Pension and PBOP trust contributions.

As discussed above, SCE expects to meet its 2009 continuing obligations, including cash outflows for operating expenses and power-procurement, through cash and equivalents on hand, and operating cash flows. Projected 2009 capital expenditures are expected to be financed through cash and equivalents on hand, operating cash flows and incremental capital market financings. SCE expects that it would also be able to draw on the remaining availability of its credit facilities and access capital markets if additional funding and liquidity is necessary to meet the estimated operating and capital requirements, but given uncertain market conditions there can be no assurance of capital market availability.

On February 17, 2009, President Obama signed the American Recovery and Reinvestment Act of 2009 which extended the availability of accelerated bonus depreciation through the end of 2009. Edison International expects that certain capital expenditures incurred by SCE during 2009 will qualify for this accelerated bonus depreciation, which would provide additional 2009 cash flow benefits estimated to be in the range of approximately $125 million to $175 million.

SCE's liquidity may be affected by, among other things, matters described in "SCE: Regulatory Matters" and "Commitments, Guarantees and Indemnities."

Capital Expenditures

SCE's capital investment plan projects total capital expenditures for the period 2009 – 2013 to be in the range of $16.8 billion to $20.4 billion. The 2009 – 2011 planned capital expenditures for CPUC-jurisdictional projects are consistent with the revenue requirements authorized in SCE's 2009 GRC. Recovery of planned capital expenditures for CPUC-jurisdictional projects beyond 2011 is subject to the outcome of future CPUC general rate cases or other CPUC approvals. Recovery of certain projects included in the 2009 – 2013 capital investment plan have been approved or will be requested through other CPUC-authorized mechanisms on a project-by-project basis. These projects include, among others, SCE's Solar Photovoltaic Program (based on the decision discussed below) and SCE's EdisonSmartConnect™ project. Recovery of 2009 planned capital expenditures for FERC-jurisdictional projects is subject to FERC approval in SCE's pending 2009 Rate Case (see "SCE: Regulatory

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Matters—Current Regulatory Developments—FERC Rate Cases" above for further information). Recovery of planned capital expenditures for FERC-jurisdictional projects beyond 2009 is subject to future FERC approval.

Execution of SCE's capital investment plan is dependent on access to capital markets, regulatory decisions, and economic conditions in the U.S. The completion of the projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, weather and other unforeseen conditions.

SCE capital expenditures (including accruals) related to its 2009 capital plan were $1.15 billion for the first six months of 2009. SCE's capital expenditures for the first six months of 2009 were approximately 22% less than forecast, primarily due to timing delays including the delay in the 2009 GRC decision. The estimated capital expenditures for the next five years may vary from SCE's current forecast. If SCE assumes the same level of variability to forecast experienced in 2008 (approximately 18%), the estimated capital expenditures for the next five years would vary in the range of: 2009 – $2.7 billion to $3.3 billion; 2010 – $3.2 billion to $3.9 billion; 2011 – $3.5 billion to $4.3 billion; 2012 – $3.7 billion to $4.5 billion; and 2013 – $3.6 billion to $4.4 billion.

Solar Photovoltaic Program

In June 2009, the CPUC issued a final decision approving SCE's 250 MW Solar Photovoltaic Program, which allows recovery of costs through rates provided the costs are reasonable. The final decision provided that SCE would earn its CPUC-authorized rate of return on this investment. The final decision also ordered SCE to solicit power purchase agreements from independent power producers for an additional 250 MW of rooftop solar photovoltaic power.

Credit Ratings

SCE's credit ratings are as follows:

		Moody's Rating			S&P Rating			Fitch Rating
Long-term senior secured debt			A1			A			A+
Short-term (commercial paper)			P-2			A-2			F-1

On July 2, 2009 and July 13, 2009, Fitch and S&P affirmed SCE's credit ratings, respectively. In addition, on July 8, 2009, Moody's issued a credit opinion with no change to its previously issued credit ratings for SCE. Subsequently, on August 3, 2009, Moody's upgraded most senior secured ratings of investment-grade regulated utilities by one notch. As a result, SCE's long-term senior secured debt was upgraded to A1 from A2. SCE cannot provide assurance that its current credit ratings will remain in effect for any given period of time or that one or more of these ratings will not be changed. These credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

Dividend Restrictions and Debt Covenants

The CPUC regulates SCE's capital structure and 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 June 30, 2009, SCE's 13-month

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weighted-average common equity component of total capitalization was 49.6% resulting in the capacity to pay $225 million in additional dividends.

SCE has a debt covenant in its credit facility that requires a debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At June 30, 2009, SCE's debt to total capitalization ratio was 0.46 to 1.

Margin and Collateral Deposits

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. Collateral requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments, and other factors. Future collateral requirements may be higher (or lower) than requirements at June 30, 2009, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.

Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral. The table below illustrates the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of June 30, 2009.

In millions
Collateral posted as of June 30, 2009(1)		$	188
Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade			220
Total posted and potential collateral requirements(2)		$	408

(1)

Collateral posted consisted of $67 million which was offset against derivative liabilities in accordance with the implementation of FIN 39-1, and $121 million provided to counterparties and other brokers (consisting of $33 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $88 million in letters of credit).

(2)

Total posted and potential collateral requirements may increase by an additional $59 million, based on SCE's forward position as of June 30, 2009, due to adverse market price movements over the remaining life of the existing contracts using a 95% confidence level.

In the table above less than $1 million of collateral posted as of June 30, 2009 related to derivative liabilities, and $32 million of incremental collateral requirements related to derivative liabilities.

SCE's incremental collateral requirements are expected to be met from liquidity available from cash on hand and available capacity under SCE's credit facilities, discussed above.

SCE: MARKET RISK EXPOSURES

SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative financial instruments, as appropriate, to manage its market risks.

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Commodity Price Risk

Introduction

As discussed in the year-ended 2008 MD&A, SCE is exposed to commodity price risk from its purchases of capacity and ancillary services to meet peak energy requirements and from exposure to natural gas prices that affect costs associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including SCE's Mountainview and peaker plants.

Natural Gas and Electricity Price Risk

As discussed in the year-ended 2008 MD&A, SCE has an active hedging program in place to minimize ratepayer exposure to variability in market prices; however, to the extent that SCE does not mitigate the exposure to commodity price risk, the unhedged portion is subject to the risks and benefits of spot-market price movements, which are ultimately passed-through to ratepayers.

The following table summarizes the fair values of outstanding derivative financial instruments used at SCE to mitigate its exposure to spot market prices:

		June 30, 2009						December 31, 2008
In millions		Assets			Liabilities			Assets			Liabilities
Electricity options, swaps and forward arrangements		$	11		$	27		$	7		$	15
Natural gas options, swaps and forward arrangements			70			280			80			304
Congestion revenue rights and firm transmission rights(1)			455			—			81			—
Tolling arrangements(2)			86			418			63			647
Netting and collateral			(1	)		(68	)		—			(72	)
Total		$	621		$	657		$	231		$	894

(1)

In September 2007 and November 2008, the CAISO allocated CRRs for the period April 2009 through December 2017 based on SCE's load requirements. In addition, SCE participated in CAISO auctions for the procurement of additional CRRs. The CRRs meet the definition of a derivative under SFAS No. 133.

(2)

In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new Southern California generating resources. SCE has entered into a number of contracts, of which five received regulatory approval in the fourth quarter of 2008 and are recorded as derivative instruments. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives. See "Other Developments—Environmental Matters—Priority Reserve Legal Challenges" in the year-ended 2008 MD&A.

SCE recognizes realized gains and losses on derivative instruments as purchased power expense and recovers these costs from ratepayers. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased power expense until realized. As a result, realized and unrealized gains and losses do not affect earnings, but may temporarily affect cash flows. Realized losses on economic hedging activities were $96 million and $194 million for the three- and six-month periods ended June 30, 2009, respectively, compared to realized gains on economic hedging activities of $28 million and $26 million for the comparable periods in 2008, respectively. Changes in realized gains and losses on economic hedging activities were primarily due to significant decreases in

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settled natural gas prices. Unrealized gains on economic hedging activities were $293 million and $626 million for the three- and six-month periods ended June 30, 2009, respectively, compared to $333 million and $486 million for the comparable periods in 2008, respectively. Changes in unrealized gains and losses on economic hedging activities were primarily related to the recognition of the long-term portion of CRRs recorded in the first quarter of 2009 as well as decreases in forward natural gas prices in 2009 compared to 2008.

SCE adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements. For further discussion of SCE's adoption of SFAS No. 157, see "Edison International Notes to Consolidated Financial Statements—Note 10. Fair Value Measurements."

Market Redesign and Technology Upgrade

The MRTU market became effective on March 31, 2009 and SCE began participating in the day-ahead and real-time markets for the sale of its generation and purchases of its load requirements. See "SCE: Market Risk Exposures—Commodity Price Risk—Market Redesign and Technology Upgrade" in the year-ended 2008 MD&A for a further description of these markets.

Interest Rate Risk

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity purposes, to fund business operations and to finance capital expenditures. The nature and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. At June 30, 2009, the fair market value of SCE's long-term debt (including long-term debt due within one year) was $7.1 billion, compared to a carrying value of $6.7 billion.

Credit Risk

As discussed in the year-ended 2008 MD&A, as part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments.

The credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the balance sheet. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements.

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At June 30, 2009, the amount of balance sheet exposure as described above, broken down by the credit ratings of SCE's counterparties, was as follows:

		June 30, 2009
In millions		Exposure(2)			Collateral			Net Exposure
S&P Credit Rating(1)
A or higher		$	89		$	(4	)	$	85
A-			456			—			456
BBB+			1			—			1
BBB			—			—			—
BBB-			—			—			—
Below investment grade and not rated			1			(2	)		(1	)
Total		$	547		$	(6	)	$	541

(1)

SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.

(2)

Exposure excludes amounts related to contracts classified as normal purchase and sales and non- derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related net accounts receivable.

The credit risk exposure set forth in the above table is comprised of $4 million of net account receivables and $543 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

Due to recent developments in the financial markets, the credit ratings may not be reflective of the related credit risk. The CAISO comprises 84% of the total net exposure above and is mainly related to the CRRs' fair value (see "—Commodity Price Risk" for further information).

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EDISON MISSION GROUP

EMG: LIQUIDITY

Liquidity

At June 30, 2009, EMG and its subsidiaries had cash and cash equivalents and short-term investments of $1.67 billion, excluding approximately $542 million at Edison Capital which is expected to be used to meet tax, debt and other obligations of this business segment. EMG's subsidiaries had a total of $110 million of available borrowing capacity under their credit facilities. EME had a total of $88 million of available borrowing capacity under its $600 million corporate credit facility, and Midwest Generation had a total of $22 million of available borrowing capacity under its $500 million working capital facility. EMG's consolidated debt at June 30, 2009 was $4.9 billion, of which $132 million was current. In addition, EME's subsidiaries had $3.4 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 26 years.

The following table summarizes the status of the EME and Midwest Generation credit facilities at June 30, 2009:

In millions		EME			Midwest Generation
Commitment		$	600		$	500
Less: Commitment from Lehman Brothers subsidiary			(36	)		—
			564			500
Outstanding borrowings			(351	)		(475	)
Outstanding letters of credit			(125	)		(3	)
Amount available		$	88		$	22

On September 15, 2008, Lehman Brothers Holdings filed for protection under Chapter 11 of the U.S. Bankruptcy Code. A subsidiary of Lehman Brothers Holdings, Lehman Commercial Paper Inc., a lender in EME's credit agreement representing a commitment of $36 million, in September 2008 declined requests for funding under that agreement and in October 2008, filed for bankruptcy protection.

As a result of the recent credit ratings actions described under "—Credit Ratings," the margins applicable to EME's $600 million corporate credit facility and Midwest Generation's $500 million working capital facility increased. The applicable margin on borrowings outstanding under EME's credit facility was increased by 50 basis points to 2%. The interest rate on borrowings outstanding under Midwest Generation's credit facility is LIBOR plus 0.875%, except if average utilized commitments during a period exceed $250 million, in which case the margin increases to 1%, which was the case at June 30, 2009. This represents an increase in the applicable margin, assuming utilization exceeds $250 million, of 35 basis points due to the recent credit ratings actions.

Access to the capital markets remains uncertain due to the financial market and economic conditions discussed in "Edison International: Management Overview—Areas of Business Focus—Commodity Prices" and also in "Edison International: Management Overview—Areas of Business Focus—Financial Markets and Economic Conditions" in the year-ended 2008 MD&A, though very preliminary signs of improvement are beginning to show as evidenced by EME's successful closing of the $202 million non-recourse wind portfolio financing at the end of the second quarter of 2009. Accordingly, EME's liquidity is currently comprised of cash on hand and cash flow generated from operations. Pending full recovery of the capital markets, EME intends to preserve capital by focusing on a selective growth

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strategy, primarily on completion of projects under construction and development of sites for future renewable projects deploying current turbine commitments, and using its cash on hand and future cash flow to meet its existing contractual commitments. Long-term disruption in the capital markets could adversely affect EME's business plans and financial position.

Capital Expenditures

At June 30, 2009, the estimated capital expenditures through 2011 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

In millions			July through December 2009			2010			2011
Illinois Plants
	Plant capital expenditures		$	35		$	96		$	62
	Environmental expenditures			9			(1)			(1)
Homer City Facilities
	Plant capital expenditures			13			55			29
	Environmental expenditures			—			15			32
New Projects
	Projects under construction			55			—			—
	Turbine commitments(2)			596			242			—
Other capital expenditures				17			9			7
Total			$	725		$	417		$	130

(1)

See discussion below regarding capital expenditures for environmental improvements at the Illinois Plants.

(2)

See "Edison International: Management Overview—Areas of Business Focus—Business Development and Capital Commitments—EMG" for discussion of potential changes to EME's turbine commitments.

Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, mill steam inerting projects, generator stator rewinds, 4Kv switchgear and main power transformer replacement.

Midwest Generation is subject to various commitments with respect to environmental compliance. Midwest Generation continues to review all technology and unit shutdown combinations, including interim and alternative compliance solutions. For more information on the current status of environmental improvements in Illinois, see "Edison International: Management Overview—Areas of Business Focus—Environmental Developments—Environmental Compliance Plans and Costs." For further discussion of environmental regulations, refer to "Other Developments—Environmental Matters" in the year-ended 2008 MD&A.

Expenditures for New Projects

At June 30, 2009, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 942 MW. The turbine commitments generally represent approximately two-thirds of the total capital costs of EME's wind projects. As of June 30, 2009, EME had a development pipeline of potential wind projects with projected installed capacity of

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approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development of a wind project may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits and agreements necessary to support an investment. There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed, or that EME will be able to successfully develop projects utilizing all of its turbine commitments. For further discussion, see "Edison International: Management Overview—Business Development and Capital Commitments—EMG."

Big Sky Wind Project

The Big Sky wind project is a 240 MW planned wind project in Illinois. EME has commenced pre-construction activities for equipment purchases, site development and interconnection activities (approximately $100 million capitalized at June 30, 2009). EME plans to use wind turbines currently under contract to complete the Big Sky wind project. The costs to complete the project, including construction and turbine transportation and installation, are expected to be approximately $165 million. This estimate excludes the turbine costs set forth as turbine commitments in the table above and costs incurred to date. Upon completion, the project plans to sell electricity into the PJM market as a merchant generator or to third-party customers under power sales contracts.

Walnut Creek Project

Walnut Creek Energy, a subsidiary of EME, was awarded by SCE, through a competitive bidding process, a ten-year power sales contract starting in 2013 for the output of the Walnut Creek project. In July 2008, the Los Angeles Superior Court found that actions taken by the SCAQMD, in promulgating rules that had made available a "Priority Reserve" of emissions credits for new power generation projects, did not satisfy California environmental laws. In November 2008, the Los Angeles Superior Court enjoined the SCAQMD from issuing Priority Reserve emission credits to any facility, including new power projects, until a satisfactory environmental analysis is completed. Legal challenges related to the Priority Reserve emission credits are continuing. In the air basins regulated by SCAQMD, the need for particulate matter (PM10) and SO₂ emission credits exceeds available supply, and it is difficult to create new qualifying credits. Walnut Creek will be unable to begin construction until the legal challenges to the Priority Reserve emission credits have been favorably resolved or another source of credits for the project has been identified. The capital costs to construct this project, excluding interest, are estimated in the range of $500 million to $600 million.

Credit Ratings

Overview

Credit ratings for EMG's direct and indirect subsidiaries are as follows:

		Moody's Rating		S&P Rating		Fitch Rating
EME(1)		B2		B		BB-
Midwest Generation(2)		Ba1		BB-		BBB-
EMMT		Not Rated		B		Not Rated
Edison Capital (Edison Funding)		Ba3		BB+		Not Rated

(1)

Senior unsecured rating.

(2)

First priority senior secured rating.

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On July 13, 2009, S&P lowered the credit ratings of EME, Midwest Generation and EMMT from BB- to B, BB+ to BB-, and BB- to B, respectively. On June 30, 2009, Moody's lowered the credit ratings of EME and Midwest Generation from B1 to B2 and Baa3 to Ba1, respectively. The S&P ratings remain on negative outlook, while the Moody's rating outlook is stable. In addition, on July 2, 2009, Fitch placed the credit ratings for EME and Midwest Generation on Rating Watch Negative.

On June 30, 2009, Moody's lowered the credit rating of Edison Capital (Edison Funding) from Ba1 to Ba3. The outlook is now stable. On May 11, 2009, S&P revised Edison Capital's (Edison Funding) rating outlook to stable from negative.

EMG cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EMG notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency. EME does not have any "rating triggers" contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. Furthermore, EME's senior notes do not contain any cross-defaults to subsidiary financings. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. For discussions of contingent features related to energy contracts, see "—Margin, Collateral Deposits and Other Credit Support for Energy Contracts."

Credit Rating of EMMT

The Homer City sale-leaseback documents restrict EME Homer City's ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from S&P or Moody's or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME's internal credit scoring procedures. These documents also include a requirement that EME Homer City's counterparty to such transactions, whether it is EMMT or another party, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and EME Homer City is not rated. In order to continue to sell forward the output of the Homer City facilities through EMMT, either: (1) a consent from the sale-leaseback owner participant must be obtained; or (2) EMMT must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participants that allows EME Homer City to enter into such sales, under specified conditions, through March 1, 2014. EME Homer City continues to be in compliance with the terms of the consent; however, because EMMT's credit rating has dropped below BB-, the consent is revocable by the sale-leaseback owner participant at any time. The sale-leaseback owner participants have not indicated that they intend to revoke the consent; however, there can be no assurance that they will not do so in the future. An additional consequence of EMMT's lowered credit rating is that outstanding accounts receivable between EMMT and EME Homer City have been reduced to zero, as required under the terms of the consent. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. For further discussion, see "EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities."

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Margin, Collateral Deposits and Other Credit Support for Energy Contracts

To reduce its exposure to market risk, EME hedges a portion of its electricity price exposure through EMMT, an EME subsidiary engaged in the power marketing and trading business. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities; however, because the credit ratings of EMMT and EME are below investment grade, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. At June 30, 2009, EMMT had deposited $47 million in cash with clearing brokers in support of futures contracts and had deposited $53 million in cash with counterparties in support of forward energy and congestion contracts. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $46 million at June 30, 2009. In addition, EME had received cash collateral of $275 million at June 30, 2009, to support credit risk of counterparties under margin agreements; $188 million of which is classified as restricted cash. The liability for margin deposits received from counterparties has been offset against net derivative assets.

Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2009, if wholesale energy prices or the amount hedged changes. EME estimates that margin and collateral requirements for energy and congestion contracts outstanding as of June 30, 2009 could increase by approximately $85 million over the remaining life of the contracts using a 95% confidence level. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—Dividend Restrictions in Major Financings." Furthermore, the hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EME or Midwest Generation to comply with these provisions would result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position on June 30, 2009 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.

Midwest Generation has cash on hand to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois Plants. In addition, EME has cash on hand to provide credit support to subsidiaries. For discussion on available borrowing capacity under Midwest Generation and EME credit facilities, see "—EME's Liquidity."

EME's Credit Facility Financial Ratios

EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-corporate-capital ratio as such terms are defined in the credit facility. The following details of EME's interest coverage ratio and a maximum corporate-debt-to-corporate-capital ratio are provided as an aid to understanding the components of the computations as defined in the credit facility. This information is not intended to measure the financial performance of EME and, accordingly, should not be used in lieu of the financial information set forth in EME's consolidated financial statements.

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The following table sets forth the major components of the interest coverage ratio for the 12 months ended June 30, 2009 and December 31, 2008:

			12 Months Ended
In millions			June 30, 2009			December 31, 2008
Funds Flow Available for Interest
Distributions:
	Midwest Generation		$	290		$	206
	EME Homer City			80			110
	Big 4 Projects(1)			107			114
	Viento Funding II(2)			164			—
	Other projects			60			55
Tax payments received from subsidiaries				230			364
Realized trading income				78			175
Tax allocation receipts (payments)				31			(92	)
Operating expenses				(153	)		(155	)
Other items, net				(15	)		(14	)
			$	872		$	763
Net Interest Expense:
EME corporate debt			$	261		$	248
Addback: Capitalized interest				24			32
Powerton-Joliet intercompany notes				112			112
EME interest income				(4	)		(6	)
			$	393		$	386
Ratio				2.22			1.98
Covenant threshold (not less than)				1.20			1.20

(1)

Prior to the repayment of the Series B bonds of EME Funding Corp. in September 2008, distributions from the Big 4 projects represented funds transferred to EME after meeting debt service and restricted cash provisions set forth in this financing.

(2)

In June 2009, a subsidiary of EME, Viento Funding II, Inc., completed a non-recourse portfolio financing of EME's interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. For further details of this financing, see "—Wind Financing." The proceeds of the financing, net of financing costs, were distributed to EME.

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The following table sets forth the major components of the corporate-debt-to-corporate-capital ratio at June 30, 2009 and December 31, 2008:

In millions			June 30, 2009			December 31, 2008
Corporate Debt
Indebtedness for money borrowed			$	4,526		$	4,564
Powerton-Joliet termination value				1,106			1,163
Letters of credit				128			132
			$	5,760		$	5,859
Corporate Capital
Common shareholder's equity			$	2,811		$	2,684
Less:
	Non-cash cumulative changes in accounting			1			1
	Accumulated other comprehensive income			(230	)		(200	)
Adjustments:
	After-tax losses incurred on termination of Collins lease			587			587
	Dividend to MEHC for repayment of 13.5% notes			899			899
			$	4,068		$	3,971
Corporate debt				5,760			5,859
			$	9,828		$	9,830
Corporate-debt-to-corporate-capital ratio				0.59			0.60
Covenant threshold (not more than)				0.75			0.75

Dividend Restrictions in Major Financings

General

Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME's subsidiaries are not available to satisfy EME's obligations or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies.

EME's corporate credit agreement contains covenants that restrict its ability and the ability of several of its subsidiaries to make distributions. This restriction binds the subsidiaries that own interests in the Westside projects, the Sunrise project, the Illinois Plants, the Homer City facilities and the Big 4 projects. These subsidiaries would not be able to make a distribution to EME's shareholder if an event of default were to occur and be continuing under EME's secured credit agreement after giving effect to the distribution.

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Key Ratios of EMG's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at June 30, 2009 or for the twelve months ended June 30, 2009:

Subsidiary		Financial Ratio		Covenant		Actual
Midwest Generation (Illinois Plants)		Debt to Capitalization Ratio		Less than or equal to 0.60 to 1			0.27 to 1
EME Homer City (Homer City facilities)		Senior Rent Service Coverage Ratio		Greater than 1.7 to 1			2.57 to 1

For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Dividend Restrictions in Major Financings" in the year-ended 2008 MD&A.

Edison Capital's principal subsidiary, Edison Funding Company, is required by covenants in its financial instruments to maintain a specified minimum net worth. The minimum net worth covenants range from $130 million to $160 million. Edison Funding did not satisfy these minimum net worth requirements as of June 30, 2009 due to a $628 million loss on termination of its interests in the cross border leases, the settlement of prior years federal income taxes and related tax adjustments. See "Edison International: Management Overview—Areas of Business Focus—Federal and State Income Taxes" for further discussion. As a consequence of not satisfying the minimum net worth covenants, Edison Funding Company may be required to pay outstanding medium-term loans in the amount of $92 million (at June 30, 2009) and purchase certain affordable housing projects for approximately $20 million at June 30, 2009 under existing guarantees. Edison International does not expect such payments to have a material adverse impact on its results of operations, financial position, or cash flows.

EME's Senior Notes and Guaranty of Powerton-Joliet Leases

EME is restricted from the sale or disposition of assets, which includes the making of a distribution, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding such sale or disposition. At June 30, 2009, the maximum sale or disposition of EME assets is determined as follows:

In millions				June 30, 2009
Consolidated Net Tangible Assets
	Total consolidated assets			$	9,532
	Less:
		Consolidated current liabilities			(538	)
		Intangible assets			(135	)
				$	8,859
10% Threshold				$	886

This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or dispositions, which are not reinvested as provided above,

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are retained by EME as cash or cash equivalents or are used by EME to repay senior debt of EME or debt of its subsidiaries.

As a wholly owned indirect subsidiary of Edison International, EME is subject to determinations made by its directors, each of whom is appointed by Edison International, to act in the interests of Edison International and its shareholders, which may result in EME making distributions of cash or assets, subject to the limitations described above, at any time or from time to time, which may affect assets held or under development.

Wind Financing

In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse portfolio financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The portfolio financing included a:

•

$189 million seven-year term loan that is expected to fully amortize within the seven years via scheduled principal payments and cash sweeps from a portion of excess cash flow; and

•

$13 million letter of credit facility which replaced project letters of credit previously issued under the EME corporate credit facility.

In July 2009, Viento Funding II amended the credit agreement to add a working capital facility. Availability under the facility is initially $3.8 million and steps up semi-annually to $5.2 million by maturity. The agreement restricts the use of proceeds from the working capital facility to operation and maintenance expenditures at these three wind projects.

Interest under the term loan accrues at LIBOR plus 3.875% initially, with the rate increasing 0.25% on the third and sixth anniversaries of the closing date. Viento Funding II has entered into interest rate swap agreements to hedge the majority of the variable interest rate under the term loan. The interest rate swap agreements fixed the majority of the LIBOR rate under the term loan to 3.175%, before amortization of the deferred financing costs. At June 30, 2009, the swap adjusted rate was 7.05%. Distributions from Viento Funding II are subject to compliance with the terms and conditions of credit facilities, including a covenant to meet a 12-month historic debt service coverage ratio as specified in the agreement of 1.20 to 1.0.

In connection with this financing, EME entered into an agreement with Viento Funding II to make quarterly payments for production tax credits irrespective of whether such credits can be realized on Edison International's consolidated tax returns.

EMG: OTHER DEVELOPMENTS

RPM CONE

On March 26, 2009, the FERC issued an order accepting the CONE values submitted by PJM in its February 9, 2009 filing. The FERC-accepted CONE as proposed for the May 2009 RPM auction for the 2012/2013 delivery year is higher than the previously approved CONE value. In addition, the FERC approved a proposal that would set a higher net region-wide CONE value. The FERC also accepted other RPM provisions, such as the holdback of 2.5% of the reliability requirement from the Base Residual Auction to encourage Demand Side Management which could reduce the clearing price for market capacity. Finally, the FERC RPM order directed PJM to file a proposal in September 2009 that would automate the adjustment of CONE (as compared to the existing tariff that requires a CONE evaluation and FERC filing every three years). Several parties have requested rehearing of the order. This matter is currently pending before the FERC.

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EMG: MARKET RISK EXPOSURES

Introduction

EMG's primary market risk exposures are associated with the sale of electricity and capacity from, and the procurement of fuel for, its merchant power plants. These market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, and transmission rights. Additionally, EME's financial results can be affected by fluctuations in interest rates. EME manages these risks in part by using derivative instruments in accordance with established policies and procedures.

Commodity Price Risk

Introduction

EME's merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored, with oversight provided by a risk management committee, to ensure compliance with EME's risk management policies. Policies are in place which define risk management processes, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by EME's risk management committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

In addition to prevailing market prices, EME's ability to derive profits from the sale of electricity will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of production of the units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the units may vary.

EME uses "gross margin at risk" to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions at the Illinois Plants, the Homer City facilities, and the merchant wind projects, and "value at risk" to identify, measure, monitor and control its overall risk exposure with respect to its trading positions. The use of these measures allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss, and gross margin at risk measures the potential change in value, of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers and counterparty credit exposure limits.

Energy Price Risk Affecting Sales from the Illinois Plants

All the energy and capacity from the Illinois Plants is sold under terms, including price and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. As discussed further below, power generated at the Illinois Plants is generally sold into the PJM market.

Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois Plants are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, or may be entered into at other trading hubs, including the Cinergy Hub in the Midwest Independent Transmission System Operator (MISO). These trading hubs have been the most liquid locations for hedging purposes. For further discussion, see "—Basis Risk" below.

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PJM has a short-term market, which establishes an hourly clearing price. The Illinois Plants are situated in the PJM control area and are physically connected to high-voltage transmission lines serving this market.

The following table depicts the average historical market prices for energy per megawatt-hour during the first six months of 2009 and 2008:

		24-Hour Northern Illinois Hub Historical Energy Prices(1)
		2009			2008
January		$	42.10		$	47.09
February			33.33			54.46
March			26.74			58.58
April			26.93			53.87
May			25.81			44.49
June			25.59			56.06
Six-Month Average		$	30.08		$	52.42

(1)

Energy prices were calculated at the Northern Illinois Hub delivery point using hourly real-time prices as published by PJM.

Forward market prices at the Northern Illinois Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Illinois Plants into these markets may vary materially from the forward market prices set forth in the table below.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at June 30, 2009:

			24-Hour Northern Illinois Hub Forward Energy Prices(1)
2009
	July		$	31.54
	August			30.33
	September			26.33
	October			25.82
	November			28.63
	December			30.91
2010 Calendar "strip"(2)			$	33.39

(1)

Energy prices were determined by obtaining broker quotes and information from other public sources relating to the Northern Illinois Hub delivery point.

(2)

Market price for energy purchases for the entire calendar year, as quoted for sales into the Northern Illinois Hub.

EMMT engages in hedging activities for the Illinois Plants to hedge the risk of future change in the price of electricity. Hedging activities are typically weighted toward on-peak periods. The following

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table summarizes Midwest Generation's hedge position for contracts entered into at both the Northern Illinois Hub and AEP/Dayton Hub at June 30, 2009:

		2009			2010			2011
GWh			5,352			6,981			612
Average price/MWh(1)		$	63.91		$	67.30		$	76.40

(1)

The above hedge positions include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions at June 30, 2009 are not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.

In addition, as of June 30, 2009, EMMT has entered into 9.8 billion cubic feet of natural gas futures contracts (equivalent to approximately 1,600 GWh of energy only contracts using a ratio of 6 MMBtu to 1 MWh) to hedge Midwest Generation energy price risks during 2009 and 2010.

Energy Price Risk Affecting Sales from the Homer City Facilities

All the energy and capacity from the Homer City facilities is sold under terms, including price and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Electric power generated at the Homer City facilities is generally sold into the PJM market. PJM has a short-term market, which establishes an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets.

The following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and the PJM West Hub (EME Homer City's primary trading hub) during the first six months of 2009 and 2008:

		Historical Energy Prices(1) 24-Hour PJM
		Homer City						West Hub
		2009			2008			2009			2008
January		$	53.22		$	54.32		$	59.32		$	66.80
February			42.86			61.74			46.31			68.29
March			38.08			65.37			41.63			70.48
April			32.64			61.99			34.48			69.12
May			31.39			49.37			33.40			59.84
June			29.87			78.72			33.25			98.50
Six-Month Average		$	38.01		$	61.92		$	41.40		$	72.17

(1)

Energy prices were calculated at the Homer City busbar (delivery point) and PJM West Hub using historical hourly real-time prices provided on the PJM web-site.

Forward market prices at the PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the Homer City facilities into these markets may vary materially from the forward market prices set forth in the table below.

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The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at June 30, 2009:

			24-Hour PJM West Hub Forward Energy Prices(1)
2009
	July		$	41.24
	August			41.10
	September			36.23
	October			35.25
	November			38.72
	December			45.15
2010 Calendar "strip"(2)			$	48.63

(1)

Energy prices were determined by obtaining broker quotes and information from other public sources relating to the PJM West Hub delivery point. Forward prices at PJM West Hub are generally higher than the prices at the Homer City busbar.

(2)

Market price for energy purchases for the entire calendar year, as quoted for sales into the PJM West Hub.

EMMT engages in hedging activities for the Homer City facilities to hedge the risk of future change in the price of electricity. Hedging activities are typically weighted toward on-peak periods. The following table summarizes EME Homer City's hedge position at June 30, 2009:

		2009			2010
GWh			2,064			2,662
Average price/MWh(1)		$	82.88		$	90.61

(1)

The above hedge positions include forward contracts for the sale of power during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at June 30, 2009 is not directly comparable to the 24-hour PJM West Hub prices set forth above.

The average price/MWh for EME Homer City's hedge position is based on the PJM West Hub. Energy prices at the Homer City busbar have been lower than energy prices at the PJM West Hub. For a discussion of the difference, see "—Basis Risk" below.

Capacity Price Risk

On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-term pricing signal for capacity resources. The RPM provides a mechanism for PJM to satisfy the region's need for generation capacity, the cost of which is allocated to load-serving entities through a locational reliability charge.

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The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at June 30, 2009:

(1)

Capacity not sold arises from: (1) capacity retained to meet forced outages under the RPM auction guidelines, and (2) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.

(2)

Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into to manage capacity risks.

(3)

Includes 342 MW purchases in January 2009 from RPM incremental auction at $40 per MW-day.

The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the price of $16.46 per MW-day was substantially lower than previous capacity prices. The decrease in forward capacity prices was attributable to a substantial increase in demand side management resources. The impact of lower capacity prices for this period on available resources and energy prices is uncertain.

Revenues from the sale of capacity from Midwest Generation and EME Homer City beyond the periods set forth above will depend upon the amount of capacity available and future market prices either in PJM or nearby markets if EME has an opportunity to capture a higher value associated with those markets. Under PJM's RPM system, the market price for capacity is generally determined by aggregate market-based supply conditions and an administratively set aggregate demand curve. Among the factors influencing the supply of capacity in any particular market are plant forced outage rates, plant closings, plant delistings (due to plants being removed as capacity resources and/or to export capacity to other markets), capacity imports from other markets, demand side management activities and the CONE.

Basis Risk

Sales made from the Illinois Plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices or day-ahead prices, as the case may be, at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case of the Homer City facilities and for settlement

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points at the Northern Illinois Hub and the AEP/Dayton Hub in the case of the Illinois Plants. EME's hedging activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as "basis risk." During the six months ended June 30, 2009 and 2008, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 8% and 14%, respectively. The monthly average difference between prices at the Homer City busbar and those at the PJM West Hub during the 12 months ended June 30, 2009 ranged from 5% to 21%. During the six months ended June 30, 2009, transmission congestion in PJM has resulted in prices at the individual busbars of the Illinois Plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 17% and less than 1%, respectively.

By entering into cash settled futures contracts and forward contracts using the PJM West Hub, the Northern Illinois Hub, and the AEP/Dayton Hub (or other similar trading hubs) as settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME may purchase financial transmission rights and basis swaps in PJM for EME Homer City and Midwest Generation. A financial transmission right is a financial instrument that entitles the holder to receive the difference between actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME's hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

Coal and Transportation Price Risk

The Illinois Plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at June 30, 2009 for the remainder of 2009 and the following two years:

		Amount of Coal Under Contract in Millions of Equivalent Tons(1)
		July through December 2009			2010			2011
Illinois Plants(2)			8.8			11.7			—
Homer City facilities(3)			2.6			1.0			0.2

(1)

The amount of coal under contract in tons is calculated based on contracted tons and applying an 8,800 Btu equivalent for the Illinois Plants and 13,000 Btu equivalent for the Homer City facilities.

(2)

In July 2009, Midwest Generation entered into additional contractual agreements for the purchase of coal of 5.4 million tons for 2010, 9.8 million tons for 2011 and 9.8 million tons for 2012.

(3)

At June 30, 2009, there are options to purchase additional coal of 0.5 million tons for 2010, 0.6 million tons for 2011, 0.5 million tons for 2012, and 0.1 million tons for 2013.

EME is subject to price risk for purchases of coal that are not under contract. Prices of NAPP coal, which are related to the price of coal purchased for the Homer City facilities, decreased during 2009 from 2008 year-end prices. The price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) decreased to $46.50 per ton at July 2, 2009 from $76 per ton at January 9, 2009, as reported by the Energy Information Administration. The 2009 decrease in NAPP coal prices was due in part to current global economic conditions that have lessened demand for coal, high levels of inventories and fuel switching. Prices of PRB coal (with 8,800 Btu per pound heat

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content and 0.8 pounds of SO₂ per MMBtu sulfur content) purchased for the Illinois Plants declined during 2009. The price of PRB coal decreased to $9.00 per ton at July 2, 2009 from $13 per ton at January 9, 2009, as reported by the Energy Information Administration. The 2009 decrease in PRB coal prices was due to lower demand and higher levels of inventory.

EME has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through 2011. EME is exposed to price risk related to higher transportation rates after the expiration of its existing transportation contracts. Current transportation rates for PRB coal are higher than the existing rates under contract (transportation costs are approximately 50% of the delivered cost of PRB coal to the Illinois Plants).

Emission Allowances Price Risk

The federal Acid Rain Program requires electric generating stations to hold SO₂ allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the Clean Air Interstate Rule, electric generating stations are required to hold seasonal and annual NO_X allowances beginning January 1, 2009. As part of the acquisition of the Illinois Plants and the Homer City facilities, EME obtained the rights to emission allowances that have been or are allocated to these plants. EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. For further discussion of the Clean Air Interstate Rule, refer to "Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule" in the year-ended 2008 MD&A.

EME is subject to price risk for purchases of emission allowances required for actual emissions greater than allowances held. The market price for emission allowances may vary significantly. The average purchase price of SO₂ allowances decreased to $66 per ton during the six months ended June 30, 2009 from $315 per ton during 2008. Based on broker's quotes and information from public sources, the spot price for SO₂ allowances and annual NO_X allowances was $70 per ton and $1,113 per ton, respectively, at June 30, 2009.

For a discussion of environmental regulations related to emissions, refer to "Other Developments—Environmental Matters—Air Quality Regulation" in the year-ended 2008 MD&A.

Accounting for Derivative Instruments

EME uses derivative instruments to reduce its exposure to market risks that arise from fluctuations in electricity, capacity and fuel prices, emission allowances and transmission rights. These derivative instruments include forward sales transactions entered into on a bilateral basis with third parties, futures contracts, full requirements services contracts or load requirements services contracts and capacity transactions. SFAS No. 133 requires changes in the fair value of each derivative instrument to be recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that qualifies for cash flow hedge accounting is recognized currently in earnings. For further discussion of derivative instruments, see "Edison International Notes to Consolidated Financial Statements—Note 2. Derivative Instruments and Hedging Activities," and also refer to "Critical Accounting Estimates and Policies—Derivative Financial Instruments and Hedging Activities" in the year-ended 2008 MD&A.

EME classifies unrealized gains and losses from derivative instruments as part of operating revenues or fuel expenses. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. The following table summarizes unrealized gains

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(losses) from non-trading activities for the second quarters of 2009 and 2008 and six months ended June 30, 2009 and 2008:

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Illinois Plants
	Non-qualifying hedges		$	18		$	2		$	34		$	2
	Ineffective portion of cash flow hedges			1			(5	)		—			(10	)
Homer City facilities
	Non-qualifying hedges			1			1			—			2
	Ineffective portion of cash flow hedges			4			(7	)		5			(9	)
Total unrealized gains (losses)			$	24		$	(9	)	$	39		$	(15	)

At June 30, 2009, unrealized gains of $33 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($6 million for the remainder of 2009, $22 million for 2010, and $5 million for 2011).

Fair Value of Derivative Instruments

EME adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements. For further discussion of EME's adoption of SFAS No. 157, see "Edison International Notes to Consolidated Financial Statements—Note 10. Fair Value Measurements."

Non-Trading Derivative Instruments

The fair value of outstanding non-trading commodity derivative instruments at June 30, 2009 and December 31, 2008 was $470 million and $375 million, respectively. In assessing the fair value of EME's non-trading commodity derivative instruments, EME uses quoted market prices and forward market prices adjusted for credit risk. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The increase in fair value of commodity contracts at June 30, 2009 as compared to December 31, 2008 is attributable to a decline in the average market prices for power as compared to contracted prices at June 30, 2009, which is the valuation date. The following table summarizes the maturities and the related fair value of EME's commodity derivative assets and liabilities before the impact of offsetting collateral under FIN No. 39-1 as of June 30, 2009:

In millions		Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years			Maturity >5 years
Prices actively quoted		$	17		$	10		$	7		$	—		$	—
Prices provided by external sources			450			332			118			—			—
Price based on models and other valuation methods			3			2			1			—			—
Total		$	470		$	344		$	126		$	—		$	—

Prices actively quoted in the preceding table include exchange-traded derivatives. Prices provided by external sources include derivatives whose fair value is based on forward market prices in active markets adjusted for nonperformance risks which would be considered Level 2 derivative positions when there are no unobservable inputs that are significant to the valuation. EME obtains forward market prices from traded exchanges (ICE Futures U.S. or New York Mercantile Exchange) and

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available broker quotes. Then, EME selects a primary source that best represents traded activity for each market to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources that EME believes to provide the most liquid market for the commodity. EME considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers, and comparison to executed trades.

Energy Trading Derivative Instruments

The fair value of outstanding energy trading derivative instruments at June 30, 2009 and December 31, 2008 was $128 million and $112 million, respectively. The change in the fair value of trading contracts for the six months ended June 30, 2009 was as follows:

In millions
Fair value of trading contracts at January 1, 2009		$	112
Net gains from energy trading activities			30
Amount realized from energy trading activities			(24	)
Other changes in fair value			10
Fair value of trading contracts at June 30, 2009		$	128

The impact of changes to the various inputs used to determine the fair value of Level 3 derivatives is not currently material to EME's results of operations as such changes are offset by similar changes in derivatives classified within Level 3 as well as other categories.

The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities before the impact of offsetting collateral under FIN No. 39-1 (as of June 30, 2009):

In millions		Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years			Maturity >5 years
Prices actively quoted		$	2		$	1		$	1		$	—		$	—
Prices provided by external sources			(111	)		(99	)		(7	)		(5	)		—
Prices based on models and other valuation methods			237			151			41			28			17
Total		$	128		$	53		$	35		$	23		$	17

In the table above, prices actively quoted include exchange-traded derivatives. Prices provided by external sources include non-exchange-traded derivatives. These are priced based on forward market prices adjusted for nonperformance risks which would be considered Level 2 derivative positions when there are no unobservable inputs that are significant to the valuation. Fair values for Level 2 derivative positions are determined using the same methodology previously described for non-trading derivative instruments. Fair values for Level 3 derivative positions are determined using prices based on models and other valuation methods and include load requirements services contracts, illiquid financial transmission rights, over-the-counter derivatives at illiquid locations and long-term power agreements. For long-term power agreements, EME's subsidiary records these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit and liquidity.

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Credit Risk

In conducting EME's hedging and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted price if the nonperforming counterparty were unable to pay the resulting damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time a counterparty defaulted.

To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that EME would expect to incur if a counterparty failed to perform pursuant to the terms of its contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure.

EME has established processes to determine and monitor the creditworthiness of counterparties. EME manages the credit risk of its counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. A risk management committee regularly reviews the credit quality of EME's counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EME's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At June 30, 2009, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

In millions		June 30, 2009
Credit Rating(1)		Exposure(2)			Collateral			Net Exposure
A or higher		$	468		$	(263	)	$	205
A-			54			—			54
BBB+			38			—			38
BBB			150			—			150
BBB-			4			—			4
Below investment grade			3			—			3
Total		$	717		$	(263	)	$	454

(1)

EME assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.

(2)

Exposure excludes amounts related to contracts classified as normal purchase and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related accounts receivable.

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The credit risk exposure set forth in the above table is comprised of $149 million of net accounts receivable and payables and $568 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties.

Included in the table above are exposures to financial institutions with credit ratings of A or above. Due to developments in the financial markets, the credit ratings may not be reflective of the related credit risks. For further discussion, refer to "Edison International: Management Overview—Financial Markets and Economic Conditions" in the year-ended 2008 MD&A. The total net exposure to financial institutions at June 30, 2009 was $186 million. This total net exposure excludes positions with Lehman Brothers Holdings and its subsidiaries. Five financial institutions comprise 38% of the net exposure above with the largest single net exposure with a financial institution representing 13%. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $100 million cash margin in the aggregate with PJM, NYISO, MISO, clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EME to credit risk of the related entities.

EME's plants owned by unconsolidated affiliates in which EME owns an interest sell power under power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a counterparty under a power purchase agreement, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of such power project.

In addition, coal for the Illinois Plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers to the Illinois Plants and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages in the event of default by a supplier. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

EME's merchant plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 41% of EME's consolidated operating revenues for the six months ended June 30, 2009. Moody's rates PJM's debt Aa3. PJM, an ISO with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At June 30, 2009, EME's account receivable due from PJM was $46 million.

For the six months ended June 30, 2009, a second customer, Constellation Energy Commodities Group, Inc., accounted for 24% of EME's consolidated operating revenues. Sales to Constellation are primarily generated from EME's merchant plants and largely consist of energy sales under forward contracts. The contract with Constellation is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating of BBB by S&P and Baa3 by Moody's. At June 30, 2009, EME's account receivable due from Constellation was $25 million.

The terms of EME's wind turbine supply agreements contain significant obligations of the suppliers in the form of manufacturing and delivery of turbines and payments, for delays in delivery and for failure to meet performance obligations and warranty agreements. EME's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to a turbine supplier may have a material impact on EME's wind projects.

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At June 30, 2009, Edison Capital had a net leveraged lease investment, before deferred taxes, of $47 million in three aircraft leased to American Airlines. American Airlines reported net losses in the first and second quarters of 2009 and previously reported losses for 2008. A default in the leveraged lease by American Airlines could result in a loss of some or all of Edison Capital's lease investment. At June 30, 2009, American Airlines was current in its lease payments to Edison Capital.

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. In June 2009, EME's subsidiary, Viento Funding II, Inc., entered into interest rate swap agreements in connection with the non-recourse portfolio financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. For details, see "EMG: Liquidity and Capital Resources—Wind Financing." The fair market values of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EMG's consolidated long-term obligations (including current portion) was $4.0 billion at June 30, 2009, compared to the carrying value of $4.9 billion.

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EDISON INTERNATIONAL (PARENT)

EDISON INTERNATIONAL (PARENT): LIQUIDITY

The parent company's liquidity and its ability to pay interest and principal on debt, if any, operating expenses and dividends to common shareholders are affected by dividends and other distributions from subsidiaries, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets. At June 30, 2009, Edison International (parent) had approximately $27 million of cash and cash equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at June 30, 2009:

In millions		Edison International (parent)
Commitment		$	1,426
Outstanding borrowings			(77	)
Outstanding letters of credit			—
Amount available		$	1,349

In June 2009, Edison International amended the $1.5 billion revolving credit facility to remove a subsidiary of Lehman Brothers Holding as a lender which resulted in a reduction of the total commitment under the facility.

Edison International (parent)'s cash requirements for the 12-month period following June 30, 2009 are expected to consist of:

•

Dividends to common shareholders. The Board of Directors of Edison International declared $0.31 per share quarterly dividends in December 2008, February 2009, and June 2009 which were paid in January 2009, April 2009, and July 2009, respectively. These quarterly dividends represent an increase of $0.005 per share over quarterly dividends paid in 2008. The dividend increase is consistent with Edison International's dividend policy of paying out approximately 45% to 55% of the earnings of SCE and balancing dividend increases with the significantly growing capital needs of Edison International's business;

•

Principal and interest payments and fees on debt outstanding under the credit facility;

•

Interest payments on intercompany related debt; and

•

General and administrative expenses.

Edison International (parent) expects to meet its 2009 continuing obligations through cash and cash equivalents on hand, external borrowings, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and two $100 million SCE dividends paid in January 2009 and July 2009.

Intercompany Tax-Allocation Agreement

SCE, EME and Edison Capital are included in the consolidated federal and combined state income tax returns of Edison International and participate in tax-allocation payments with other subsidiaries of Edison International in accordance with the terms of intercompany tax allocation agreements among the affiliated companies.

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In connection with the Global Settlement, Edison International made federal and state tax payments of $195 million. Under the tax allocation agreement with EMG, Edison International received net payments of $1.06 billion, principally from Edison Capital ($920 million) funded by the proceeds of termination of the cross border leases. Edison International made net tax allocation payments of $875 million to SCE.

Edison International expects that the Global Settlement, together with the termination of the Edison Capital cross border leases, will result in a positive cash impact over time. The following table provides the approximate amounts expected by major subsidiary:

In millions		SCE			Edison Capital			Edison International (parent) and All Other(1)			Edison International Consolidated
Net proceeds from termination of cross-border leases		$	—		$	1,385		$	—		$	1,385
Taxes settled through June 30, 2009			875			(920	)		(150	)		(195	)
Estimated future net tax payments			(235	)		(765	)		190			(810	)
Cash flow expected over time		$	640		$	(300	)	$	40		$	380

(1)

Includes all other Edison International consolidated subsidiaries.

See "Edison International: Management Overview—Areas of Business Focus—Federal and State Income Taxes" for further discussion on the Global Settlement.

Debt Covenant

Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At June 30, 2009, Edison International's consolidated debt to total capitalization ratio was 0.54 to 1.

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EDISON INTERNATIONAL (CONSOLIDATED)

RESULTS OF OPERATIONS

Edison International's reportable segments include its "electric utility operations" (SCE), "competitive power generation" (EME), "financial services and other" (Edison Capital and other EMG subsidiaries).

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Electric utility – SCE			$	499		$	157		$	707		$	307
EMG
	Competitive power generation			40			72			96			217
	Financial services and other			(598	)		39			(606	)		48
Edison International (parent) and other(1)				43			(7	)		37			(13	)
Net Income Attributable to Edison International			$	(16	)	$	261		$	234		$	559

(1)

Includes amounts from Edison International (parent), and other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.

Electric Utility Net Income – SCE

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Electric utility operating revenue			$	2,273		$	2,850		$	4,462		$	5,231
Fuel				156			397			356			746
Purchased power				583			1,026			1,124			1,721
Other operation and maintenance				823			816			1,547			1,544
Depreciation, decommissioning and amortization				289			287			574			553
Lease terminations and other				(1	)		(7	)		(1	)		(8	)
Total operating expenses				1,850			2,519			3,600			4,556
Operating Income				423			331			862			675
Interest and dividend income				2			5			6			10
Other nonoperating income				29			25			56			44
Interest expense – net of amounts capitalized				(106	)		(96	)		(215	)		(193	)
Other nonoperating deductions				(12	)		(14	)		(20	)		(26	)
Income from continuing operations before income taxes				336			251			689			510
Income tax expense (benefit)				(198	)		30			(77	)		111
Income from continuing operations				534			221			766			399
Less: Net income attributable to noncontrolling interests				35			64			59			92
Electric utility net income attributable to
	Edison International		$	499		$	157		$	707		$	307

SCE has contracts with certain QFs that contain variable contract pricing provisions based on the price of natural gas. Four of these contracts are with entities that are partnerships owned in part by EME. The QFs sell electricity to SCE and steam to nonrelated parties. As required by FIN 46(R), SCE

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consolidates these Big 4 projects. See "—Competitive Power Generation Operating Income" for a discussion related to the Big 4 projects.

Electric Utility Operating Revenue

The following table sets forth the major components of electric utility revenue:

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2009			2008			2009			2008
Electric utility revenue
Retail billed and unbilled revenue		$	2,322		$	2,244		$	4,217		$	4,143
Balancing account (over)/under collections			(189	)		257			(126	)		368
Sales for resale			13			143			104			325
Big 4 projects (SCE's VIEs)(1)			46			118			106			215
Other (including intercompany transactions)			81			88			161			180
Total		$	2,273		$	2,850		$	4,462		$	5,231

(1)

See "—Competitive Power Generation Net Income" for a discussion related to the Big 4 projects.

SCE's retail sales represented approximately 94% and 92% of electric utility revenue for the three- and six-month periods ended June 30, 2009, respectively, compared to approximately 88% and 86% for the comparable periods in 2008, respectively. Due to warmer weather during the summer months and SCE's rate design, electric utility revenue during the third quarter of each year is generally higher than other quarters. Of total electric utility revenue approximately $1.0 billion and $2.0 billion was subject to balancing account treatment for the three- and six-month periods ended June 30, 2009, respectively, compared to approximately $1.7 billion and $2.9 billion for the same periods in 2008, respectively.

Total electric utility revenue decreased by $577 million and $769 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008. The variances for the revenue components are as follows:

•

Retail billed and unbilled revenue increased $78 million and $74 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008. The quarter and year-to-date increases reflect a rate increase of $216 million and $287 million, respectively, and a sales volume decrease of $138 million and $213 million, respectively. Effective April 4, 2009, SCE's overall system average rate increased to 14.1¢ per-kWh (including 2.3¢ per-kWh related to CDWR). The sales volume decrease was due to the economic downtown as well as the impact of milder weather experienced in the later part of second quarter 2009 compared to the same period in 2008. For the three- and six-month periods ended June 30, 2009, SCE deferred $189 million and $126 million of revenue collected above the authorized revenue requirement, respectively, compared to $257 million and $368 million of revenue accrued due to collections below the authorized revenue requirement for the three- and six-month periods ended June 30, 2008, respectively. SCE's revenue requirement provides recovery of pass-through costs under ratemaking mechanisms (balancing accounts) authorized by the CPUC. The revenue requirement for pass-through costs provides recovery of fuel and purchased-power expenses, demand-side management programs, nuclear decommissioning, public purpose programs, certain operation and maintenance expenses and depreciation expense related to certain projects. SCE recognizes revenue equal to actual costs incurred for pass-through costs. During the first quarter of 2009, SCE implemented the 2009 GRC which resulted in an updated revenue requirement retroactive to January 1, 2009 consistent with the CPUC authorization. The change in balancing account (over)/under collections for the periods was

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due to lower purchased power and fuel costs experienced during 2009 compared to the same periods in 2008 (see "—Purchased-Power Expense" and "—Fuel Expense" for further information).

•

Sales for resale represent the sale of excess energy. SCE determines whether it is economically beneficial to dispatch available generation resources for the sale of excess energy. Sales for resale revenue decreased for the three- and six-month periods ended June 30, 2009 compared to the same periods in 2008 primarily due to lower natural gas prices and lower kWh sales due to SCE's decision not to dispatch generation resources because to do so would have not been economically beneficial. Revenue from sales for resale is refunded to customers through the ERRA balancing account and does not impact earnings.

Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWR and are not recognized as revenue by SCE. The amounts collected and remitted to CDWR were $391 million and $896 million for the three- and six-month periods ended June 30, 2009, respectively and $539 million and $1.1 billion for the three- and six-month periods ended June 30, 2008, respectively.

Fuel Expense

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2009			2008			2009			2008
SCE		$	80		$	149		$	179		$	306
SCE's VIEs (Big 4 projects)(1)			76			248			177			440
Total fuel expense		$	156		$	397		$	356		$	746

(1)

See "—Competitive Power Generation Net Income" for a discussion related to the Big 4 projects.

SCE's fuel expense decreased $69 million and $127 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008. The quarter and year-to-date decreases were mainly due to decreases at SCE's Mountainview plant of $80 million and $145 million, respectively, resulting primarily from lower natural gas costs in 2009 compared to 2008.

SCE's VIEs fuel expense decreased $172 million and $263 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008. The decreases were mainly due to lower natural gas costs in 2009 compared to 2008.

Purchased-Power Expense

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2009			2008			2009			2008
Cost of purchased power		$	487		$	1,054		$	930		$	1,747
Realized losses (gains) on economic hedging activities – net			96			(28	)		194			(26	)
Total purchased-power expense		$	583		$	1,026		$	1,124		$	1,721

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SCE's total purchased-power expense decreased $443 million and $597 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008.

Cost of purchased power decreased $567 million and $817 million for the three- and six-month periods ended June 30, 2009, respectively, as compared to the same periods in 2008. The quarter and year-to-date decreases were due to: lower bilateral energy and QF purchases of $475 million and $640 million, respectively, resulting from decreased kWh purchases and lower costs per kWh due to lower natural gas prices; and lower ISO-related energy costs of $90 million and $100 million, respectively. The year-to-date variance also includes lower firm transmission rights costs of $60 million (see "SCE: Market Risk Exposures—Natural Gas and Electricity Price Risk" for further information).

SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and recovers these costs from ratepayers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Realized losses on economic hedging activities were $96 million and $194 million for the three- and six-month periods ended June 30, 2009, respectively, compared to realized gains on economic hedging activities of $28 million and $26 million for the comparable periods in 2008, respectively. Changes in realized gains and losses on economic hedging activities were primarily due to significant decreases in settled natural gas prices. See "SCE: Market Risk Exposures—Commodity Price Risk" for further discussion.

Depreciation, Decommissioning and Amortization Expense

SCE's depreciation, decommissioning and amortization expense increased $2 million and $21 million for the three- and six-month periods ended June 30, 2009, compared to the same periods in 2008. The quarter and year-to date variances reflect an increase in capitalized software amortization costs of $10 million and $20 million respectively. The quarter variance also reflects an increase in planned capital expenditures offset by a $17 million cumulative depreciation rate adjustment recorded in the second quarter of 2008.

Other Nonoperating Income

SCE's other nonoperating income increased $12 million for the six months ended June 30, 2009, compared to the same period in 2008 mainly due to an increase in allowance for funds used during construction – equity resulting from an increase in construction work in progress due to planned capital expenditures (see "SCE: Liquidity—Capital Expenditures" for further discussion).

Interest Expense – Net of Amounts Capitalized

SCE's interest expense – net of amounts capitalized increased $10 million and $22 million for the three- and six-month periods ended June 30, 2009, respectively, compared to the same periods in 2008. The increases were primarily due to higher interest expense on long-term debt resulting from higher outstanding balances compared to the same periods in 2008. These increases were partially offset by lower over-collections of certain balancing accounts and lower interest rates applied to those over-collections during 2009 compared to the same periods in 2008.

Income Taxes

SCE's composite federal and state statutory income tax rates were approximately 41% and 40% (net of the federal benefit for state income taxes) for 2009 and 2008 respectively. The effective tax rate was (63)% and (12)% for the three-and six-month periods ended June 30, 2009, respectively, as compared to 15% and 25% for the respective periods in 2008. The 2009 effective tax rate was lower when compared to both the 2008 effective tax rate and the 2009 statutory rate mainly due to a $300 million benefit related primarily to tax timing differences on certain affirmative claims as a result of the Global

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Settlement (see "Edison International: Management Overview—Areas of Business Focus—Federal and State Income Taxes" for further discussion).

Competitive Power Generation Net Income

The following table sets forth the major changes in competitive power generation net income:

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Competitive power generation operating revenue			$	557		$	613		$	1,169		$	1,332
Fuel				172			157			359			344
Other operation and maintenance				241			289			478			517
Depreciation, decommissioning and amortization				56			46			112			90
Lease terminations and other				—			—			1			(16	)
Total operating expenses				469			492			950			935
Operating Income				88			121			219			397
Interest and dividend income				12			16			16			25
Equity in income from partnerships and
	unconsolidated subsidiaries – net			20			37			26			49
Other nonoperating income				1			(1	)		2			5
Interest expense – net of amounts capitalized				(73	)		(66	)		(147	)		(137	)
Income from continuing operations before income taxes				48			107			116			339
Income tax expense				2			34			17			116
Income from continuing operations				46			73			99			223
Loss from discontinued operations – net of tax				(7	)		(1	)		(4	)		(6	)
Net income				39			72			95			217
Less: Loss attributable to noncontrolling interests				(1	)		—			(1	)		—
Competitive power generation net income attributable to Edison International			$	40		$	72		$	96		$	217

Competitive Power Generation Operating Income

EME operates in one line of business, independent power production. Operating revenues are primarily derived from the sale of energy and capacity from the Illinois Plants and the Homer City facilities. Equity in income from unconsolidated affiliates relates to energy projects accounted for under the equity method. EME recognizes its proportional share of the income or loss of such entities.

EME uses the words "earnings" or "losses" in this section to describe adjusted operating income (loss) as described below.

The following section and table provide a summary of results of EME's operating projects and corporate expenses for the second quarters of 2009 and 2008 and six months ended June 30, 2009 and 2008, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

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The following table shows the adjusted operating income of EME's projects:

		Three Months Ended June 30,						Six Months Ended June 30,
In millions		2009			2008			2009			2008
Illinois Plants		$	74		$	111		$	188		$	342
Homer City			47			(13	)		83			41
Renewable energy projects			11			25			37			33
Energy trading			17			51			27			92
Big 4 projects			11			28			17			36
Sunrise			6			6			1			5
Doga			8			8			8			8
March Point			1			—			3			—
Westside projects			—			1			3			5
Other non-wind projects			3			4			5			6
			178			221			372			568
Corporate administrative and general			(43	)		(42	)		(79	)		(82	)
Corporate depreciation and amortization			(3	)		(2	)		(6	)		(5	)
Adjusted Operating Income(1)		$	132		$	177		$	287		$	481

The following table reconciles adjusted operating income to operating income as reflected on EME's consolidated statements of income:

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Adjusted Operating Income			$	132		$	177		$	287		$	481
Less:
	Equity in earnings of unconsolidated affiliates			20			37			26			49
	Dividend income from projects			9			9			10			10
	Production tax credits			14			11			30			20
	Other income (expense), net			1			(1	)		2			5
Operating Income			$	88		$	121		$	219		$	397

(1)

Adjusted operating income is equal to operating income under GAAP, plus equity in earnings of unconsolidated affiliates, dividend income from projects, production tax credits and other income and expenses. Production tax credits are recognized as wind energy is generated based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Adjusted operating income is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits and other income and expenses in adjusted operating income is more meaningful for investors as these components are integral to the operating results of EME.

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Earnings from Consolidated Operations

Illinois Plants

The following table presents additional data for the Illinois Plants:

				Three Months Ended June 30,						Six Months Ended June 30,
In millions				2009			2008			2009			2008
Operating Revenues				$	340		$	391		$	724		$	859
Operating Expenses
	Fuel(1)				110			106			233			224
	Gain on sale of emission allowances(2)				—			(1	)		—			(3	)
	Plant operations				106			125			202			219
	Plant operating leases				19			18			38			37
	Depreciation and amortization				27			27			54			52
	Gain on buyout of contract and disposal of assets				—			—			—			(16	)
	Administrative and general				5			5			10			11
	Total operating expenses				267			280			537			524
Operating Income					73			111			187			335
Other Income (Expense)					1			—			1			7
Adjusted Operating Income(3)				$	74		$	111		$	188		$	342
Statistics(4)
	Generation (in GWh):
		Energy only contracts			6,361			5,533			12,117			12,071
		Load requirements services contracts(5)			447			1,287			1,333			3,132
		Total			6,808			6,820			13,450			15,203
	Aggregate plant performance:
		Equivalent availability(6)			78.5	%		72.6	%		80.6	%		77.5	%
		Capacity factor(7)			57.1	%		57.2	%		51.2	%		63.7	%
		Load factor(8)			72.7	%		78.7	%		63.5	%		82.2	%
		Forced outage rate(9)			5.7	%		6.5	%		6.4	%		9.3	%
	Average realized price/MWh:
		Energy only contracts(10)		$	41.38		$	52.67		$	44.41		$	52.94
		Load requirements services contracts(11)		$	62.47		$	62.48		$	62.52		$	62.40
	Capacity revenue only (in millions)			$	42		$	20		$	81		$	29
	Average realized fuel costs/MWh(12)			$	18.19		$	15.56		$	18.37		$	14.74

(1)

Included in fuel costs were $14 million and $33 million during the second quarter and six months ended June 30, 2009 related to the net cost of emission allowances. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

(2)

The Illinois Plants sold excess SO₂ emission allowances to the Homer City facilities at fair market value. Sales to the Homer City facilities were $2 million during the six months ended June 30, 2008. These sales reduced operating expenses. EME recorded $3 million of intercompany profit during the six months ended June 30, 2008 consisting of $2 million related to emission allowances sold by the Illinois Plants to the Homer City facilities during the fourth quarter of 2007, but not used by the Homer City facilities until the first quarter of 2008, and $1 million related to emission

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allowances sold by the Illinois Plants to the Homer City facilities during the first quarter of 2008, but not used by the Homer City facilities until the second quarter of 2008.

(3)

As described above, adjusted operating income is equal to operating income plus other income (expense). Adjusted operating income is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of other income (expense) is more meaningful for investors as the components of other income (expense) are integral to the results of the Illinois Plants.

(4)

This table summarizes key performance measures related to coal-fired generation, which represents the majority of the operations of the Illinois Plants.

(5)

Represents two load requirements services contracts, awarded as part of an Illinois auction, with Commonwealth Edison that commenced on January 1, 2007. One contract expired in May 2008 and the remaining contract expired in May 2009.

(6)

The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.

(7)

The capacity factor is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.

(8)

The load factor is determined by dividing capacity factor by the equivalent availability factor.

(9)

Midwest Generation refers to unplanned maintenance as a forced outage.

(10)

The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less unrealized gains (losses) and other non-energy related revenue by (ii) generation as shown in the table below. Revenue related to capacity sales are excluded from the calculation of average realized energy price.

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Operating revenues			$	340		$	391		$	724		$	859
Less:
	Load requirements services contracts			(28	)		(81	)		(83	)		(196	)
	Unrealized (gains) losses			(5	)		3			(20	)		8
	Capacity and other revenues			(44	)		(22	)		(83	)		(32	)
Realized revenues			$	263		$	291		$	538		$	639
Generation (in GWh)				6,361			5,533			12,117			12,071
Average realized energy price/MWh			$	41.38		$	52.67		$	44.41		$	52.94

The average realized energy price is presented as an aid in understanding the operating results of the Illinois Plants. Average realized energy price is a non-GAAP performance measure since such statistical

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measure excludes unrealized gains or losses recorded as operating revenues. Management believes that the average realized energy price is more meaningful for investors as it reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to real-time market prices. A reconciliation of the Illinois Plants operating revenues presented above to consolidated operating revenues is set forth below.

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Operating revenues:
	Illinois Plants		$	340		$	391		$	724		$	859
	Homer City facilities			161			127			326			312
	Renewable energy projects			31			34			75			50
	Other revenues			25			61			44			111
Consolidated operating revenues as reported			$	557		$	613		$	1,169		$	1,332

(11)

The average realized price reflects the contract price for sales to Commonwealth Edison under load requirements services contracts that include energy, capacity and ancillary services. It is determined by dividing (i) contract revenue less PJM operating and ancillary charges by (ii) generation.

(12)

The average realized fuel costs reflect the average cost per MWh at which fuel is consumed for generation sold into the market, including the effects of hedges. It is determined by dividing (i) fuel expense adjusted for unrealized gains (losses) by (ii) generation as shown in the table below.

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Fuel expenses			$	110		$	106		$	233		$	224
Add back:
	Unrealized gains (losses)			14			—			14			—
Realized fuel expenses			$	124		$	106		$	247		$	224
Generation (in GWh)				6,808			6,820			13,450			15,203
Average realized fuel costs/MWh			$	18.19		$	15.56		$	18.37		$	14.74

The average realized fuel cost is presented as an aid in understanding the operating results of the Illinois Plants. Average realized fuel cost is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as fuel expenses. Management believes that average realized fuel cost is more meaningful for investors as it reflects the impact of hedge contracts

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at the time of actual generation in period-over-period comparisons. A reconciliation of the Illinois Plants fuel expense presented above to consolidated fuel expense is set forth below.

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Fuel expense:
	Illinois Plants		$	110		$	106		$	233		$	224
	Homer City facilities			63			52			127			124
	Other			(1	)		(1	)		(1	)		(4	)
Consolidated fuel expense as reported			$	172		$	157		$	359		$	344

Earnings from the Illinois Plants decreased $37 million and $154 million in the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. The 2009 decreases in earnings were primarily attributable to decreases in realized gross margin of $77 million and $186 million in the second quarter and six months ended June 30, 2009, respectively, partially offset by higher unrealized gains related to hedge contracts (described below) and lower plant operations expense. Realized gross margin was affected by the following factors:

•

lower average realized energy prices and lower generation due to lower energy prices and increased congestion affecting the Northern Illinois control area;

•

higher fuel costs primarily due to annual NOX emission allowance costs commencing in January 2009, operation of mercury controls and an increase in the cost of coal; and

•

partially offsetting the above, higher capacity revenue primarily due to higher capacity prices in the RPM auction.

In addition, earnings were lower for the six months ended June 30, 2009 due to a gain of $15 million recorded in 2008 related to the buyout of a fuel contract and an estimated insurance recovery of approximately $6 million recorded in 2008 primarily related to the outages at the Powerton Station.

Included in operating revenues were unrealized gains (losses) of $5 million and $(3) million for the second quarters of 2009 and 2008, respectively, and $20 million and $(8) million for the six months ended June 30, 2009 and 2008, respectively. Unrealized gains in 2009 were primarily due to hedge contracts that are not accounted for as cash flow hedges under SFAS No. 133 (referred to as economic hedges). Unrealized losses in 2008 were primarily due to the ineffective portion of hedge contracts at the Illinois Plants attributable to changes in the difference between energy prices at NiHub (the settlement point under forward contracts) and the energy prices at the Illinois Plants busbars (the delivery point where power generated by the Illinois Plants is delivered into the transmission system) resulting from marginal losses. Included in fuel expenses were unrealized gains of $14 million for the second quarter and six months ended June 30, 2009 due to oil futures contracts that were accounted for as economic hedges. The contracts were entered into to hedge a portion of a fuel adjustment provision of a rail transportation contract. For more information regarding forward market prices and unrealized gains (losses), see "EMG: Market Risk Exposures—Commodity Price Risk" and "EMG: Market Risk Exposures—Accounting for Derivative Instruments," respectively.

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Homer City

The following table presents additional data for the Homer City facilities:

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Operating Revenues			$	161		$	127		$	326		$	312
Operating Expenses
	Fuel(1)			63			52			127			124
	Loss on sale of emission allowances(2)			1			—			1			—
	Plant operations			21			57			55			86
	Plant operating leases			25			26			50			51
	Depreciation and amortization			3			4			8			8
	Administrative and general			1			1			2			2
	Total operating expenses			114			140			243			271
Operating Income (Loss)				47			(13	)		83			41
Other Income				—			—			—			—
Adjusted Operating Income (Loss)(3)			$	47		$	(13	)	$	83		$	41
Statistics
	Generation (in GWh)			3,025			2,250			5,683			5,442
	Equivalent availability(4)			90.5	%		61.6	%		83.7	%		74.6	%
	Capacity factor(5)			73.4	%		54.6	%		69.3	%		66.0	%
	Load factor(6)			81.1	%		88.7	%		82.8	%		88.6	%
	Forced outage rate(7)			7.0	%		12.1	%		9.5	%		10.6	%
	Average realized energy price/MWh(8)		$	46.24		$	53.81		$	51.29		$	55.06
	Capacity revenue only (in millions)		$	18		$	11		$	30		$	19
	Average fuel costs/MWh		$	20.91		$	23.23		$	22.36		$	22.84

(1)

Included in fuel costs were $1 million and $2 million during the second quarters of 2009 and 2008, respectively, and $8 million and $7 million during the six months ended June 30, 2009 and 2008, respectively, related to the net cost of emission allowances. For more information regarding the price of emission allowances, see "EMG: Market Risk Exposures—Commodity Price Risk—Emission Allowances Price Risk."

(2)

The Homer City facilities sold seasonal NO_X emission allowances to the Illinois Plants at fair market value. Sales to the Illinois Plants were $1 million during the six months ended June 30, 2009. These sales reduced operating expenses. EME recorded $1 million of intercompany loss during the second quarter of 2009 related to emission allowances sold by the Homer City facilities to the Illinois Plants during the first quarter of 2009, but not used by the Illinois Plants until the second quarter of 2009.

(3)

As described above, adjusted operating income (loss) is equal to operating income (loss) plus other income. Adjusted operating income (loss) is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of other income is more meaningful for investors as the components of other income are integral to the results of the Homer City facilities.

(4)

The equivalent availability factor is defined as the number of MWh the coal plants are available to generate electricity divided by the product of the capacity of the coal plants (in MW) and the

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number of hours in the period. Equivalent availability reflects the impact of the unit's inability to achieve full load, referred to as derating, as well as outages which result in a complete unit shutdown. The coal plants are not available during periods of planned and unplanned maintenance.

(5)

The capacity factor is defined as the actual number of MWh generated by the coal plants divided by the product of the capacity of the coal plants (in MW) and the number of hours in the period.

(6)

The load factor is determined by dividing capacity factor by the equivalent availability factor.

(7)

Homer City refers to unplanned maintenance as a forced outage.

(8)

The average realized energy price reflects the average price at which energy is sold into the market including the effects of hedges, real-time and day-ahead sales and PJM fees and ancillary services. It is determined by dividing (i) operating revenue less unrealized gains (losses) and other non-energy related revenue by (ii) total generation as shown in the table below. Revenue related to capacity sales are excluded from the calculation of average realized energy price.

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Operating revenues			$	161		$	127		$	326		$	312
Less:
	Unrealized (gains) losses			(5	)		6			(5	)		7
	Capacity and other revenues			(17	)		(11	)		(30	)		(19	)
Realized revenues			$	139		$	122		$	291		$	300
Generation (in GWh)				3,025			2,250			5,683			5,442
Average realized energy price/MWh			$	46.24		$	53.81		$	51.29		$	55.06

The average realized energy price is presented as an aid in understanding the operating results of the Homer City facilities. Average realized energy price is a non-GAAP performance measure since such statistical measure excludes unrealized gains or losses recorded as operating revenues. Management believes that the average realized energy price is more meaningful for investors as it reflects the impact of hedge contracts at the time of actual generation in period-over-period comparisons or as compared to real-time market prices. A reconciliation of the Homer City facilities operating revenues presented above to consolidated operating revenues is set forth below.

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Operating revenues:
	Illinois Plants		$	340		$	391		$	724		$	859
	Homer City facilities			161			127			326			312
	Renewable energy projects			31			34			75			50
	Other revenues			25			61			44			111
Consolidated operating revenues as reported			$	557		$	613		$	1,169		$	1,332

Earnings from Homer City increased $60 million and $42 million for the second quarter and six months ended June 30, 2009, compared to the corresponding periods of 2008. The second quarter increase in

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earnings was primarily attributable to higher realized gross margin and lower plant maintenance expenses. The increase in realized gross margin was primarily due to higher capacity revenues and higher generation (driven primarily by higher availability), partially offset by lower average realized energy prices. The year-to-date increase in earnings was primarily attributable to lower plant maintenance expenses. In 2008, higher forced outages, lower off-peak dispatch and extended planned overhauls contributed to lower generation and higher maintenance expenses.

Seasonal Disclosure

Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the Illinois Plants and the Homer City facilities vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall) further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, earnings from the Illinois Plants and the Homer City facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Illinois Plants" and "—Energy Price Risk Affecting Sales from the Homer City Facilities."

Renewable Energy Projects

The following table presents additional data for EME's renewable energy projects:

				Three Months Ended June 30,						Six Months Ended June 30,
In millions				2009			2008			2009			2008
Operating Revenues				$	31		$	34		$	75		$	50
Production Tax Credits					14			11			30			20
					45			45			105			70
Operating Expenses
		Plant operations			12			8			25			14
		Depreciation and amortization			21			12			41			22
		Administrative and general			1			1			2			2
		Total operating expenses			34			21			68			38
Other Income					—			1			—			1
Adjusted Operating Income(1)				$	11		$	25		$	37		$	33
Statistics
	Generation (in GWh)				718			565			1,538			1,065
	Aggregate plant performance:
		Equivalent availability			87.3	%		81.8	%		84.2	%		83.2	%
		Capacity factor			30.5	%		36.4	%		33.4	%		37.1	%

(1)

Adjusted operating income is equal to operating income (loss) plus production tax credits and other income. Production tax credits are recognized as wind energy is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. Accordingly, adjusted operating income represents a non-GAAP performance measure which may not be comparable to those of other companies. Management believes that inclusion of production tax credits in adjusted operating income for wind projects is more meaningful for investors as federal

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and state subsidies are an integral part of the economics of these projects. The following table reconciles adjusted operating income as shown above to operating income (loss) under GAAP:

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Adjusted Operating Income			$	11		$	25		$	37		$	33
Less:
	Production tax credits			14			11			30			20
	Other income (expense)			—			1			—			1
Operating Income (Loss)			$	(3	)	$	13		$	7		$	12

Earnings from renewable energy projects decreased $14 million and increased $4 million for the second quarter and six months ended June 30, 2009, compared to the corresponding periods of 2008. The second quarter decrease in earnings was primarily due to cumulative liquidated damages related to Suzlon wind turbines being recorded during the second quarter of 2008. Earnings for the second quarter of 2009 and 2008 included $5 million and $13 million, respectively, of liquidated damages for availability guarantees provided by Suzlon Wind Energy Corporation. The year-to-date increase in earnings was primarily due to new projects that commenced operations in the last six months of 2008. Earnings for the six months ended June 30, 2009 and 2008 included $16 million and $13 million, respectively, of the Suzlon liquidated damages. At June 30, 2009, EME had a receivable from this vendor of $20 million.

Energy Trading

EME seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, and transmission congestion primarily in the eastern power grid using products available over the counter, through exchanges, and from ISOs. Earnings from energy trading activities decreased $34 million and $65 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. The 2009 decreases in earnings from energy trading activities were primarily attributable to lower congestion in the eastern power grid resulting primarily from lower electrical load.

Earnings from Unconsolidated Affiliates

Big 4 Projects

Earnings from the Big 4 projects decreased $17 million and $19 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. Lower earnings in 2009 were primarily due to lower natural gas prices affecting electricity and steam revenues. Partially offsetting these decreases was an increase in earnings from the Kern River project due to a planned outage in 2008. For further discussion regarding power sales from the Midway-Sunset, Sycamore and Watson projects, all of which are selling power to SCE under the terms and conditions contained in their prior long-term power purchase agreements, with revised pricing terms as mandated by CPUC Decision 07-09-040, dated September 20, 2007, and a description of the dispute between SCE and Watson.

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Sunrise

Earnings from the Sunrise project decreased $4 million for the six months ended June 30, 2009, compared to the corresponding period of 2008. The 2009 year-to-date decrease was primarily due to a planned outage in the first quarter of 2009.

March Point

During the second quarter and six months ended June 30, 2009, EME recorded its share of equity in income of $1 million and $3 million, respectively, from the March Point project. During the first quarter of 2009, EME commenced recording its share of equity in income from the March Point project. Previously, EME suspended equity accounting since 2005 when its investment in the March Point project was fully impaired. Declining natural gas prices reduced fuel expenses and returned the project to profitability. To the extent that cash is received from the project in excess of EME's investment, such amount will be recorded as equity in income.

Seasonal Disclosure

EME's third quarter equity in income from its energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME's energy projects located on the West Coast have power sales contracts that provide for higher payments during the summer months.

Interest Related Income (Expense)

				Three Months Ended June 30,						Six Months Ended June 30,
In millions				2009			2008			2009			2008
Interest income				$	3		$	7		$	6		$	15
Interest expense:
	EME debt			$	(68	)	$	(61	)	$	(136	)	$	(123	)
	Non-recourse debt:
		Midwest Generation			(2	)		—			(5	)		(7	)
		EME CP Holding Co.			(1	)		(2	)		(2	)		(3	)
		Other project			(2	)		(3	)		(4	)		(4	)
				$	(73	)	$	(66	)	$	(147	)	$	(137	)

Interest Income

EME's interest income decreased $4 million and $9 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008. The decreases were primarily attributable to lower interest rates in 2009 compared to 2008.

Interest Expense

EME's interest expense to third parties, before capitalized interest, increased $2 million for both the second quarter and six months ended June 30, 2009, compared to the corresponding periods of 2008. The increases were primarily due to higher debt balances under EME's and Midwest Generation's credit facilities in 2009, compared to 2008. Capitalized interest decreased $5 million and $8 million for the second quarter and six months ended June 30, 2009, respectively, compared to the corresponding periods of 2008, due to a reduction in projects under construction.

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Income Taxes

EME's income tax provision from continuing operations was $17 million and $116 million for the six months ended June 30, 2009 and 2008, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the six months ended June 30, 2009 and 2008, EME recognized $30 million and $20 million, respectively, of production tax credits related to wind projects. In addition, EME recognized additional income tax benefits of $1 million and $3 million during the six months ended June 30, 2009 and 2008, respectively, related to estimated additional taxes or benefits allocated from Edison International. Effective January 1, 2009, the state of Massachusetts changed its tax regulations from a separate return basis, where each entity files separately, to a combined return basis where Edison International and its subsidiaries file together.

In May 2009, Edison International and the Internal Revenue Service completed a settlement of federal tax disputes and affirmative claims for open tax years 1986 through 2002. The settlement includes resolution of issues pertaining to EME which were largely timing in nature. During the second quarter of 2009, EME recorded an income tax benefit of $6 million due to the settlement and related estimated impact of interest and state income taxes. The amount recorded is subject to change based on the final determination of interest and state taxes and items affected under the tax-allocation agreement.

Results of Discontinued Operations

Loss from discontinued operations, net of tax, was $7 million and $1 million for the second quarters of 2009 and 2008, respectively, and $4 million and $6 million for the six months ended June 30, 2009 and 2008, respectively. The losses in 2009 and 2008 included foreign exchange gains (losses) and interest associated with contract indemnities related to EME's sale of its international projects in December 2004. In addition, EME increased its estimated liability for a tax indemnity by $6 million during the second quarter of 2009.

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Financial Services and Other (Edison Capital and other EMG subsidiaries) Net Income (Loss)

The following table sets forth the major changes in financial services and other net income (loss):

			Three Months Ended June 30,						Six Months Ended June 30,
In millions			2009			2008			2009			2008
Financial services and other operating revenue			$	5		$	15		$	17		$	29
Other operation and maintenance				3			1			5			2
Depreciation, decommissioning and amortization				2			1			2			2
Lease terminations and other				867			(49	)		888			(49	)
Total operating expenses				872			(47	)		895			(45	)
Operating Income (Loss)				(867	)		62			(878	)		74
Interest and dividend income				1			2			5			5
Equity in income (loss) from partnerships and
	unconsolidated subsidiaries – net			(3	)		(1	)		(11	)		(3	)
Other Nonoperating Income				(2	)		1			(5	)		—
Interest expense – net of amounts capitalized				(4	)		(2	)		(4	)		(4	)
Income (loss) from continuing operations before income taxes				(875	)		62			(893	)		72
Income tax expense (benefit)				(277	)		23			(287	)		24
Income (loss) from continuing operations				(598	)		39			(606	)		48
Income (loss) from discontinued operations – net of tax				—			—			—			—
Net income (loss)				(598	)		39			(606	)		48
Less: Net income attributable to noncontrolling interests				—			—			—			—
Financial services and other net income (loss) attributable to Edison International			$	(598	)	$	39		$	(606	)	$	48

Lease Termination and Other

Pursuant to an agreement reached with the Internal Revenue Service, Edison Capital terminated its interests in cross-border leases during the first half of 2009 (see "Edison International: Management Overview—Areas of Business Focus—Federal and State Income Taxes—Global Settlement" and "Off-Balance Sheet Transactions" for further discussion). The net proceeds and loss, before income tax, from termination of the cross-border leases were $1.385 billion and $920 million, respectively. The after-tax loss on termination of the cross-border leases, including the federal and state income tax impact of the Global Settlement, was $628 million. In addition, Edison Capital sold its interest in another leverage lease transaction, Midland Cogeneration Ventures, during the three months ended June 30, 2009 and recorded a pre-tax gain on sale of $33 million ($20 million after tax).

In March 2008, First Energy exercised an early buyout right under the terms of an existing lease agreement with Edison Capital related to Unit No. 2 of the Beaver Valley Nuclear Power Plant. The termination date of the lease under the early buyout option was June 1, 2008. Proceeds from the sale were $72 million. Edison Capital recorded a pre-tax gain of $41 million ($23 million after tax) during the second quarter of 2008.

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Income Tax Expense

The composite federal and state statutory income tax rate was approximately 40% (net of federal benefit of state income taxes) for all periods presented. The lower effective tax rate of 32% for the six months ended June 30, 2009, as compared to the statutory rate, was primarily due to the impacts of the Global Settlement. The lower effective tax rate of 33% for the six months ended June 30, 2008, as compared to the statutory rate, was primarily due to low income housing tax credits.

EDISON INTERNATIONAL (CONSOLIDATED) HISTORICAL CASH FLOW ANALYSIS

The "Historical Cash Flow Analysis" section of this MD&A discusses consolidated cash flows from operating, financing and investing activities.

Cash Flows from Operating Activities

Net cash provided (used) by operating activities is as follows:

		Six Months Ended June 30,
In millions		2009			2008
Continuing operations		$	887		$	739
Discontinued operations			(4	)		(6	)
Total		$	883		$	733

Cash provided by operating activities from continuing operations increased $148 million in 2009 compared to 2008. The 2009 change was primarily due to the impacts of the Global Settlement which resulted in remittances of approximately $195 million to the IRS and the Franchise Tax Board and reductions in deferred tax liabilities related to the termination of Edison Capital's interests in cross-border leases partially offset by increases in deferred tax liabilities at SCE related to the settlement of affirmative claims (see "Edison International: Management Overview—Areas of Business Focus—Federal and State Income Taxes" for further discussion). The 2009 change was also due to a net $225 million cash inflow related to balancing account activities mainly due to: ERRA balancing account collections in 2009, compared to ERRA balancing account refunds in 2008; partially offset by $200 million in refund payments received in 2008 related to SCE's public purpose programs with no comparable refunds in 2009; and a net under-collection of other balancing accounts in 2009, compared to a net over-collection in 2008. The ERRA balancing account was under-collected by $184 million and $406 million at June 30, 2009 and December 31, 2008, respectively, compared to an under-collection of $95 million and an over-collection of $433 million at June 30, 2008 and December 31, 2007, respectively. The 2009 change was also attributable to the timing of cash receipts and disbursements related to working capital items, including margin deposits received from counterparties related to hedge activities at June 30, 2009, net of the restricted cash balances under margin agreements.

Cash Flows from Financing Activities

Net cash provided (used) by financing activities is as follows:

		Six Months Ended June 30,
In millions		2009			2008
Continuing operations		$	(1,820	)	$	444
Total		$	(1,820	)	$	444

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Cash provided (used) by financing activities from continuing operations mainly consisted of net repayments of short-term debt and long-term debt issuances (payments) at SCE and EMG and dividends paid by Edison International to its common shareholders.

Financing activities for the first six months of 2009 were as follows:

•

In June 2009, EME completed through its subsidiary, Viento Funding II, Inc., a non-recourse portfolio financing of its interest in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The portfolio financing included a $189 million seven-year term loan. For further details of this financing, see "—Wind Financing." The proceeds of the financing, net of financing costs, were distributed to EME.

•

In March 2009, SCE issued $500 million of first refunding mortgage bonds due in 2039 and $250 million of first and refunding mortgage bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories.

•

In March 2009, SCE purchased two issues of its tax-exempt pollution control bonds totaling approximately $219 million and converted the issues to a variable rate structure. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

•

In February 2009, SCE repaid $150 million of its first and refunding mortgage bonds.

•

During the first six months of 2009, SCE's net repayments of short-term debt were $1.9 billion.

•

During the first six months of 2009, Edison International's (parent) net repayments of short-term debt were $173 million.

•

Other financing activities in 2009 include dividend payments of $202 million paid by Edison International to its common shareholders and payments of $6 million for the purchase and delivery of outstanding common stock for settlement of stock based awards (facilitated by a third party).

Financing activities for the first six months of 2008 were as follows:

•

In January, SCE issued $600 million of first refunding mortgage bonds due in 2038. The proceeds were used to repay SCE's outstanding commercial paper of approximately $426 million and for general corporate purposes.

•

In January, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 per share. SCE retired this preferred stock in January 2008 and recorded a $2 million gain on the cancellation of reacquired capital stock (reflected in the caption "Common stock" on the consolidated balance sheets).

•

During the first quarter of 2008, SCE purchased $212 million of its auction rate bonds, converted the issue to a variable rate structure, and terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

•

During the first six months of 2008, SCE's net issuances of commercial paper classified as short-term debt was $300 million.

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•

Other financing activities in 2008 include dividend payments of $199 million paid by Edison International to its common shareholders and payments of $51 million for the purchase and delivery of outstanding common stock for settlement of stock based awards (facilitated by a third party).

Cash Flows from Investing Activities

Net cash used by investing activities is as follows:

		Six Months Ended June 30,
In millions		2009			2008
Continuing operations		$	(278	)	$	(1,548	)
Total		$	(278	)	$	(1,548	)

Cash flows from investing activities are affected by capital expenditures, Edison Capital's proceeds from termination of leases, SCE's funding of nuclear decommissioning trusts, and proceeds and maturities of investments.

Investing activities in 2009 reflect $1.385 billion of net proceeds from termination of the cross-border leases (see "Other Developments—Federal and State Income Taxes" for further discussion). Investing activities in 2009 also reflect $1.4 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $52 million for nuclear fuel acquisitions, and $138 million in capital expenditures at EMG. Investing activities also include net purchases of nuclear decommissioning trust investments of $105 million.

Investing activities in 2008 reflect $1.2 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $55 million for nuclear fuel acquisitions, and $218 million in capital expenditures at EMG. Investing activities also include net maturities and sales of short-term investments of $68 million and net purchases of nuclear decommissioning trust investments and other of $59 million, and proceeds from the sale of 33% of EME's membership in the Elkhorn Ridge wind project during the second quarter of 2008.

NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements are discussed in Note 1—Summary of Significant Accounting Policies—New Accounting Pronouncements under "Edison International's Notes to Consolidated Financial Statements."

COMMITMENTS, GUARANTEES AND INDEMNITIES

The following is an update to Edison International's commitments, guarantees and indemnities. See the section, "Commitments, Guarantees and Indemnities" in the year-ended 2008 MD&A for a detailed discussion.

Fuel Supply Contracts

At June 30, 2009, Midwest Generation and EME Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices subject to adjustment clauses, these minimum commitments are currently estimated to aggregate $417 million, summarized as follows: remainder of 2009 – $230 million, 2010 – $177 million, and 2011 – $10 million.

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In July 2009, Midwest Generation entered into additional contractual agreements for the purchase of coal. These commitments, together with the estimated transportation costs under the existing agreements through 2011, are currently estimated to be $136 million for 2010, $264 million for 2011 and $134 million for 2012.

Turbine Commitments

EME had entered into various turbine supply agreements with vendors to support its wind development efforts. At June 30, 2009, EME had secured the rights to 484 wind turbines (942 MW) for use in future projects for an aggregate purchase price of $1.2 billion, with remaining commitments of $596 million in 2009 and $242 million in 2010. At June 30, 2009, EME had recorded wind turbine deposits of $410 million, included in other long-term assets on its consolidated balance sheet. EME has executed non-binding letter agreements with two of its vendors to provide vendor financing. EME and such vendors are in the process of negotiating definitive agreements based on the non-binding letter agreements, but there is no assurance that final binding agreements will be executed or executed on terms that conform to the letter agreements. If definitive agreements are executed substantially in accordance with the terms of the letter agreements, turbine commitments would be reduced to approximately $191 million in 2009, $229 million in 2010, and $210 million in 2011, and the remaining $206 million due based on specified conditions (expected during the time period of 2011 and 2014). These commitments would be further reduced during this period if a third turbine supplier agrees to provide vendor financing. Furthermore, EME can elect under the existing turbine supply agreement with this supplier to terminate the agreement for convenience which would further reduce turbine commitments to $9 million in 2009 and $49 million in 2010 (in such case, EME would write off approximately $90 million in previously made non-refundable deposits).

Capital Improvements

At June 30, 2009, EME's subsidiaries had firm commitments to spend approximately $110 million during the remainder of 2009 and $14 million in 2010 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects and non-environmental improvements at both the Illinois Plants and the Homer City facilities. These expenditures are planned to be financed by cash on hand and cash generated from operations.

Other Commitments

During the second quarter of 2009, SCE extended its power purchase agreement with Midway Sunset which resulted in additional commitments estimated to be: remainder of 2009 – $13 million, 2010 – $18 million, 2011 – $18 million, 2012 – $18 million and thereafter – $129 million.

Uncertain Tax Position Net Liability

At June 30, 2009, Edison International recorded a liability for uncertain tax positions of $609 million. Edison International currently cannot reliably predict the timing of cash flows associated with the resolution of uncertain tax positions due to timing of resolving tax issues with the IRS. Edison International's federal income tax returns are subject to examination by the IRS for tax years 2003 to present. Consummation of the Global Settlement effectively closed the examination for tax years 1986 - 2002 and resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases in their entirety (see "Edison International: Management Overview—Areas of Business Focus—Federal and State Income Taxes"). In addition to the IRS audits, Edison International's California and other state income tax returns are open for examination by the California Franchise Tax Board and other state tax authorities for tax years 1986 to present.

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OFF-BALANCE SHEET TRANSACTIONS

The following is an update to Edison International's off-balance sheet transactions. See the section, "Off-Balance Sheet Transactions" in the year-ended 2008 MD&A for a detailed discussion.

Leveraged Leases

As of June 30, 2009, Edison Capital is the lessor in various power generation aircraft leveraged leases. The debt ($255 million as of June 30, 2009) in these leveraged leases is nonrecourse to Edison Capital and is not recorded on Edison International's balance sheet in accordance with SFAS No. 13, "Accounting for Leases."

Pursuant to an agreement with the Internal Revenue Service, Edison Capital terminated its interests in cross-border leases during the first half of 2009 (see "Edison International: Management Overview—Areas of Business Focus—Federal and State Income Taxes—Global Settlement" for further discussion). The net proceeds and loss, before income tax, from termination of the cross-border leases were $1.385 billion and $920 million, respectively. The after-tax loss on termination of the cross-border leases, as well as the federal and state income tax impact of the Global Settlement, was $628 million. In addition, Edison Capital sold its interest in another leverage lease transaction during the three months ended June 30, 2009 and recorded a pre-tax gain on sale of $33 million ($20 million after tax).

The net investment in leveraged leases is:

In millions		June 30, 2009			December 31, 2008
		(Unaudited)
Rental receivables – net		$	189		$	3,227
Estimated residual value			21			42
Unearned income			(44	)		(802	)
Investments in leveraged leases		$	166		$	2,467
Deferred income taxes			(155	)		(2,313	)
Net investments in leveraged leases		$	11		$	154

OTHER DEVELOPMENTS

Environmental Matters

Air Quality Regulation

New Source Review Requirements – Four Corners Section 114 Information Request

In April 2009, APS received a US EPA request pursuant to Section 114 of the CAA for information about Four Corners, where SCE is 48% owner of generating units 4 and 5 of Four Corners and APS is a part owner and the operating agent. The US EPA requested information about the Four Corners plant and its operations, including information about Four Corners capital projects from 1990 to the present. APS is now in the process of providing requested information to the US EPA according to a schedule that was agreed upon with the US EPA. SCE understands that in other cases the US EPA has utilized similar Section 114 letters for examining whether power plants have triggered New Source Review requirements under the CAA and are therefore potentially subject to more stringent air pollution control requirements. However, other than this request for information, no New Source Review enforcement-related proceedings have been initiated by the US EPA with respect to Four Corners. SCE cannot predict the outcome of this inquiry.

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Pennsylvania

The PADEP opacity regulations limit stack opacity to 20% on a one-minute average. PADEP's prior policy recognized the occurrence of transient exceedances of the standard, and allowed such exceedances within certain parameters (below 30% opacity and up to 1.5% of a unit's operating time). On April 18, 2009, the PADEP changed its opacity policy, eliminating many exemptions and reducing the allowable exceedance rate to 0.5% of a unit's operating time, effective as of April 1, 2009. EME has undertaken optimization of unit ramp rates and combustion parameters at the Homer City facilities to reduce the deratings required to meet the opacity standards. Additional capital improvements may also be required. EME Homer City has operated below the 0.5% exceedance rate during the second quarter of 2009.

Water Quality Regulation

Clean Water Act – Cooling Water Standards and Regulations

In January 2007, the Second Circuit rejected the US EPA rule on cooling water intake structures and remanded it to the US EPA. Among the key provisions remanded by the court were the use of cost-benefit analysis for determining the best technology available and the use of restoration to achieve compliance with the rule. On July 2007, the US EPA suspended the requirements for cooling water intake structures, pending further rulemaking. In April 2009, the U.S. Supreme Court reversed the Second Circuit and held that the US EPA may consider, but is not required to use, cost-benefit analysis in formulating regulations under Clean Water Act Section 316(b). The Court did not grant review of the Second Circuit's rejection of the use of restoration as compliance, which means the Second Circuit decision on this issue remains valid. It is unknown whether the US EPA will use cost-benefit analysis when it revises the regulations.

In June 2009 the California State Water Resources Control Board released its draft "Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling." SCE is currently reviewing the draft policy.

Environmental Remediation

Edison International is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

Possible future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that additional costs would be recovered from customers or that Edison International's results of operations, financial position or cash flow would not be materially affected.

Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International records the lower end of this reasonably likely range of costs (classified as "Other long-term liabilities") at undiscounted amounts.

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As of June 30, 2009, Edison International's recorded estimated minimum liability to remediate its 30 identified sites at SCE (24 sites) and EME (6 sites primarily related to Midwest Generation) was $43 million, $39 million of which was related to SCE including $6 million related to San Onofre. Edison International's other subsidiaries have no identified remediation sites. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $178 million, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 31 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $29 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $39 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $11 million to $30 million. Recorded costs were $2 million and $7 million for the three months ended June 30, 2009 and 2008, respectively, and were $5 million and $10 million for the six months ended June 30, 2009 and 2008, respectively.

Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flow. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information responding to Part I, Item 3 is included in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," under the headings "SCE: Market Risk Exposures" and "EMG: Market Risk Exposures."

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

Edison International's management, under the supervision and with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of Edison International's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, Edison International's disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There were no changes in Edison International's internal control over financial reporting (as that term is defined in Rules 13(a)-15(f) or 15(d)-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, Edison International's internal control over financial reporting.

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PART II. – OTHER INFORMATION

Item 1. Legal Proceedings

Catalina South Coast Air Quality Management District Potential Environmental Proceeding

During the first half of 2006, the South Coast Air Quality Management District (SCAQMD) issued three NOVs alleging that Unit 15, SCE's primary diesel generation unit on Catalina Island, had exceeded the NO_x emission limit dictated by its air permit. Prior to the NOVs, SCE had filed an application with the SCAQMD seeking a permit amendment that would allow a three-hour averaging of the NO_x limit during normal (non-startup) operations and clarification regarding a startup exemption. In July 2006, the SCAQMD denied SCE's application to amend the Unit 15 air permit, and informed SCE that several conditions would have to be satisfied prior to re-application. SCE is currently in the process of developing and supplying the information and analyses required by those conditions.

On October 2, 2006 and July 19, 2007, SCE received two additional NOVs pertaining to two other Catalina Island diesel generation units, Unit 7 and Unit 10, alleging that these units have exceeded their annual NO_x limit in 2004 (Unit 10), 2005 (Unit 7), and 2006 (Unit 10). Going forward, SCE expects that the new Continuous Emissions Monitoring System, installed in late 2006, which monitors the emissions from these units, along with the employment of best practices, would enable these units to meet their annual NO_x limits in 2007.

In July 2008, SCE received an additional NOV for emitting NO_x in excess of SCE's Regional Clean Air Incentives Market (RECLAIM) credits. Under the RECLAIM program, a RECLAIM-regulated facility must have sufficient RECLAIM Trading Credits to equal the amount of NO_x that the facility emits. The NOV alleges that SCE did not have sufficient RECLAIM Trading Credits in the first and second quarters of 2007 to match the actual NO_x emissions at Catalina's generating units.

A settlement agreement, which resolves all of the NOVs, was fully executed in April 2009 and requires SCE to install new equipment by December 31, 2011 or pay a $3 million fine if the equipment is not installed by that date. The settlement agreement also provides that if SCE's application for a permit amendment is not granted, the parties will not be bound by the terms of the settlement. SCE continues to work with the SCAQMD on the permit amendment process.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(c) Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table contains information about all purchases made by or on behalf of Edison International or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) of shares or other units of any class of Edison International's equity securities that is registered pursuant to Section 12 of the Exchange Act.

Period		(a) Total Number of Shares (or Units) Purchased(1)			(b) Average Price Paid per Share (or Unit)(1)			(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs			(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1, 2009 to April 30, 2009			520,763		$	28.06			—			—
May 1, 2009 to May 31, 2009			435,815		$	28.60			—			—
June 1, 2009 to June 30, 2009			525,567		$	31.54			—			—
Total			1,482,145		$	29.45			—			—

(1)

The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's (i) 401(k) Savings Plan, (ii) Dividend Reinvestment and Direct Stock Purchase Plan, and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions.

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Item 4. Submission of Matters to a Vote of Security Holders

At Edison International's Annual Meeting of Shareholders on April 23, 2009, four matters were put to a vote of the shareholders: the election of eleven directors, ratification of the appointment of the independent registered public accounting firm, a management proposal to approve an amendment to the Edison International 2007 Performance Incentive Plan, and a shareholder proposal on "Shareholder Say on Executive Pay."

Shareholders elected eleven nominees to the Board of Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for and withheld from each Director-nominee were as follows:

		Number of Votes
Name		For			Withheld
Vanessa C.L. Chang			268,297,090			6,824,331
France A. Córdova			268,492,794			6,628,627
Theodore F. Craver, Jr.			262,095,820			13,025,601
Charles B. Curtis			268,838,728			6,282,693
Bradford M. Freeman			266,213,481			8,907,940
Luis G. Nogales			266,889,819			8,231,602
Ronald L. Olson			252,912,549			22,208,872
James M. Rosser			265,500,666			9,620,755
Richard T. Schlosberg, III			266,102,762			9,018,659
Thomas C. Sutton			265,217,758			9,903,663
Brett White			266,586,355			8,535,066

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The proposal to ratify the appointment of the independent registered public accounting firm, which received the affirmative vote of a majority of the votes cast, was adopted. The proposal received the following numbers of votes:

For		Against		Abstentions		Broker Non-Votes
268,061,962		5,140,603		1,918,856		0

The management proposal to amend the Edison International 2007 Performance Incentive Plan, which received the affirmative vote of a majority of the votes cast, was adopted. The proposal received the following numbers of votes:

For		Against		Abstentions		Broker Non-Votes
196,631,673		42,141,957		2,796,052		33,551,739

The shareholder proposal on "Shareholder Say on Executive Pay," which received the affirmative vote of a majority of the votes cast, was adopted. The proposal received the following numbers of votes:

For		Against		Abstentions		Broker Non-Votes
121,342,974		115,370,608		4,856,100		33,551,739

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Item 6. Exhibits

Edison International

	10.1		Edison International Executive Incentive Compensation Plan, as amended on February 25, 2009
	10.2		Edison International Director Compensation Schedule, as adopted June 18, 2009
	10.3		Edison International 2007 Performance Incentive Plan, as amended and restated as of February 26, 2009
	31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
	31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
	32		Statement Pursuant to 18 U.S.C. Section 1350
	101		Financial statements from the quarterly report on Form 10-Q of Edison International for the quarter ended June 30, 2009, filed on August 7, 2009, formatted in XBRL: (i) the Consolidated Statements of Income (Loss); (ii) the Consolidated Statements of Comprehensive Income (Loss); (iii) the Consolidated Balance Sheets; and (iv) the Notes to the Consolidated Financial Statements tagged as blocks of text

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	EDISON INTERNATIONAL             (Registrant)
	By:		/s/ LINDA G. SULLIVAN LINDA G. SULLIVAN Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

Date: August 7, 2009

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