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

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:

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


AB		Assembly Bill
AFUDC		allowance for funds used during construction
APS		Arizona Public Service Company
ARO(s)		asset retirement obligation(s)
Bcf		billion cubic feet
Big 4		Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
Btu		British thermal units
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
CAMR		Clean Air Mercury Rule
CARB		California Air Resources Board
Commonwealth Edison		Commonwealth Edison Company
CDWR		California Department of Water Resources
CEC		California Energy Commission
CONE		cost of new entry
CPS		Combined Pollutant Standard
CPUC		California Public Utilities Commission
CRRs		congestion revenue rights
DCR		Devers-Colorado River
DOE		United States Department of Energy
DOJ		United States Department of Justice
DRA		Division of Ratepayer Advocates
DWP		Los Angeles Department of Water & Power
EME		Edison Mission Energy
EME Homer City		EME Homer City Generation L.P.
EMG		Edison Mission Group Inc.
EMMT		Edison Mission Marketing & Trading, Inc.
EPS		earnings per share
ERRA		energy resource recovery account
Exelon Generation		Exelon Generation Company LLC
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGIC		Financial Guarantee Insurance Company
Fitch		Fitch Ratings
FTRs		firm transmission rights
GAAP		generally accepted accounting principles
GHG		greenhouse gas


Global Settlement		A settlement between Edison International and the IRS that resolved asserted deficiencies related to Edison International's deferral of income taxes associated with certain of its cross-border, leveraged leases in their entirety and all other outstanding tax disputes for open tax years 1986 through 2002.
GRC		General Rate Case
GWh		gigawatt-hours
Illinois Plants		EME's largest power plants (fossil fuel) located in Illinois
Investor-Owned Utilities		SCE, SDG&E and PG&E
IRS		Internal Revenue Service
ISO		Independent System Operator
kWh(s)		kilowatt-hour(s)
LIBOR		London Interbank Offered Rate
MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations
MEHC		Mission Energy Holding Company
Midwest Generation		Midwest Generation, LLC
MMBtu		million British thermal units
Mohave		Mohave Generating Station
Moody's		Moody's Investors Service
MRTU		Market Redesign and Technology Upgrade
MW		megawatts
MWh		megawatt-hours
NAPP		Northern Appalachian
Ninth Circuit		United States Court of Appeals for the Ninth Circuit
NOV		notice of violation
NO_x		nitrogen oxide
NRC		Nuclear Regulatory Commission
PADEP		Pennsylvania Department of Environmental Protection
Palo Verde		Palo Verde Nuclear Generating Station
PBOP(s)		Postretirement benefits other than pension(s)
PBR		performance-based ratemaking
PG&E		Pacific Gas & Electric Company
PJM		PJM Interconnection, LLC
POD		Presiding Officer's Decision
PRB		Powder River Basin
PSD		Prevention of Significant Deterioration
PX		California Power Exchange
QF(s)		qualifying facility(ies)
RICO		Racketeer Influenced and Corrupt Organization
ROE		return on equity
RPM		reliability pricing model
S&P		Standard & Poor's Ratings Services
San Onofre		San Onofre Nuclear Generating Station
SCAQMD		South Coast Air Quality Management District

	Three Months Ended September 30,						Nine Months Ended September 30,


In millions, except per-share amounts	2009			2008			2009			2008

	(Unaudited)
Electric utility	$	3,065		$	3,467		$	7,526		$	8,696
Competitive power generation		592			813			1,759			2,143
Financial services and other		7			14			25			45

Total operating revenue		3,664			4,294			9,310			10,884

Fuel		406			635			1,120			1,725
Purchased power		1,032			1,333			2,155			3,053
Other operation and maintenance		1,093			1,035			3,136			3,110
Depreciation, decommissioning and amortization		365			327			1,053			972
Lease terminations and other		—			(1	)		888			(75	)

Total operating expenses		2,896			3,329			8,352			8,785

Operating income		768			965			958			2,099
Interest and dividend income		2			9			29			44
Equity in income from partnerships and unconsolidated subsidiaries – net		35			31			34			40
Other nonoperating income		74			23			131			78
Interest expense – net of amounts capitalized		(187	)		(176	)		(556	)		(511	)
Other nonoperating deductions		(16	)		(82	)		(41	)		(115	)

Income from continuing operations before income taxes		676			770			555			1,635
Income tax expense (benefit)		232			277			(169	)		521

Income from continuing operations		444			493			724			1,114
Income (loss) from discontinued operations – net of tax		(1	)		6			(5	)		—

Net income		443			499			719			1,114
Less: Net income attributable to noncontrolling interests		40			60			82			115

Net income attributable to Edison International common shareholders	$	403		$	439		$	637		$	999

Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	404		$	433		$	642		$	999
Income (loss) from discontinued operations, net of tax		(1	)		6			(5	)		—

Net income attributable to Edison International common shareholders	$	403		$	439		$	637		$	999

Weighted-average shares of common stock outstanding		326			326			326			326
Basic earnings per common share attributable to Edison International common shareholders:
Continuing operations	$	1.23		$	1.31		$	1.95		$	3.03
Discontinued operations		—			0.02			(0.01	)		—

Total	$	1.23		$	1.33		$	1.94		$	3.03

Weighted-average shares of common stock outstanding, including effect of dilutive securities		329			328			328			329
Diluted earnings per common share attributable to Edison International common shareholders:
Continuing operations	$	1.22		$	1.31		$	1.95		$	3.02
Discontinued operations		—			0.02			(0.01	)		—

Total	$	1.22		$	1.33		$	1.94		$	3.02

Dividends declared per common share	$	0.310		$	0.305		$	0.930		$	0.915

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

			Three Months Ended September 30,						Nine Months Ended September 30,


In millions			2009			2008			2009			2008

			(Unaudited)
Net income			$	443		$	499		$	719		$	1,114

Other comprehensive income (loss), net of tax:
	Foreign currency translation adjustments – net			—			(1	)		4			(4	)
	Pension and postretirement benefits other than pensions:
		Net gain arising during the period-net		—			—			1			—
		Amortization of net loss included in net income – net		1			—			4			—
	Unrealized gain (loss) on cash flow hedges:
		Unrealized gain (loss) arising during the period – net of income tax expense (benefit) of $(4) and $357 for the three months and $44 and $53 for the nine months ended September 30, 2009 and 2008, respectively		(5	)		535			56			81
		Reclassification adjustments included in net income – net of income tax expense (benefit) of $52 and $44 for the three months and $75 and $(45) for the nine months ended September 30, 2009 and 2008, respectively		(72	)		(65	)		(104	)		69

Other comprehensive income (loss)				(76	)		469			(39	)		146

Comprehensive income				367			968			680			1,260
Less: Comprehensive income attributable to noncontrolling interests				40			60			82			115

Comprehensive income attributable to Edison International			$	327		$	908		$	598		$	1,145

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

In millions		September 30, 2009			December 31, 2008


		(Unaudited)
ASSETS
Cash and equivalents		$	2,411		$	3,916
Short-term investments			5			7
Receivables, less allowances of $47 and $39 for uncollectible accounts at respective dates			1,158			1,006
Accrued unbilled revenue			583			328
Inventory			549			553
Derivative assets			403			327
Restricted cash			148			3
Margin and collateral deposits			222			105
Regulatory assets			57			605
Deferred income taxes – net			28			104
Other current assets			204			399

Total current assets			5,768			7,353

Nonutility property – less accumulated depreciation of $2,157 and $2,019 at respective dates			4,718			5,374
Nuclear decommissioning trusts			3,025			2,524
Investments in partnerships and unconsolidated subsidiaries			238			229
Investments in leveraged leases			164			2,467
Other investments			93			89

Total investments and other assets			8,238			10,683

Utility plant, at original cost:
	Transmission and distribution		21,035			20,006
	Generation		2,633			1,819
Accumulated depreciation			(5,757	)		(5,570	)
Construction work in progress			2,688			2,454
Nuclear fuel, at amortized cost			277			260

Total utility plant			20,876			18,969

Derivative assets			344			244
Restricted deposits			43			43
Rent payments in excess of levelized rent expense under plant operating leases			1,039			878
Regulatory assets			5,084			5,414
Other long-term assets			1,380			1,031

Total long-term assets			7,890			7,610

Total assets		$	42,772		$	44,615

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

In millions, except share amounts	September 30, 2009		December 31, 2008


	(Unaudited)
LIABILITIES AND EQUITY
Short-term debt	$	85	$	2,143
Current portion of long-term debt		842		174
Accounts payable		966		1,031
Accrued taxes		271		590
Accrued interest		207		187
Customer deposits		241		228
Book overdrafts		260		224
Derivative liabilities		108		178
Regulatory liabilities		1,176		1,111
Other current liabilities		803		831

Total current liabilities		4,959		6,697

Long-term debt		10,448		10,950

Deferred income taxes – net		4,414		5,717
Deferred investment tax credits		198		109
Customer advances		123		137
Derivative liabilities		674		776
Pensions and benefits		3,000		2,860
Asset retirement obligations		3,179		3,042
Regulatory liabilities		2,848		2,481
Other deferred credits and other long-term liabilities		1,924		1,137

Total deferred credits and other liabilities		16,360		16,259

Total liabilities		31,767		33,906

Commitments and contingencies (Note 6)

Common stock, no par value (325,811,206 shares outstanding at each date)		2,294		2,272
Accumulated other comprehensive income		128		167
Retained earnings		7,401		7,078

Total Edison International's common shareholders' equity		9,823		9,517
Noncontrolling interests – other		275		285
Preferred and preference stock of utility not subject to mandatory redemption		907		907

Total equity		11,005		10,709

Total liabilities and equity	$	42,772	$	44,615

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

		Nine Months Ended September 30,


In millions		2009			2008

		(Unaudited)
Cash flows from operating activities:
Net income		$	719		$	1,114
Loss from discontinued operations			5			—

Income from continuing operations			724			1,114
Adjustments to reconcile to net cash provided by operating activities:
	Depreciation, decommissioning and amortization		1,053			972
	Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)		133			42
	Other amortization		95			80
	Lease terminations and other		888			(75	)
	Stock-based compensation		17			25
	Equity in income from partnerships and unconsolidated subsidiaries – net		(34	)		(40	)
	Distributions and dividends from unconsolidated entities		5			9
	Deferred income taxes and investment tax credits		(1,322	)		69
	Rent payments in excess of levelized rent expense		(161	)		(162	)
	Income from leveraged leases		(13	)		(39	)
	Long-term regulatory assets and liabilities – net		338			(28	)
	Long-term derivative assets and liabilities – net		(176	)		29
	Other assets		(136	)		(71	)
	Other liabilities		835			(13	)
Changes in working capital:
	Margin and collateral deposits – net of collateral received		(99	)		(70	)
	Receivables and accrued unbilled revenue		(409	)		(378	)
	Inventory		4			(75	)
	Restricted cash		(148	)		—
	Other current assets		190			93
	Book overdrafts		41			90
	Accrued taxes		(318	)		128
	Current regulatory assets and liabilities – net		613			(97	)
	Current derivative assets and liabilities – net		(238	)		(3	)
	Accounts payable and other current liabilities		235			35
Operating cash flows from discontinued operations			(5	)		—

Net cash provided by operating activities			2,112			1,635

Cash flows from financing activities:
Long-term debt issued			939			2,132
Long-term debt issuance costs			(25	)		(15	)
Long-term debt repaid			(566	)		(246	)
Bonds repurchased			(219	)		(212	)
Preferred stock redeemed			—			(7	)
Short-term debt financing – net			(2,058	)		1,308
Cash contributions from noncontrolling interests			2			—
Stock-based compensation – net			4			(22	)
Dividends and distributions to noncontrolling interests			(88	)		(116	)
Dividends paid			(303	)		(298	)

Net cash provided (used) by financing activities		$	(2,314	)	$	2,524

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

	Nine Months Ended September 30,


In millions	2009			2008

	(Unaudited)
Cash flows from investing activities:
Capital expenditures	$	(2,287	)	$	(1,959	)
Purchase of interest in acquired companies		(7	)		(11	)
Proceeds from termination of leases		1,420			—
Proceeds from sale of property and interests in projects		1			113
Proceeds from nuclear decommissioning trust sales		1,814			2,279
Purchases of nuclear decommissioning trust investments and other		(1,977	)		(2,329	)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment		10			35
Maturities and sales of short-term investments		3			80
Purchase of short-term investments		(1	)		(22	)
Customer advances for construction and other investments		(279	)		(322	)

Net cash used by investing activities		(1,303	)		(2,136	)

Net increase (decrease) in cash and equivalents		(1,505	)		2,023
Cash and equivalents, beginning of period		3,916			1,441

Cash and equivalents, end of period	$	2,411		$	3,464

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

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 nine-month periods ended September 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.

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 consolidated 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 presentation of noncontrolling interests in the consolidated financial statements 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 November 6, 2009, the date the financial statements were issued.

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

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 11. Included in cash and equivalents is $94 million and $89 million at September 30, 2009 and December 31, 2008, respectively, for four projects that Edison International is consolidating under an accounting interpretation for VIEs.

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 September 30,						Nine Months Ended September 30,


In millions	2009			2008			2009			2008

	(Unaudited)
Basic earnings per share – continuing operations:
Income from continuing operations, net of tax	$	404		$	433		$	642		$	999
Gain on redemption of preferred stock		—			—			—			2
Participating securities dividends		(4	)		(6	)		(5	)		(12	)

Income from continuing operations available to common shareholders	$	400		$	427		$	637		$	989

Weighted average common shares outstanding		326			326			326			326

Basic earnings per share – continuing operations	$	1.23		$	1.31		$	1.95		$	3.03

Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	400		$	427		$	637		$	989
Income impact of assumed conversions		2			3			2			6

Income from continuing operations available to common shareholders and assumed conversions	$	402		$	430		$	639		$	995

Weighted average common shares outstanding		326			326			326			326
Incremental shares from assumed conversions		3			2			2			3

Adjusted weighted average shares – diluted		329			328			328			329

Diluted earnings per share – continuing operations	$	1.22		$	1.31		$	1.95		$	3.02

Stock-based compensation awards to purchase 6,279,410 and 3,874,740 shares of common stock for the three months ended September 30, 2009 and 2008, respectively, and 8,645,549 and 2,244,291 shares of common stock for the nine months ended September 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 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 September 30, 2009 and December 31, 2008 consisted of the following:

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 the authoritative guidance which allows for netting of counterparty receivables and payables under a master netting arrangement, 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 $66 million and $123 million at September 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral received from others that have been offset against derivative assets totaled $232 million and $225 million at September 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral provided to others that have not been offset against derivative liabilities totaled $222 million and $105 million at September 30, 2009 and December 31, 2008, respectively. Amounts recognized for cash collateral received from others that have not been offset against derivative assets totaled $28 million and $8 million at September 30, 2009 and December 31, 2008 respectively.

In June 2009, the FASB issued an accounting standard establishing the FASB Accounting Standards Codification (Codification) as 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 action, 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. Edison International adopted the Codification effective July 1, 2009.

In May 2009, the FASB issued authoritative guidance that sets forth the period subsequent to 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 this guidance effective April 1, 2009. The

adoption had no impact on Edison International's consolidated results of operations, financial position or cash flows.

In April 2009, the FASB issued authoritative guidance affirming 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. This includes guidance on identifying circumstances that indicate when there is no active market or transactions where the price inputs being used represent distressed or forced sales. If either of these conditions exists, this guidance 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 guidance and to quantify its effects, if practicable. This guidance also requires disclosures on a more disaggregated basis for investments in debt and equity securities measured at fair value. Edison International adopted this guidance effective April 1, 2009. The adoption had no impact on Edison International's consolidated results of operations, financial position or cash flows. See Note 11.

In April 2009, the FASB issued authoritative guidance requiring 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 guidance effective April 1, 2009. Since this guidance impacts disclosure only, the adoption did not have an impact on Edison International's consolidated results of operations, financial position or cash flows. See Note 11.

Effective January 1, 2009, Edison International adopted authoritative guidance for nonrecurring fair value measurements of nonfinancial assets and liabilities. The adoption did not have a material impact on Edison International's consolidated financial statements.

In April 2009, the FASB amended existing authoritative guidance which determines whether impairment is other than temporary for debt securities. Under this amended guidance, 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 guidance effective April 1, 2009, resulting in increased disclosures. The adoption did not have an impact on Edison International's consolidated results of operations, financial position or cash flows. See Note 11.

In November 2008, the FASB clarified the accounting for certain transactions and impairment considerations involving equity method investments. Effective January 1, 2009, Edison International adopted this guidance prospectively. The adoption had no impact on its consolidated financial statements.

In December 2007, the FASB issued authoritative guidance, establishing 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. This guidance determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This guidance applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning on or after January 1, 2009. The initial adoption had no impact on Edison International's consolidated results of operations, financial position or cash flows.

In April 2009, the FASB issued amended authoritative guidance addressing 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 fair value cannot be determined, the asset acquired or liability assumed arising from a contingency is recognized only if certain criteria are met. This guidance 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 guidance 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. The initial adoption had no impact on Edison International's consolidated results of operations, financial position or cash flows.

In December 2007, the FASB issued authoritative guidance, requiring 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 statements 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 guidance effective January 1, 2009 and retrospectively applied this guidance as of December 31, 2008. In accordance with this guidance, 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 authoritative guidance, requiring 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 guidance effective January 1, 2009. Since this guidance impacts disclosures only, the adoption 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 authoritative guidance amending the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The intent of the guidance is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset under business combinations and other GAAP. Edison International adopted this guidance

effective January 1, 2009. The adoption had no impact on Edison International's consolidated results of operations, financial position or cash flows.

In December 2008, the FASB issued authoritative guidance requiring additional postretirement benefit plan asset disclosures by employers about the major categories of assets, the inputs and valuation techniques used to measure fair value, the level within the fair value hierarchy, the effect of using significant unobservable inputs (Level 3) and significant concentrations of risk. This guidance is effective for years ending after December 15, 2009 and, therefore, Edison International will adopt this guidance at year-end 2009. This guidance 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 an amendment on the accounting and disclosure requirements for the consolidation of variable interest entities. This amendment 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 is currently evaluating the impact that the adoption will have on its consolidated financial statements including the impact on four QF contracts in which SCE has variable interests and currently consolidates. Edison International will adopt this guidance on January 1, 2010.

In August 2009, the FASB issued an accounting standards update that provides additional guidance on how companies should measure liabilities at fair value. While reaffirming the existing definition of fair value, the update reintroduced the concept of entry value into the determination of fair value. Entry value is the amount an entity would receive to enter into an identical liability. Under the new guidance, the fair value of a liability is not adjusted to reflect the impact of contractual restrictions that prevent its transfer. If the quoted price of a liability when traded as an asset includes the effect of a credit enhancement (i.e. a guarantee), this effect should be excluded from the measurement of the liability. Edison International adopted this guidance effective October 1, 2009. This guidance is not expected to have a material impact on its consolidated financial statements.

In September 2009, the FASB issued an accounting standards update that provides additional guidance on how companies should measure the fair value of certain alternative investments such as hedge funds, private equity funds, venture capital funds and funds of funds. This update is designed to address concerns regarding how to appropriately adjust the Net Asset Value (NAV) of these investments to reflect specific attributes, including redemption restrictions and capital commitments. If the investee's underlying investments are measured at fair value at the investor's measurement date, this update allows investors to use NAV to estimate the fair value unless it is probable the investment will be sold at something other than NAV. If not calculated as of the reporting entity's measurement date, the NAV must be adjusted for significant market events. This update provides guidance on fair value hierarchy classification and also requires enhanced disclosures. Edison International is currently evaluating the impact, if any, that the adoption will have on certain investments in the defined benefit pension and PBOP plans and the resulting impact on the funded status of these plans recorded on Edison International's balance sheets. Edison International will adopt this guidance on December 31, 2009.

Cash balances that are restricted under margining agreements are classified as restricted cash included in current assets, as such amounts change frequently based on forward market prices. Cash balances that are restricted to pay amounts required for lease payments or to provide collateral are classified as restricted deposits.

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 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 42% 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.

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.

The following table summarizes the notional volumes of derivatives used for hedging activities at September 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. These CRRs meet the definition of a derivative.
(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.

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

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 $113 million and $307 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to realized gains on economic hedging activities of $14 million and $39 million for the comparable periods in 2008, respectively. Unrealized losses on

economic hedging activities were $198 million for the three months ended September 30, 2009, and unrealized gains on economic hedging activities were $428 million for the nine months ended September 30, 2009. Unrealized losses on economic hedging activities were $617 million and $131 million for the comparable periods in 2008, respectively.

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 September 30, 2009, was $74 million, for which SCE has posted no collateral to its counterparties. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2009, SCE would be required to post an additional $18 million of collateral.

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

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 follow authoritative guidance on derivatives and hedging.

Authoritative guidance on derivatives and hedging establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). A company is required 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. 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.

The accounting requirements for cash flow hedges provide 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. 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).

Authoritative guidance on derivatives and hedging affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies from accrual accounting (i.e., revenue recognition based on the settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from commodity contracts in operating 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 11 – Fair Value Measurements. Resulting gains and losses are recognized in operating revenues in the accompanying consolidated statements of income in the period of change.

Where EME's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EME presents its derivative assets and liabilities on a net basis in its consolidated balance sheet.

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

				Hedging Activities

Commodity	Instrument	Classification	Unit of Measure	Cash Flow Hedges			Economic Hedges			Trading Activities

Electricity	Forwards/Futures	Sales	GWh		21,487	⁽¹⁾		18,871	⁽³⁾		22,055
Electricity	Forwards/Futures	Purchases	GWh		—			18,025	⁽³⁾		23,445
Electricity	Capacity	Sales	MW-Day (in thousands)		320	⁽²⁾		—			733	⁽²⁾
Electricity	Capacity	Purchases	MW-Day (in thousands)		18	⁽²⁾		—			867	⁽²⁾
Electricity	Congestion	Sales	GWh		—			136	⁽⁴⁾		10,277	⁽⁴⁾
Electricity	Congestion	Purchases	GWh		—			2,454	⁽⁴⁾		138,567	⁽⁴⁾
Natural gas	Forwards	Sales	billion cubic feet		—			3.7			36.3
Natural gas	Forwards/Futures	Purchases	billion cubic feet		—			—			35.0
Fuel oil	Forwards/Futures	Sales	Barrels		—			—			150,000
Fuel oil	Forwards/Futures	Purchases	Barrels		—			600,000			150,000
Coal	Forwards/Futures	Purchases	Tons		—			285,000			—

(1): EME's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power contracts for the Illinois Plants which meet the normal sales and purchase exception 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.
(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.
(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 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 September 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.

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

The following table provides the activity of accumulated other comprehensive income for the nine months ended September 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:

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 $11 million and $23 million during the third quarters of 2009 and 2008, respectively, and $16 million and $(8) million during the nine months ended September 30, 2009 and 2008, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in operating revenues in the consolidated statements of income.

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

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 September 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.

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 September 30, 2009 is $21 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 nine months ended September 30, 2009 was less than $1 million and the amount reclassified from accumulated other comprehensive income into income was $4 million.

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 financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The 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.

In July 2009, Viento Funding II amended the credit agreement to add a working capital facility. Availability under the working capital 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.

In September 2009, Midwest Generation and EME repaid $200 million and $163 million, respectively, of borrowings under their respective credit facilities. The outstanding balances under Midwest Generation's working capital facility of $275 million and EME's corporate credit facility of $188 million were reported as current portion of long-term obligations on EME's consolidated balance sheet and were repaid in October 2009.

At September 30, 2009, Edison International (parent) had $85 million of short-term debt outstanding under its $1.4 billion credit facility at a weighted average interest rate of 0.61%.

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 Holdings as a lender.

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

Edison International's composite federal and state statutory income tax rates were approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International's effective tax rates, excluding income attributable to non-controlling interests, were 36% and (36%) for the three- and nine-month periods ended September 30, 2009, respectively, as compared to 39% and 34% for the respective periods in 2008. The principal items affecting comparability of the effective tax rates for the three- and nine-month periods ended September 30, 2009 and 2008 were lower software and property flow-through deductions in 2009, partially offset by higher nondeductible expenses during 2008. The nine-month period also includes a $300 million benefit recorded in 2009 related to 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 extends the 50% bonus depreciation provision for an additional year to include property placed in service by December 31, 2009, provides for an option to elect a cash grant in lieu of an investment tax credit for certain renewable energy property, including the solar energy investment tax credit, and provides for an option to claim cash grants or an investment tax credit in lieu of certain production tax credits, including the wind production tax credit. To elect the cash grant an application must be filed with the United States Department of Treasury. SCE's PV Solar Rooftop facilities are expected to qualify for the investment tax credit and SCE also expects that it will have the option to elect the cash grant. EME placed Phase II of the Goat Wind and High Lonesome wind projects in service during 2009. For its most recently completed projects, EME is currently planning to claim investment tax credits for Phase II of the Goat Wind and High Lonesome wind projects and to claim production tax credits for its Elkhorn Ridge wind project. Both SCE and EME are reviewing the rules issued by the United States Department of Treasury regarding the grant program in their evaluations as to whether to make the grant election. 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.

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

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 September 30, 2009 and December 31, 2008, respectively, if recognized, $263 million and $210 million of the unrecognized tax benefits would impact the effective tax rate.

The total amount of accrued interest and penalty related to Edison International's income tax reserve was $359 million and $200 million as of September 30, 2009 and December 31, 2008, respectively. After-tax interest income, recognized in income tax expense, was $92 million for the nine-months ended September 30, 2009. After-tax interest expense, recognized in income tax expense, was $7 million for the three months ended September 30, 2009 and was $5 million and $18 million for the three- and nine-month periods ended September 30, 2008, respectively.

Edison International's federal income tax returns are currently under active examination by the IRS for tax years 2003 through 2006 and are subject to examination through tax years 2008. Consummation of the Global Settlement, as described below, effectively closed tax years 1986 - 2002 with the IRS and resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases in their entirety.

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 through 2008. The Franchise Tax Board is currently examining tax years through 2002.

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

For the nine months ended September 30, 2009, Edison International made 2008 plan year contributions of $6 million and 2009 plan year contributions of $56 million and expects to make $51 million of additional 2009 plan year contributions in the last three months of 2009. SCE's total 2009 annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to its total annual expense.

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.

	Three Months Ended September 30,						Nine Months Ended September 30,


In millions	2009			2008			2009			2008

	(Unaudited)
Service cost	$	32		$	32		$	96		$	95
Interest cost		52			50			155			151
Expected return on plan assets		(42	)		(65	)		(125	)		(197	)
Amortization of prior service cost		4			4			12			13
Amortization of net loss		14			—			42			1

Expense under accounting standards	$	60		$	21		$	180		$	63
Regulatory adjustment – deferred		(24	)		—			(72	)		—

Total expense recognized	$	36		$	21		$	108		$	63

For the nine months ended September 30, 2009, Edison International made 2009 plan year contributions of $13 million and expects to make $67 million of additional 2009 plan year contributions in the last three months of 2009. SCE's total 2009 annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to its total annual expense.

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) was $9 million and $5 million for the three months ended September 30, 2009 and 2008, respectively, and was $25 million and $24 million for the nine months ended September 30, 2009 and 2008, respectively. The income tax benefit recognized in the consolidated statements of income was $4 million and $2 million for the three months ended September 30, 2009 and 2008, respectively, and was $10 million for each of the nine-month periods ended September 30, 2009 and 2008. Total stock-based compensation cost capitalized was less than $1 million and $2 million for the three- and nine-month periods ended September 30, 2008. Consistent with SCE's 2009 GRC, no stock-based compensation was capitalized in 2009.

				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		5,043,022		$	25.10
Expired		(126,275	)	$	46.41
Forfeited		(241,565	)	$	32.45
Exercised		(235,132	)	$	21.97

Outstanding at September 30, 2009		17,881,885		$	31.75		6.59

Vested and expected to vest at September 30, 2009		17,158,352		$	31.71		6.50	$	74,229,458

Exercisable at September 30, 2009		10,006,960		$	30.22		4.96	$	51,665,003

The amount of cash used to settle stock options exercised was $2 million and $5 million for the three months ended September 30, 2009 and 2008, respectively, and was $8 million and $46 million for the nine months ended September 30, 2009 and 2008, respectively. Cash received from options exercised was $1 million and $3 million for the three months ended September 30, 2009 and 2008, respectively, and was $5 million and $23 million for the nine months ended September 30, 2009 and 2008, respectively. The estimated tax benefit from options exercised was less than $1 million and $1 million for the three months ended September 30, 2009 and 2008, respectively, and was $1 million and $9 million for the nine months ended September 30, 2009 and 2008, respectively.

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

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):

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.

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 September 30, 2009 and December 31, 2008. The asset carrying amount, net of amortization, was $13 million and $16 million at September 30, 2009 and 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. There are no sublease rentals and the contingent rentals for capital leases were less than $1 million for both the nine months ended September 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	Operating Leases – Power Contracts		Operating Leases – Other		Capital Leases


	(Unaudited)
Year ending December 31,
2009 (remaining three months)	$	84	$	64	$	1
2010		626		400		96
2011		498		378		93
2012		361		369		120
2013		356		356		120
Thereafter		2,186		2,183		2,388

Total future commitments	$	4,111	$	3,750	$	2,818
Amount representing executory costs		—		—		(696	)
Amount representing interest		—		—		(402	)

Net commitments	$	4,111	$	3,750	$	1,720

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 $242 million and $212 million for the three months ended September 30, 2009 and 2008, respectively, and was $478 million and $456 million for the nine months ended September 30, 2009 and 2008, respectively.

At September 30, 2009, EME's subsidiaries had firm commitments to spend approximately $87 million during the remainder of 2009 and $31 million in 2010 on capital and construction expenditures. The majority of these expenditures relate to non-environmental improvements at both the Illinois Plants and the Homer City facilities and the construction of wind projects. These expenditures are planned to be financed by cash on hand and cash generated from operations.

EME has entered into various turbine supply agreements with vendors to support its wind development efforts. As of September 30, 2009, EME has commitments to purchase 419 wind turbines (785 MW) with obligations of $718 million due in 2010. In October 2009, EME extended and reduced payment obligations through two agreements. EME, through its subsidiary, Big Sky Wind, LLC, (Big Sky) entered into turbine financing arrangements totaling approximately $206 million for the purchase of 114 wind turbines (240 MW) for the Big Sky wind project. In October 2009, EME also entered into an amendment to one of its turbine supply agreements which no longer obligates EME to purchase 22 wind turbines (46 MW). EME has deferred all remaining 2009 payments to 2010. EME continues to

actively negotiate with its turbine suppliers to match turbine delivery and payment dates to the deployment of turbines at individual wind projects.

As of September 30, 2009, EME has recorded wind turbine deposits of $395 million included in other long-term assets in its consolidated balance sheet. EME has 67 wind turbines (163 MW) in storage to be used for future wind projects with commitments on these turbines of $6 million remaining in 2009 and $8 million in 2010. EME has recorded $191 million in other long-term assets on its consolidated balance sheet related to wind turbines in storage.

EME can elect under one of its existing turbine supply agreements to terminate the agreement for convenience which, if terminated in its entirety, would further reduce turbine commitments by $181 million during 2010. In the event of such termination by EME, a write-off of approximately $45 million would be recognized.

At September 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 $1.0 billion, summarized as follows: remainder of 2009 – $101 million, 2010 – $461 million, 2011 – $255 million, and 2012 – $212 million.

At September 30, 2009, Midwest Generation and EME Homer City had contractual agreements for the transport of coal to their respective facilities. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts. These minimum commitments are currently estimated to aggregate $507 million, summarized as follows: remainder of 2009 – $67 million, 2010 – $276 million, and 2011 – $164 million.

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.

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.

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

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 litigation discussed below under "—Contingencies—Midwest Generation New Source Review Lawsuit." 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 203 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at September 30, 2009. Midwest Generation had recorded a $50 million liability at September 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.

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specified 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.

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 September 30, 2009, EME had recorded a liability of $96 million (of which $49 million is classified as a current liability) related to these matters.

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 September 30, 2009, EME had recorded a liability of $2 million related to these matters.

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.

SCE's Mountainview 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.

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.

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.

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 replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the PSD 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.

Edison International is subject to numerous environmental laws and regulations, which typically require a lengthy and complex process for obtaining licenses, permits and approvals and 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 developments, such as the enactment of more stringent environmental laws and regulations, proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures or operational expenditures or the ceasing of operations at certain facilities. There is no assurance that additional costs would be recovered from customers or that Edison International's financial position results of operations and cash flows 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 September 30, 2009, Edison International's recorded estimated minimum liability to remediate its 31 identified sites at SCE (24 sites) and EME (7 sites primarily related to Midwest Generation) was $44 million, $39 million of which was related to SCE including $5 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 $40 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 $13 million for the three months ended September 30, 2009 and 2008, respectively, and were $7 million and $23 million for the nine months ended September 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 flows. 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.

Edison International's federal income tax returns are currently under active examination by the IRS for tax years 2003 through 2006 and are subject to examination through tax years 2008. Edison International's California and other state income tax returns remain open for tax years 1986 through 2008. As discussed in the section "Global Settlement" in Note 4, the Global Settlement was finalized on May 5, 2009 and effectively closed the federal income tax examination for tax years 1986 – 2002 and resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases in their entirety.

In February 2008, the FERC approved, subject to refund, SCE's request to collect 100% of CWIP in rate base for its Tehachapi, DCR, and Rancho Vista projects, which resulted in base transmission revenue billed of $37 million. In March 2008, the CPUC requested a 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 a hearing to be set to further review SCE's costs. SCE cannot predict the outcome of the matters in this proceeding.

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.

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 DCR and Tehachapi transmission projects and 75 basis points for SCE's Rancho Vista Substation Project ("Rancho Vista"), as well as a 50 basis points adder 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 DCR 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 but the appeal has been deferred until a final FERC order is issued in the 2008 CWIP case.

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 $50 million, of which approximately $12 million had been expended through September 30, 2009. The ruling also directs SCE to explain why certain information was 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.

At September 30, 2009, Edison Capital had a net leveraged lease investment, before deferred taxes, of $43 million in three aircraft leased to American Airlines. American Airlines reported net losses in the nine months ended September 30, 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 September 30, 2009, American Airlines was current in its lease payments to Edison Capital.

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 PSD 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 alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV did not specify the penalties or other relief that the US EPA sought for the alleged violations. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the DOJ, along with several Chicago-based environmental action groups, had been in confidential talks designed to explore the possibility of a settlement.

On August 27, 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, based in part on the allegations in the NOV. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install best available control technology at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. By motion dated October 9, 2009, the environmental groups that had been involved in previous settlement discussions asked the court to allow them to intervene in the August 27 action. The parties have been instructed to meet and confer on the proposed intervention. Midwest Generation plans to vigorously defend against the allegations in the complaint.

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.

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.

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 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.

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.

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

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.

The following table provides the changes in equity for the nine months ended September 30, 2009:

	Equity Attributable to Edison International											Noncontrolling Interests

In millions	Common Stock		Accumulated Other Comprehensive Income (Loss)			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		—		—			637			637			44			38			719
Other comprehensive loss		—		(39	)		—			(39	)		—			—			(39	)
Common stock dividends declared ($ 0.93 per share)		—		—			(303	)		(303	)		—			—			(303	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(54	)		(38	)		(92	)
Shares purchased for stock-based compensation		—		—			(8	)		(8	)		—			—			(8	)
Proceeds from stock option exercises		—		—			5			5			—			—			5
Noncash stock-based compensation and other		16		—			(8	)		8			—			—			8
Excess tax benefits related to stock-based awards		6		—			—			6			—			—			6

Balance at September 30, 2009	$	2,294	$	128		$	7,401		$	9,823		$	275		$	907		$	11,005

The following table provides the changes in equity for the nine months ended September 30, 2008:

	Equity Attributable to Edison International											Noncontrolling Interests

In millions	Common Stock		Accumulated Other Comprehensive Income (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		—		—			999			999			77			38			1,114
Other comprehensive income		—		146			—			146			—			—			146
Common stock dividends declared ($ 0.915 per share)		—		—			(298	)		(298	)		—			—			(298	)
Preferred stock redeemed, net of gain		2		—			—			2			—			(8	)		(6	)
Dividends, distributions to noncontrolling interests and other		—		—			—			—			(53	)		(38	)		(91	)
Shares purchased for stock-based compensation		—		—			(57	)		(57	)		—			—			(57	)
Proceeds from stock option exercises		—		—			23			23			—			—			23
Noncash stock-based compensation and other		24		—			(14	)		10			—			—			10
Excess tax benefits related to stock-based awards		12		—			—			12			—			—			12

Balance at September 30, 2008	$	2,263	$	54		$	6,964		$	9,281		$	319		$	907		$	10,507

The amount of commodity hedges included in unrealized gains on cash flow hedges, net of tax, at September 30, 2009 was a gain of $194 million. The amount of interest rate hedges included in unrealized gains on cash flow hedges, net of tax, at September 30, 2009 was a loss of $2 million. For further discussion regarding interest rate hedges, see Note 2.

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, $146 million, after tax, of the net unrealized gains on cash flow hedges at September 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.

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 100% owned 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 $680 million and $173 million, respectively. The transfer resulted in a $603 million increase in SCE's utility plant (primarily generation plant) with a corresponding decrease in nonutility property (primarily building, plant and equipment). In addition, SCE recognized a one time, non-cash accounting benefit of approximately $46 million primarily 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.

Fair value is defined 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"). Authoritative guidance on fair value measurements and disclosures clarifies that a fair value measurement for a liability should reflect the entity's non-performance risk. In addition, a fair value hierarchy is established 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 are:

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.

Level 3 also includes derivatives that trade infrequently (such as firm transmission rights and CRRs in the California market, financial transmission rights traded in markets outside California 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 September 30, 2009, Edison International reduced the fair value of derivative assets and derivative liabilities for nonperformance risks by $6 million and $10 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.

The following table sets forth assets and liabilities that were accounted for at fair value as of September 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⁾		$	2,307		$	—		$	1		$	—		$	2,308
	Derivative contracts			40			348			654			(295	)		747
	Long-term disability plan			8			—			—			—			8
	Nuclear decommissioning trusts⁽³⁾
		Municipal bonds		—			608			—			—			608
		Stocks		1,681			—			—			—			1,681
		United States government issues		262			39			—			—			301
		Corporate bonds		—			414			—			—			414
		Short-term investments, primarily cash equivalents		—			15			—			—			15

		Sub-total of nuclear decommissioning trusts	$	1,943		$	1,076		$	—		$	—		$	3,019

Total assets⁽⁴⁾			$	4,298		$	1,424		$	655		$	(295	)	$	6,082
Liabilities at Fair Value
	Derivative contracts			(22	)		(277	)		(613	)		130			(782	)

Net assets (liabilities)			$	4,276		$	1,147		$	42		$	(165	)	$	5,300

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⁾		$	3,583		$	—		$	3		$	—		$	3,586
	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⁾			$	5,078		$	1,463		$	451		$	(300	)	$	6,692
Liabilities at Fair Value
	Derivative contracts			(2	)		(397	)		(753	)		198			(954	)

Net assets (liabilities)			$	5,076		$	1,066		$	(302	)	$	(102	)	$	5,738

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

		Three Months Ended September 30,						Nine Months Ended September 30,


In millions		2009			2008			2009			2008

		(Unaudited)
Fair value, net at beginning of period		$	357		$	386		$	(302	)	$	98
Total realized/unrealized gains (losses):
	Included in earnings⁽¹⁾		30			142			127			234
	Included in regulatory assets and liabilities⁽²⁾		(322	)		(264	)		270			(99	)
	Included in accumulated other comprehensive income		—			9			—			3
Purchases and settlements, net			(49	)		(36	)		(67	)		11
Transfers in or out of Level 3			26			(75	)		14			(85	)

Fair value, net		$	42		$	162		$	42		$	162

Change during the period in unrealized gains (losses) related to financial instruments held at the end of the period⁽³⁾		$	(281	)	$	(79	)	$	377		$	(14	)

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.

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

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Realized gains were $35 million and $43 million for the three months ended September 30, 2009 and 2008, respectively and $223 million and $96 million for the nine months ended September 30, 2009 and 2008, respectively. Realized losses were $3 million and $40 million for the three months ended September 30, 2009 and 2008, respectively and $142 million and $46 million for the nine months ended September 30, 2009 and 2008, respectively. Proceeds from sales of securities (which are reinvested) were $503 million and $778 million for the three months ended September 30, 2009 and 2008, respectively and $1.8 billion and $2.3 billion for the nine months ended September 30, 2009 and 2008, respectively. Unrealized holding gains, net of losses, were $1.1 billion and $618 million at September 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 nine months ended September 30, 2009:

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 the current month and 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 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 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.

In millions	September 30, 2009		December 31, 2008


	(Unaudited)
Current:
Regulatory balancing accounts	$	47	$	455
Energy derivatives		8		138
Other		2		12

	$	57	$	605

Long-term:
Regulatory balancing accounts	$	42	$	29
Flow-through taxes – net		1,529		1,337
ARO		—		224
Unamortized nuclear investment – net		352		375
Nuclear-related ARO investment – net		263		278
Unamortized coal plant investment – net		75		79
Unamortized loss on reacquired debt		293		309
SFAS No. 158 pensions and postretirement benefits		1,907		1,882
Energy derivatives		446		723
Environmental remediation		40		40
Other		137		138

	$	5,084	$	5,414

Total Regulatory Assets	$	5,141	$	6,019

In millions	September 30, 2009		December 31, 2008


	(Unaudited)
Current:
Regulatory balancing accounts	$	1,146	$	1,068
Other		30		43

	$	1,176	$	1,111

Long-term:
Regulatory balancing accounts	$	33	$	43
ARO		132		—
Cost of removal		2,501		2,368
Employee benefit plans		182		70

	$	2,848	$	2,481

Total Regulatory Liabilities	$	4,024	$	3,592

EME has purchased a majority interest in a number of wind projects under joint development agreements with third-party developers. At September 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. Based on the allocation of income and losses, EME expects to earn a majority of the expected gains or absorb the majority of the expected losses from these entities and, therefore, determined that it is the primary beneficiary.

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. The QFs sell electricity to SCE and steam to nonrelated parties. SCE has determined that it is the primary beneficiary of these four variable interest entities and therefore consolidates these 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

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.

The following table presents summarized financial information of the SCE QFs and EME wind projects that were consolidated at September 30, 2009 and December 31, 2008:

In millions	September 30, 2009		December 31, 2008


	(Unaudited)
Current assets	$	208	$	206
Nonutility property		1,223		1,239
Other long-term assets		6		3

Total assets	$	1,437	$	1,448

Current liabilities	$	67	$	92
Asset retirement obligation		17		15
Long-term obligations net of current maturities		21		25
Deferred revenues		20		15
Other long-term liabilities		20		18

Total liabilities	$	145	$	165

Noncontrolling interests⁽¹⁾	$	264	$	268

Assets serving as collateral for the debt obligations related to the wind projects had a carrying value of $82 million and $85 million at September 30, 2009 and December 31, 2008, respectively, and primarily consist of property, plant and equipment. The consolidated statements of income and cash flows for the nine months ended September 30, 2009 includes $8 million of pre-tax loss and $35 million of operating cash flows related to variable interest entities that are consolidated by EME.

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 affect SCE's income statement. Any liabilities of these projects are nonrecourse to SCE.

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 not require EME to contribute additional capital. At September 30, 2009, entities which EME has accounted for under the equity method had indebtedness of $251 million, of which $113 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 September 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 September 30, 2009 and December 31, 2008, if payment were required, would be $44 million and $56 million, respectively. EME has not recorded a liability related to the indemnity. EME's maximum exposure to loss at September 30, 2009 is $51 million. During the first quarter of 2009, EME commenced recording its share of equity in income from the March Point project. EME recorded $4 million and $7 million during the third quarter and nine months ended September 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 $4 million and recapture of tax credits (estimated at $36 million as of September 30, 2009 and December 31, 2008).

SCE also has seven other contracts with QFs that contain variable pricing provisions based on the price of natural gas and are potential VIEs. SCE might be considered to be the consolidating entity under this standard and continues to attempt to obtain information for these projects in order to determine whether the projects should be consolidated. These entities are not legally obligated to provide financial information to SCE and have declined to do so. Because these potential VIEs were created prior to December 31, 2003, SCE is not required to apply this accounting guidance 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 270 MW and 263 MW at September 30, 2009 and December 31, 2008, respectively. The amounts that SCE paid to these projects were $43 million and $73 million for the three months ended September 30, 2009 and 2008, respectively, and $104 million and $171 million for the nine months ended September 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.

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.

	Three Months Ended September 30,						Nine Months Ended September 30,


In millions	2009			2008			2009			2008

	(Unaudited)
Operating Revenue (Loss):
Electric utility	$	3,069		$	3,468		$	7,531		$	8,698
Competitive power generation		593			814			1,762			2,146
Financial services and other⁽⁴⁾		3			13			20			42
Parent and other⁽⁵⁾		(1	)		(1	)		(3	)		(2	)

Consolidated Edison International	$	3,664		$	4,294		$	9,310		$	10,884

Net Income (Loss) attributable to Edison International:
Electric utility⁽¹⁾	$	346		$	235		$	1,053		$	542
Competitive power generation⁽²⁾		53			209			149			426
Financial services and other⁽³⁾⁽⁴⁾		7			5			(599	)		53
Parent and other⁽⁵⁾⁽⁶⁾		(3	)		(10	)		34			(22	)

Consolidated Edison International	$	403		$	439		$	637		$	999

(1): Includes earnings of $300 million recorded in the second quarter of 2009 related to the Global Settlement. See Note 4.
(2): Includes earnings (loss) from discontinued operations of $(1) million and $6 million for the three months ended September 30, 2009 and 2008, respectively, and $(5) million for the nine months ended September 30, 2009.
(3): Includes losses of $628 million recorded in the first half of 2009 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 15.
(4): Includes amounts from other EMG subsidiaries that are not significant as a reportable segment.
(5): Includes earnings of $50 million recorded in the second quarter of 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.

Note 15. Investments in Leveraged Leases, Partnerships and Unconsolidated Subsidiaries

As of September 30, 2009, Edison Capital is a lessor in several power generation and 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 second quarter of 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 September 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 ($250 million as of September 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.

In October 2009, EME, through its subsidiary, Big Sky, entered into turbine financing arrangements totaling approximately $206 million for wind turbine purchase obligations related to the 240 MW Big Sky wind project with the following principal terms:

Notice to proceed on construction of the Big Sky wind project with Suzlon S-88 wind turbines was issued in October 2009.

In October 2009, EME completed the acquisition of a 150 MW wind development project in Texas which has a 20-year power purchase agreement with the City of San Antonio (referred to as the Cedro Hill wind project). EME plans to install 100 turbines (150 MW) to be purchased under its turbine supply agreement with General Electric Company to construct this project, which is scheduled for completion during the fourth quarter of 2010. In September 2009, EME made additional deposits of $174 million to General Electric Company. EME plans to obtain project financing for this project prior to completion of construction.

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

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:

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.

This MD&A for the three- and nine-month periods ended September 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 nine month periods ended September 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.

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.

The company-by-company discussion of SCE, EMG, and Edison International (parent) in this MD&A 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.

On September 30, 2009, FERC issued an order accepting SCE's proposed 2010 base transmission rates, subject to refund and settlement procedures, and made the rates effective March 1, 2010. The proposed base transmission rates will increase SCE's revenue requirement by $107 million, or 24%, over the 2009 base transmission revenue requirement primarily due to an increase in transmission rate base. The proposed rates, if approved, are expected to result in an approximate 1% increase to SCE's overall system average rate.

The CPUC determines SCE's cost of capital in a multi-year proceeding occurring every three years. This cost of capital mechanism allows for an annual adjustment to SCE's capital costs if certain thresholds are reached. On October 15, 2009, the CPUC approved SCE's request to forgo an expected 2010 cost of capital increase under the annual adjustment provision and extended SCE's existing capital structure and authorized rate of return through December 2012, absent any future potential annual adjustments. The revised mechanism will be subject to CPUC review in 2012 for the cost of capital set for 2013 and beyond.

SCE's growth strategy includes infrastructure reliability investments and expanding the capability of its distribution and transmission infrastructure, constructing and replacing generation assets, and deploying advanced metering infrastructure. SCE continues to advance its growth strategy included in its 2009 - 2013 capital investment plan. SCE's significant planned projects are as follows:

SCE's 2009 – 2013 total capital investment plan includes capital spending in the range of $16.8 billion to $19.8 billion. See "SCE: Liquidity—Capital Expenditures" for further discussion.

EME is continuing to focus on a selective growth strategy, primarily on development of future renewable projects deploying turbines secured under current turbine supply agreements including turbines in storage. At September 30, 2009, EME has contracts for the purchase of 785 MW of wind turbines. In October 2009, EME completed:

EME plans to defer major construction expenditures for other new wind projects until construction and related project financing is available for such projects. Such financings generally require power

purchase agreements. EME continues to participate in requests for proposals issued by potential customers and to negotiate contracts where projects have been short-listed. If EME is unable to finance its projects on acceptable terms and conditions, certain turbine orders may be terminated. Such an event would likely result in a material charge. EME may store turbines that are delivered until needed for the construction of new wind projects. At September 30, 2009, EME has 67 wind turbines (163 MW) in storage.

As discussed in the year-ended 2008 MD&A under the heading "Edison International: Management Overview—Areas of Business Focus—Environmental Developments—Air Quality Regulations in Illinois", Midwest Generation is subject to various commitments with respect to environmental compliance for the Illinois Plants under the CPS. Midwest Generation continues to review all technology and unit shutdown combinations, including interim and alternative compliance solutions. During 2009, Midwest Generation conducted tests of NO_x removal technology based on selective non-catalytic reduction and flue gas desulfurization technology based on dry sodium sorbent injection that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has preliminarily concluded that installation of selective non-catalytic reduction technology in lieu of selective catalytic reduction technology should meet the NO_x portion of the CPS. Testing of 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 Environmental Protection Agency. A decision regarding whether or not to proceed with the alternative compliance program will occur following further analysis and evaluation of results. Under current conditions, Midwest Generation cannot predict what specific method will be used or the total costs that will be incurred to comply with the CPS.

In August 2009, the US EPA and the State of Illinois filed a lawsuit in Illinois federal court based on claims contained in a previously disclosed 2007 NOV regarding alleged violations of the New Source Performance Standards of the CAA, the CAA's Title V operating permit requirements and applicable opacity and particulate matter standards. The lawsuit seeks, among other things, monetary penalties and an injunction requiring Midwest Generation to install the best available control technology at all units subject to the lawsuit. See "Legal Proceedings—Midwest Generation New Source Review Lawsuit" for further discussion.

Legislative, regulatory and legal developments related to potential controls over GHG emissions in the United States are ongoing. Actions to limit or reduce GHG emissions could significantly increase the cost of generating electricity from fossil fuels as well as the cost of purchased power. In the case of utilities, like SCE, these costs are generally borne by customers, whereas the increased costs for competitive generators, like EME, must be recovered through market prices for electricity.

Legislation to regulate GHG emissions continues to be considered by the Congress; however, the timing, content, and potential effects on Edison International and its subsidiaries of any climate change legislation that may be enacted remain uncertain. In June 2009, the American Clean Energy and Security Act was passed by the U.S. House of Representatives. The bill, which was endorsed by Edison International, would establish a 20% mandatory federal combined efficiency and renewable electricity

standard for certain retail electricity suppliers (SCE is already subject to a California law that requires California utilities to procure at least 20% of their annual electricity sales from renewable resources by 2010) and establish a cap-and-trade system for carbon emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate GHG emissions from all covered entities would be established and decline over time. Emitters of GHGs would be required to have allowances for GHG 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 GHGs 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 GHG conservation efforts).

In April 2009, the US EPA responded to the 2007 U.S. Supreme Court decision in Massachusetts v. EPA by issuing a proposed finding that the current and projected concentrations of the mix of six key GHGs, including carbon dioxide, in the atmosphere threaten the public health and welfare of current and future generations and that such GHGs were air pollutants covered by the CAA. In September 2009, the US EPA issued its Final Mandatory Greenhouse Gas Reporting Rule, which will require all sources within specified categories, including electric generation facilities, to begin emissions monitoring in January 2010, and to submit annual reports to the US EPA by March 31 of each year, with the first report due on March 31, 2011. In September 2009, the US EPA also issued a proposed rule, known as the "tailoring rule," that if adopted would require new facilities with a potential to emit over 25,000 tons of GHGs per year (major GHG sources), or exisiting major GHG sources emitting over 25,000 tons of GHGs per year that are modified and, as a result, increase their potential GHG emissions by over 10,000 tons per year, to obtain pre-construction permits that would demonstrate that they are using best available control technologies to minimize their GHG emissions. If controls are required to be installed at the facilities of Edison International subsidiaries in the future in order to reduce GHG emissions pursuant to regulations issued by the US EPA or others, the potential impact will depend on the nature of the controls applied, which remains uncertain.

Three courts recently addressed the question of whether power plants that emit GHGs constituted public nuisances that could be held liable for damages or other remedies. In one case (in which Edison International is a named defendant), a California federal district court dismissed the plaintiffs' claims. In the other two, federal courts of appeals permitted the suits to go forward. These differing results remain subject to appeal and thus the ultimate impact of these cases remains uncertain. Edison International cannot predict whether these recent appellate decisions will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts for these sorts of claims. For further discussion, see "Other Developments—Environmental Matters—Climate Change—Litigation Developments."

In California, the Governor issued an executive order in September directing the CARB to adopt a regulation by July 31, 2010 that would require utilities to procure at least 33% of their annual electricity sales from renewable resources by 2020. The Order provides that the regulation could increase the targeted percentage of annual electricity sales to be obtained from renewable resources, as well as accelerate or expand the timeframe for compliance based on a thorough assessment of relevant factors. The resulting CARB regulations would be in addition to existing California law that requires California utilities to procure at least 20% of their annual electricity sales from renewable resources by 2010.

Economic conditions and mild weather during the summer months, among other factors, contributed to declines in electrical demand for Northern Illinois and PJM West Hub locations during the nine

months ended September 30, 2009. The electrical load, calculated from published data by PJM, for these locations declined 7% and 4% during the nine months ended September 30, 2009, respectively, compared to the corresponding period of 2008. The decline in price of natural gas, which often serves as the marginal fuel source in the region, together with lower electrical demand 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 $28.62/MWh and $38.65/MWh, respectively, during the nine months ended September 30, 2009 as compared to $52.68/MWh and $73.86/MWh, respectively, during the nine months ended September 30, 2008. As reflected in the net income summary below, these factors had an adverse impact on the results of operations during the third quarter and nine months ended September 30, 2009. Lower electrical load has also generally decreased congestion in the eastern power grid, thereby resulting in lower trading income in the third quarter and nine months ended September 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.

As previously disclosed, Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolved 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. The Global Settlement and termination of the Edison Capital cross-border leases resulted in an Edison International consolidated after-tax earnings charge of $274 million through the second quarter of 2009. See "Other Developments—Federal and State Income Taxes," "Off-Balance Sheet Transactions—Leveraged Leases," and "Edison International (parent)—Liquidity—Intercompany Tax-Allocation Agreement" for further discussion.

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

SCE's earnings from continuing operations were $346 million and $1.1 billion for the three- and nine-month periods ended September 30, 2009, respectively, compared to $235 million and $542 million for the respective periods in 2008. The year-to-date variance reflects the impact of the Global Settlement which resulted in after-tax earnings of $300 million in 2009 (see "—Global Settlement" for further discussion), a non-cash accounting benefit of $46 million, in the third quarter of 2009 related to the transfer of the Mountainview power plant to utility rate base, and a charge of $49 million in the third quarter of 2008 resulting from the CPUC performance-based ratemaking decision. Excluding these items, SCE's quarter and year-to-date earnings reflect higher operating income related to the 2009 GRC decision and lower nonoperating expenses, partially offset by higher income taxes.

EMG's earnings (loss) from continuing operations were $61 million and $(445) million for the three- and nine-month periods ended September 30, 2009, respectively, compared to $208 million and $479 million for the respective periods in 2008. The quarter and year-to-date variances reflect lower income at its coal- and gas-fired projects driven by lower energy prices and lower trading income. The quarter variance also reflects a charge recognized in 2008 related to hedge contracts with Lehman Brothers Commodity Services Inc. The year-to-date variance also reflects the impact of the Global Settlement (see "—Global Settlement" for further discussion), lower earnings at Edison Capital and the favorable buy-out of a coal contract at Midwest Generation in 2008.

Edison International (parent) and other earnings (loss) from continuing operations were $(3) million and $34 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to $(10) and $(22) million for the respective periods in 2008. The after-tax earnings for the nine months ended September 30, 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 "—Global Settlement" for further discussion).

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

On October 1, 2009, SCE's system average rate increased to 14.2¢ per-kWh from 14.1¢ per-kWh due to the implementation of both revenue allocation and rate design changes authorized in Phase 2 of the 2009 GRC and the FERC transmission rate changes authorized in the 2009 FERC rate case.

As discussed in the year-ended 2008 MD&A under the heading "SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates," a California law ("AB 1X") capped customer rates for almost half of SCE's residential customers. On October 11, 2009, California Governor Schwarzenegger signed a bill into law that will allow SCE and other investor-owned utilities to spread future rate increases more broadly among their residential customers. The bill also provides for a limited, phased-in expansion of direct access for nonresidential customers. These changes are not expected to impact SCE's earnings or cash flows.

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 revised its capital expenditure forecasts for the period 2009 - 2013. See "SCE: Liquidity—Capital Expenditures" for further discussion.

On September 11, 2009, the FERC approved a settlement between SCE and the parties to the FERC rate case on the 2009 base transmission rates, effective March 1, 2009. The settlement provides for a base transmission revenue requirement of $448 million, which increases SCE's revenue requirement by $136 million over the previously authorized base transmission revenue requirement.

As discussed under the heading "SCE: Regulatory Matters—Current Regulatory Developments—Energy Efficiency Shareholder Risk/Reward Incentive Mechanism," in the year-ended 2008 MD&A, the CPUC has adopted an Energy Efficiency Risk/Reward Incentive Mechanism. Under the adopted mechanism, SCE would expect to receive a CPUC decision and record its 2006 – 2008 program cycle second progress payment, estimated in the range of $14 million to $26 million, in the fourth quarter of 2009 and would collect the payment in rates during 2010. In a related CPUC rulemaking proceeding, SCE proposed finalizing the total earnings for the 2006 – 2008 program cycle and collecting all remaining payments in 2010 and 2011. There is no assurance of earnings in any given year and SCE

cannot predict whether the CPUC will change the adopted mechanism in the related rulemaking proceeding.

As discussed in the year-ended 2008 MD&A under the heading "Other Developments—Wildfire Insurance Issues," recent damage claims related to wildfires in California and the strict liability doctrine of inverse condemnation may affect SCE's liability insurance levels and cost. On September 1, 2009, SCE renewed its insurance coverage, which included coverage for wildfire liabilities up to a reduced limit of $500 million (with an increased self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in substantially higher self-insured costs in the event of multiple wildfire occurrences during the policy period (September 1, 2009 to August 31, 2010). SCE may experience further coverage reductions and/or increased insurance costs in future years. SCE and the other California investor-owned utilities have filed a joint application with the CPUC seeking recovery of uninsured losses and increased insurance costs. SCE cannot predict the outcome of this proceeding or when a decision will be issued by the CPUC.

As of September 30, 2009, SCE had approximately $3.5 billion of available liquidity comprised of cash and equivalents and short-term investments and $2.8 billion available under credit facilities. The following table summarizes the status of SCE's credit facilities at September 30, 2009:

As of September 30, 2009, SCE's long-term debt, including current maturities of long-term debt, was $6.7 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.

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

SCE expects to meet its 2009 continuing obligations, including cash outflows for operating expenses and power-procurement, as well as projected 2009 capital expenditures through cash and equivalents on hand, and operating cash flows. 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.

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

The American Recovery and Reinvestment Act of 2009 extended the 50% bonus depreciation provision for an additional year to include property placed in service by December 31, 2009. SCE expects that certain capital expenditures incurred 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.

During the third quarter of 2009, the IRS granted companies permission to automatically elect to change their tax accounting method for routine repair and maintenance costs. The change in method would result in the recognition of a cumulative catch-up deduction in 2009 for certain repair costs that were previously capitalized and depreciated over the tax depreciable life of the property. In the fourth quarter of 2009, Edison International expects to file an election to change its tax accounting method for certain repair costs incurred mainly on SCE's transmission and distribution infrastructure assets. Unless there is further IRS guidance which may impact Edison International's ability to make such election, SCE expects to reflect the initial impact in its estimated fourth quarter 2009 federal income tax payment. SCE has not completed its detailed analysis and cannot determine the impact on its results of operations and cash flows at this time.

SCE's updated capital investment plan projects total capital expenditures for the period 2009 – 2013 to be in the range of $16.8 billion to $19.8 billion. The capital investment plan has been updated primarily to reflect timing changes due to slower than anticipated permitting and licensing of some major transmission projects. 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 was approved in SCE's 2009 Rate Case (see "SCE: Regulatory Matters—Current Regulatory Developments—2009 FERC Rate Case" 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 and SCE's service territory. 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 $1.9 billion for the first nine months of 2009. SCE's capital expenditures for the first nine months of 2009 were approximately 20% less than forecast, primarily due to timing delays resulting from a later than expected 2009 GRC decision. As discussed above, the revised capital expenditure forecast for 2009 – 2013 was updated to address expected permitting delays of major transmission projects and as a result, SCE assumed 15% variability to the current forecast (compared to 18% in 2008) in its estimated range of capital expenditures over the next five years: 2009 – $2.6 billion to $3.1 billion; 2010 – $3.3 billion to $3.8 billion; 2011 – $3.6 billion to $4.2 billion; 2012 – $3.8 billion to $4.5 billion; and 2013 – $3.5 billion to $4.2 billion. The estimated capital expenditures for the next five years may vary from SCE's current forecast.

On July 2 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.

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 September 30, 2009, SCE's 13-month weighted-average common equity component of total capitalization was 49.5% resulting in the capacity to pay $212 million in additional dividends.

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At September 30, 2009, SCE's debt to total capitalization ratio was 0.45 to 1.

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 September 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 September 30, 2009.

In the table above, there was no collateral posted as of September 30, 2009 related to derivative liabilities, and $18 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'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.

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 the Mountainview and peaker plants.

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

(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.
(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 $113 million and $307 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to realized gains on economic hedging activities of $14 million and $39 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. Unrealized losses on economic hedging activities were $198 million for the three months ended September 30, 2009, and unrealized gains on economic hedging activities were $428 million for the nine months ended September 30, 2009. Unrealized losses on economic hedging activities were $617 million and $131 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 contracts related to SCE's new generating resources (discussed above) as compared to the three- and nine-month periods ended September 30, 2008.

Effective January 1, 2008, SCE adopted the authoritative guidance that established a hierarchy for fair value measurements. For further discussion of SCE's adoption, see "Edison International Notes to Consolidated Financial Statements—Note 11. Fair Value Measurements."

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.

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 September 30, 2009, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $7.4 billion, compared to a carrying value of $6.7 billion.

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.

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

The credit risk exposure set forth in the above table is comprised of $4 million of net account receivables and $389 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

The CAISO comprises 80% of the total net exposure above and is mainly related to the CRRs' fair value (see "—Commodity Price Risk" for further information).

At September 30, 2009, EMG and its subsidiaries had cash and equivalents and short-term investments of $1.2 billion, excluding approximately $387 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 $496 million of available borrowing capacity under their credit facilities. EMG's consolidated debt at September 30, 2009 was $4.6 billion, of which $592 million was current. In addition, EME's subsidiaries had $3.3 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 25 years.

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

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.

The interest rate on borrowings outstanding under EME's credit facility is at the applicable margin of 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 September 30, 2009. In October 2009, outstanding borrowings of $188 million and $275 million under EME's and Midwest Generation's credit facilities, respectively, were repaid.

Access to the capital markets for non-investment grade credit remains uncertain due to the financial market and economic conditions discussed in "Edison International: Management Overview" and also in "Edison International: Management Overview" in the year-ended 2008 MD&A, though the market for project-based financings has shown signs of improvement. EME intends to focus on a selective growth strategy, primarily on completion of projects under construction and development of 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.

The estimated capital expenditures through 2011 by EME's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:

In millions		October through December 2009		2010			2011


Illinois Plants
	Plant capital expenditures	$	21	$	96		$	62
	Environmental expenditures		6		⁽¹⁾			⁽¹⁾
Homer City Facilities
	Plant capital expenditures		10		55			29
	Environmental expenditures		—		15			32
Renewable Projects
	Projects under construction⁽²⁾		119		453			2
	Turbine commitments⁽³⁾		6		439	⁽⁴⁾		—
Other capital expenditures			8		23			12

Total		$	170	$	1,081		$	137

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.

Environmental expenditures at EME Homer city relate to emission monitoring and control projects. 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—Midwest Generation Environmental Compliance Plans and Costs." For further discussion of environmental regulations, refer to "Other Developments—Environmental Matters" in the year-ended 2008 MD&A.

As of September 30, 2009, EME had a development pipeline of potential wind projects with projected installed capacity of 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. EME has

committed to purchase turbines for wind projects (included in the preceding table) and turbines in storage to be used for future wind projects. The turbine cost generally represents approximately two-thirds of the total capital costs of EME's wind projects. 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—Areas of Business Focus—Business Development and Capital Commitments—EMG."

Walnut Creek Energy, a subsidiary of EME, was awarded by SCE, through a competitive bidding process, a 10-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. As a result of a November 2008 decision by the Los Angeles Superior Court, SCAQMD is enjoined from issuing Priority Reserve emission credits to Walnut Creek, among others. Legal challenges related to the Priority Reserve emission credits are continuing. Legislation which passed the State Assembly and is currently pending action in the Senate would provide access to the credits for Walnut Creek. 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 access to the Priority Reserve emission credits is restored 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.

The S&P and Fitch ratings are on negative outlook, while the Moody's rating outlook is stable. 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."

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 participants 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 participants 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. Revocation of the consent would not affect trades between EMMT and EME Homer City that had been entered into while the consent was still in effect. 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."

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 September 30, 2009, EMMT had deposited $70 million in cash with clearing brokers in support of futures contracts and had deposited $136 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 $65 million at September 30, 2009. In addition, EME had received cash collateral of $232 million at September 30, 2009, to support credit risk of counterparties

under margin agreements; $148 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 September 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 September 30, 2009 could increase by approximately $123 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 September 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 and a credit facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois Plants. In addition, EME has cash on hand and a credit facility to provide credit support to subsidiaries. For discussion on available borrowing capacity under Midwest Generation and EME credit facilities, see "—EMG's Liquidity."

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.

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

		12 Months Ended


In millions		September 30, 2009			December 31, 2008

Funds Flow Available for Interest
Distributions:
	Midwest Generation	$	240		$	206
	EME Homer City⁽¹⁾		118			110
	Big 4 Projects⁽²⁾		87			114
	Viento Funding II⁽³⁾		164			—
	Other projects		47			55
Tax payments received from subsidiaries			195			364
Realized trading income			59			175
Tax allocation receipts (payments)			137			(92	)
Operating expenses			(150	)		(155	)
Other items, net			(13	)		(14	)

		$	884		$	763

Net Interest Expense:
EME corporate debt		$	267		$	248
Addback: Capitalized interest			17			32
Powerton-Joliet intercompany notes			112			112
EME interest income			(4	)		(6	)

		$	392		$	386

Ratio			2.26			1.98
Covenant threshold (not less than)			1.20			1.20

(1): Under EME's credit facility, the definition of interest coverage ratio includes the repayment of subordinated loans to EME Homer City. During April 2009, EME, through its subsidiary, Edison Mission Finance, advanced funds in the amount of $25 million to EME Homer City. In July 2009, the amount advanced was repaid by EME Homer City and is included in distributions during the 12 months ended September 30, 2009.
(2): 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.
(3): In June 2009, a subsidiary of EME, Viento Funding II, Inc., completed a non-recourse 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.

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

In millions		September 30, 2009			December 31, 2008


Corporate Debt
Indebtedness for money borrowed		$	4,163		$	4,564
Powerton-Joliet termination value			1,030			1,163
Letters of credit			97			132

		$	5,290		$	5,859

Corporate Capital
Common shareholder's equity		$	2,788		$	2,684
Less:
	Non-cash cumulative changes in accounting		1			1
	Accumulated other comprehensive income		(154	)		(200	)
Adjustments:
	After-tax losses incurred on termination of Collins lease		587			587
	Dividend to MEHC for repayment of 13.5% notes		899			899

			4,121			3,971

Corporate debt			5,290			5,859

		$	9,411		$	9,830

Corporate-debt-to-corporate-capital ratio			0.56			0.60
Covenant threshold (not more than)			0.75			0.75

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.

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements at September 30, 2009 or for the 12 months ended September 30, 2009:

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 September 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—Global Settlement" 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 $89 million (at September 30, 2009) and purchase certain affordable housing projects for approximately $11 million (at September 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 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 September 30, 2009, the maximum sale or disposition of EME assets is determined as follows:

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, 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 and applicable law, at any time or from time to time, which may affect assets held or under development.

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 September 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. Viento Funding II's payment obligations are secured by pledges of its direct and indirect ownership interests in the three wind projects.

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.

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). On August 14, 2009, the FERC denied most requests for rehearing of the March 26 order but deferred action on one rehearing and granted certain requests for clarification. As directed in the March 26 order, PJM submitted its proposal to automate the adjustment of CONE on September 1, 2009.

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.

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.

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.

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 nine months of 2009 and 2008:

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 September 30, 2009:

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

In addition, as of September 30, 2009, EMMT has entered into 3.7 billion cubic feet of natural gas futures contracts (equivalent to approximately 600 GWh of energy only contracts using a ratio of 6 MMBtu to 1 MWh) for the Illinois Plants to hedge energy price risks during the remainder of 2009 and 2010.

In October 2009, EMMT entered into 7,461 GWh of additional power hedges, primarily off-peak, for the Illinois Plants. The hedges were entered into to mitigate the price risk of negative margins during off-peak periods. Including the additional hedges entered into during October 2009, total hedges for 2010 are 20,099 GWh at an average price of approximately $43.70/MWh.

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 New York Independent System Operator (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 nine 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
July		28.94		72.39		32.42		91.80
August		31.13		60.16		36.70		73.91
September		28.28		52.33		30.38		66.04
Nine-Month Average	$	35.16	$	61.82	$	38.65	$	73.86

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.

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

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 as of September 30, 2009:

The average price per megawatt-hour 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.

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.

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

									RPM Capacity Sold in Base Residual Auction				Other Capacity Sales, Net of Purchases⁽²⁾


		Installed Capacity MW		Unsold Capacity⁽¹⁾ MW			Capacity Sold MW											Aggregate Average Price per MW-day
		Installed Capacity MW		Unsold Capacity⁽¹⁾ MW			Capacity Sold MW		MW		Price per MW-day		MW			Average Price per MW-day		Aggregate Average Price per MW-day

October 1, 2009 to May 31, 2010
	Midwest Generation		5,776		(878	)		4,898		5,329	$	102.04		(431	)	$	99.23	$	102.29
	EME Homer City		1,884		(206	)		1,678		1,670		191.32		8			191.32		191.32
June 1, 2010 to May 31, 2011
	Midwest Generation		5,477		(548	)		4,929		4,929		174.29		—			—		174.29
	EME Homer City		1,884		(71	)		1,813		1,813		174.29		—			—		174.29
June 1, 2011 to May 31, 2012
	Midwest Generation		5,477		(495	)		4,982		4,582		110.00		400			85.00		107.99
	EME Homer City		1,884		(113	)		1,771		1,771		110.00		—			—		110.00
June 1, 2012 to May 31, 2013
	Midwest Generation		5,477		(773	)		4,704		4,704		16.46		—			—		16.46
	EME Homer City		1,884		(148	)		1,736		1,736		133.37		—			—		133.37

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 will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by unavailability of competing resources and increased energy prices, which 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.

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 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 nine months ended September 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 9% and 16%, respectively. The monthly average difference between prices at the Homer City busbar and those at the PJM West Hub during the 12 months ended September 30, 2009 ranged from 5% to 17%. During the nine months ended September 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 15% 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.

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 September 30, 2009 for the remainder of 2009 and the following three years:

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 $50.50 per ton at October 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 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 $9.25 per ton at October 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).

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—Air Quality Regulation" 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 $64 per ton during the nine months ended September 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 $84 per ton and $515 per ton, respectively, at September 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.

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. The fair value changes of each derivative instrument are recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting. 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 (losses) from non-trading activities for the third quarters of 2009 and 2008 and nine months ended September 30, 2009 and 2008:

At September 30, 2009, unrealized gains of $38 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($5 million for the remainder of 2009, $28 million for 2010, and $5 million for 2011).

EME adopted authoritative guidance, effective January 1, 2008, which establishes a hierarchy for fair value measurements. For further discussion of fair value measurements guidance, see "Edison International Notes to Consolidated Financial Statements—Note 10. Fair Value Measurements."

The fair value of outstanding non-trading commodity derivative instruments at September 30, 2009 and December 31, 2008 was $346 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 decrease in fair value of commodity contracts at September 30, 2009 as compared to December 31, 2008 is attributable to the settlement of contracts during the first nine months of 2009 that were entered into in 2008 at higher prices than contracts outstanding at September 30, 2009. 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 and netting as of September 30, 2009:

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 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 fair value of outstanding energy trading derivative instruments at September 30, 2009 and December 31, 2008 was $115 million and $112 million, respectively. The change in the fair value of trading contracts for the nine months ended September 30, 2009 was as follows:

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 and netting (as of September 30, 2009):

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.

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 September 30, 2009, the balance sheet exposure as described above, broken down by the credit ratings of EME's counterparties, was as follows:

The credit risk exposure set forth in the above table is comprised of $137 million of net accounts receivable and payables and $447 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. In addition to the amounts set forth in the above table, EME's subsidiaries have posted a $206 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 45% of EME's consolidated operating revenues for the nine months ended September 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 September 30, 2009, EME's account receivable due from PJM was $40 million.

For the nine months ended September 30, 2009, a second customer, Constellation Energy Commodities Group, Inc., accounted for 17% 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 at September 30, 2009 had a senior unsecured debt rating of BBB by S&P and Baa3 by Moody's. On November 2, 2009, S&P lowered the debt rating of Constellation Energy Group, Inc. to BBB-. At September 30, 2009, EME's account receivable due from Constellation was $22 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.

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EMG 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 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 $3.9 billion at September 30, 2009, compared to the carrying value of $4.6 billion.

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 September 30, 2009, Edison International (parent) had approximately $37 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at September 30, 2009:

In June 2009, Edison International amended the $1.5 billion revolving credit facility to remove a subsidiary of Lehman Brothers Holdings 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 September 30, 2009 are expected to consist of:

Edison International (parent) expects to meet its 2009 continuing obligations through cash and equivalents on hand, external borrowings, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and dividends from SCE.

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.

In connection with the Global Settlement, Edison International made federal and state tax payments of approximately $195 million. Under the tax allocation agreement with EMG, Edison International received net payments of approximately $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 approximately $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 cash flow expected over time by major subsidiary:

See "Edison International: Management Overview—Global Settlement" for further discussion on the Global Settlement.

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 September 30, 2009, Edison International's consolidated debt to total capitalization ratio was 0.53 to 1.

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 September 30,						Nine Months Ended September 30,


In millions		2009			2008			2009			2008

Electric utility operating revenue		$	3,069		$	3,468		$	7,531		$	8,698

Fuel			177			415			533			1,161
Purchased power			1,032			1,333			2,155			3,053
Other operation and maintenance			862			782			2,409			2,324
Depreciation, decommissioning and amortization			302			276			877			830
Lease terminations and other			—			(1	)		(1	)		(9	)

Total operating expenses			2,373			2,805			5,973			7,359

Operating Income			696			663			1,558			1,339
Interest and dividend income			4			2			9			12
Other nonoperating income			69			20			126			69
Interest expense – net of amounts capitalized			(105	)		(104	)		(320	)		(297	)
Other nonoperating deductions			(13	)		(81	)		(33	)		(114	)

Income from continuing operations before income taxes			651			500			1,340			1,009
Income tax expense			236			158			159			268

Income from continuing operations			415			342			1,181			741
Less: Net income attributable to noncontrolling interests			69			107			128			199

Electric utility net income attributable to
	Edison International	$	346		$	235		$	1,053		$	542

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. In accordance with authoritative accounting guidance which requires consolidation of certain variable interest entities, SCE consolidates

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

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

SCE's retail sales represented approximately 95% and 93% of electric utility operating revenue for the three- and nine-month periods ended September 30, 2009, respectively, compared to approximately 89% and 87% for the comparable periods in 2008, respectively. Due to warmer weather during the summer months and SCE's rate design, electric utility operating revenue during the third quarter of each year is generally higher than other quarters. Of total electric utility operating revenue approximately $1.5 billion and $3.5 billion was subject to balancing account treatment for the three- and nine-month periods ended September 30, 2009, respectively, compared to approximately $2.0 billion and $4.9 billion for the same periods in 2008, respectively.

Total electric utility operating revenue decreased by $399 million and $1.2 billion for the three- and nine-month periods ended September 30, 2009, respectively, compared to the same periods in 2008. The variances for the revenue components are as follows:

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 $493 million and $1.39 billion for the three- and nine-month periods ended September 30, 2009, respectively, and $583 million and $1.68 billion for the three- and nine-month periods ended September 30, 2008, respectively.

SCE's fuel expense decreased $76 million and $204 million for the three- and nine-month periods ended September 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 $65 million and $210 million, respectively, resulting primarily from lower natural gas costs in 2009 compared to 2008.

SCE's VIEs fuel expense decreased $162 million and $424 million for the three- and nine-month periods ended September 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.

SCE's total purchased-power expense decreased $301 million and $898 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to the same periods in 2008.

Cost of purchased power decreased $428 million and $1.2 billion for the three- and nine-month periods ended September 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 $420 million and $1.1 billion, respectively, resulting from decreased kWh purchases and lower costs per kWh due to lower natural gas prices. The quarter variance also includes higher CAISO-related energy costs of $20 million. The year-to-date variance also includes lower firm transmission rights costs of $65 million (see "SCE: Market Risk Exposures—Commodity Price Risk—Natural Gas and Electricity Price Risk" for further information) and lower CAISO-related energy costs of $75 million.

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 $113 million and $307 million for the three- and nine-month periods ended September 30, 2009, respectively, compared to realized gains on economic hedging activities of $14 million and $39 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.

SCE's other operation and maintenance expense increased $81 million for the three months ended September 30, 2009, compared to the same period in 2008 mainly due to: $40 million of higher generation expenses related to San Onofre, $25 million of higher transmission and distribution maintenance costs and a $15 million increase related to the timing of outside service costs.

SCE's depreciation, decommissioning and amortization expense increased $26 million and $47 million for the three- and nine-month periods ended September 30, 2009, compared to the same periods in 2008. The quarter and year-to date variances reflect an increase in planned capital expenditures (see "SCE: Liquidity—Capital Expenditures" for a further discussion) and an increase in capitalized software amortization costs of $10 million and $25 million respectively. The year-to-date variance was offset by a $17 million cumulative depreciation rate adjustment recorded in the second quarter of 2008.

SCE's other nonoperating income increased $49 million and $57 million for the three- and nine-month periods ended September 30, 2009, compared to the same periods in 2008 due to an increase in

allowance for funds used during construction – equity. 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 2009 GRC decision 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 benefit 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.

SCE's interest expense – net of amounts capitalized increased $23 million for the nine months ended September 30, 2009 compared to the same period in 2008. The increase was primarily due to higher interest expense on long-term debt resulting from higher outstanding balances compared to the same period in 2008. This increase was 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 period in 2008 and lower interest expense on short-term debt resulting from lower outstanding balances compared to the same period in 2008.

SCE's other nonoperating deductions decreased $68 million and $81 million for the three- and nine-month periods ended September 30, 2009, compared to the same periods in 2008 mainly due to approximately $60 million related to the CPUC decision on SCE's PBR mechanism in September 2008. The quarter and year-to-date variances were also due to approximately a $10 million and $30 million decrease in expenditures made related to civic, political and related activities, and donations, respectively.

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. SCE's effective tax rates, excluding income attributable to non-controlling interests, were 40% and 13% for the three- and nine-month periods ended September 30, 2009, respectively, as compared to 39% and 32% for the respective periods in 2008. The principal items affecting comparability of the effective tax rates for the three- and nine-month periods ended September 30, 2009 and 2008 were lower software and property flow-through deductions in 2009, partially offset by higher nondeductible expenses during 2008. The nine-month period also includes a $300 million benefit recorded in 2009 related to the Global Settlement.

	Three Months Ended September 30,						Nine Months Ended September 30,


In millions	2009			2008			2009			2008

Competitive power generation operating revenue	$	593		$	814		$	1,762		$	2,146

Fuel		228			220			587			564
Other operation and maintenance		223			236			701			753
Depreciation, decommissioning and amortization		62			50			174			140
Lease terminations and other		—			—			1			(16	)

Total operating expenses		513			506			1,463			1,441

Operating Income		80			308			299			705
Interest and dividend income		1			4			17			29
Equity in income from partnerships and unconsolidated subsidiaries – net		60			74			86			123
Other nonoperating income		—			4			2			9
Interest expense – net of amounts capitalized		(78	)		(67	)		(225	)		(204	)

Income from continuing operations before income taxes		63			323			179			662
Income tax expense		10			121			27			237

Income from continuing operations		53			202			152			425
Income (loss) from discontinued operations – net of tax		(1	)		6			(5	)		—

Net income		52			208			147			425

Less: Loss attributable to noncontrolling interests		(1	)		(1	)		(2	)		(1	)

Competitive power generation net income attributable to Edison International	$	53		$	209		$	149		$	426

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.

In this section the words "earnings" or "losses" describe adjusted operating income (loss).

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,


In millions	2009			2008			2009			2008

Illinois Plants	$	69		$	211		$	257		$	553
Homer City		52			109			135			150
Renewable energy projects		—			5			37			38
Energy trading		13			45			40			137
Big 4 projects		27			47			44			83
Sunrise		29			28			31			33
Doga		—			—			8			8
March Point		4			—			7			—
Westside projects		(1	)		1			2			6
Other non-wind projects		3			2			8			8

		196			448			569			1,016

Corporate administrative and general		(40	)		(49	)		(119	)		(131	)
Corporate depreciation and amortization		(4	)		(3	)		(10	)		(8	)

Adjusted Operating Income⁽¹⁾	$	152		$	396		$	440		$	877

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

			Three Months Ended September 30,						Nine Months Ended September 30,


In millions			2009			2008			2009			2008

Operating Revenues			$	372		$	501		$	1,096		$	1,360

Operating Expenses
	Fuel⁽¹⁾			164			142			397			366
	Gain on sale of emission allowances⁽²⁾			—			—			—			(3	)
	Plant operations			89			98			291			317
	Plant operating leases			18			19			56			56
	Depreciation and amortization			27			26			81			78
	Gain on buyout of contract and disposal of assets			—			—			—			(16	)
	Administrative and general			5			5			15			16

	Total operating expenses			303			290			840			814

Operating Income				69			211			256			546
Other Income (Expense)				—			—			1			7

Adjusted Operating Income⁽³⁾			$	69		$	211		$	257		$	553

Statistics⁽⁴⁾
	Generation (in GWh):
		Energy only contracts		8,272			7,333			20,389			19,404
		Load requirements services contracts⁽⁵⁾		—			1,080			1,333			4,212

		Total		8,272			8,413			21,722			23,616

	Aggregate plant performance:
		Equivalent availability⁽⁶⁾		90.1	%		87.4	%		83.8	%		80.9	%
		Capacity factor⁽⁷⁾		68.6	%		69.7	%		60.7	%		65.8	%
		Load factor⁽⁸⁾		76.1	%		79.8	%		72.4	%		81.3	%
		Forced outage rate⁽⁹⁾		5.3	%		8.3	%		6.0	%		9.0	%
	Average realized price/MWh:
		Energy only contracts⁽¹⁰⁾	$	38.74		$	54.25		$	42.11		$	53.44
		Load requirements services contracts⁽¹¹⁾	$	—		$	63.40		$	62.52		$	62.65
	Capacity revenue only (in millions)		$	49		$	41		$	130		$	70
	Average realized fuel costs/MWh⁽¹²⁾		$	19.57		$	16.90		$	18.82		$	15.51

(1): Included in fuel costs were $19 million and $52 million during the third quarter and nine months ended September 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 nine months ended September 30, 2008. These sales reduced operating expenses. EME recorded $3 million of intercompany profit during the nine months ended September 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 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 September 30,						Nine Months Ended September 30,


In millions		2009			2008			2009			2008

Operating revenues		$	372		$	501		$	1,096		$	1,360
Less:
	Load requirements services contracts		—			(68	)		(83	)		(264	)
	Unrealized (gains) losses		(2	)		7			(22	)		15
	Capacity and other revenues		(49	)		(42	)		(132	)		(74	)

Realized revenues		$	321		$	398		$	859		$	1,037

Generation (in GWh)			8,272			7,333			20,389			19,404
Average realized energy price/MWh		$	38.74		$	54.25		$	42.11		$	53.44

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

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.

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

contracts 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.

Earnings from the Illinois Plants decreased $142 million and $296 million in the third quarter and nine months ended September 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 $158 million and $344 million in the third quarter and nine months ended September 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:

In addition, earnings were lower for the nine months ended September 30, 2009 due to a gain of $15 million recorded in 2008 related to the buyout of a fuel contract and insurance claims 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 $2 million and $(7) million for the third quarters of 2009 and 2008, respectively, and $22 million and $(15) million for the nine months ended September 30, 2009 and 2008, respectively. Unrealized gains in 2009 were primarily due to hedge contracts that are not accounted for as cash flow hedges (referred to as economic hedges). Unrealized losses in 2008 included $24 million from power contracts for 2009 and 2010 with Lehman Brothers Commodity Services, Inc. These contracts qualified as cash flow hedges until EME dedesignated the contracts due to non-performance risk and subsequently terminated the contracts. The change in fair value was recorded as an unrealized loss during the third quarter of 2008. Unrealized losses in 2008 were also attributable 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 (losses) of $(2) million and $12 million for the third quarter and nine months ended September 30, 2009, respectively, 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.

		Three Months Ended September 30,						Nine Months Ended September 30,


In millions		2009			2008			2009			2008

Operating Revenues		$	170		$	236		$	496		$	548

Operating Expenses
	Fuel⁽¹⁾		65			78			192			202
	Loss on sale of emission allowances⁽²⁾		—			—			1			—
	Plant operations		22			22			77			108
	Plant operating leases		26			25			76			76
	Depreciation and amortization		4			4			12			12
	Administrative and general		1			1			3			3

	Total operating expenses		118			130			361			401

Operating Income			52			106			135			147
Other Income			—			3			—			3

Adjusted Operating Income⁽³⁾		$	52		$	109		$	135		$	150

Statistics
	Generation (in GWh)		2,994			3,354			8,677			8,796
	Equivalent availability⁽⁴⁾		92.7	%		93.6	%		86.8	%		80.9	%
	Capacity factor⁽⁵⁾		71.8	%		80.5	%		70.1	%		70.9	%
	Load factor⁽⁶⁾		77.5	%		86.0	%		80.8	%		87.6	%
	Forced outage rate⁽⁷⁾		3.8	%		4.0	%		7.6	%		8.1	%
	Average realized energy price/MWh⁽⁸⁾	$	44.83		$	61.95		$	49.06		$	57.69
	Capacity revenue only (in millions)	$	30		$	14		$	60		$	33
	Average fuel costs/MWh	$	21.46		$	23.30		$	22.05		$	23.02

(1): Included in fuel costs were $5 million and $9 million during the third quarters of 2009 and 2008, respectively, and $13 million and $16 million during the nine months ended September 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 nine months ended September 30, 2009. These sales reduced operating expenses. EME recorded $1 million of intercompany losses 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 is equal to operating income plus other income. 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 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

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.

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.

Earnings from Homer City decreased $57 million and $15 million for the third quarter and nine months ended September 30, 2009, respectively, compared to the corresponding periods of 2008. The

2009 decreases in earnings were primarily attributable to lower average realized energy prices and lower generation, partially offset by an increase in capacity revenues. The year-to-date decrease in earnings was also partially offset by 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.

Included in operating revenues were unrealized gains from hedging activities of $6 million and $14 million for the third quarters of 2009 and 2008, respectively, and $11 million and $7 million for the nine months ended September 30, 2009 and 2008, respectively. Unrealized gains were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at Homer City was primarily attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City facilities is delivered into the transmission system). For more information regarding forward market prices and unrealized gains, see "EMG: Market Risk Exposures—Commodity Price Risk" and "EMG: Market Risk Exposures—Accounting for Derivative Instruments," respectively.

Due to fluctuations in 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."

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

			Three Months Ended September 30,						Nine Months Ended September 30,


In millions			2009			2008			2009			2008

Operating Revenues			$	26		$	20		$	101		$	70
Production Tax Credits				10			9			40			29

				36			29			141			99

Operating Expenses
		Plant operations		12			9			37			23
		Depreciation and amortization		24			17			65			39
		Administrative and general		1			1			3			3

		Total operating expenses		37			27			105			65

Other Income (Expense)				—			2			(1	)		3

Net Loss Attributable to Noncontrolling Interest				1			1			2			1

Adjusted Operating Income (Loss)⁽¹⁾			$	—		$	5		$	37		$	38

Statistics
	Generation (in GWh)			635			488			2,173			1,553
	Aggregate plant performance:
		Equivalent availability		92.8	%		83.7	%		87.3	%		83.3	%
		Capacity factor		24.3	%		25.8	%		30.1	%		33.5	%

(1): Adjusted operating income (loss) is equal to operating income (loss) plus production tax credits, other income, and net (income) loss attributable to noncontrolling interest. 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 (loss) 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 (loss) for wind projects is more meaningful for investors as federal and state subsidies are an integral part of the economics of these projects. The following table reconciles adjusted operating income (loss) as shown above to operating income (loss) under GAAP:

Earnings (losses) from renewable energy projects decreased $5 million and $1 million for the third quarter and nine months ended September 30, 2009, respectively, compared to the corresponding

periods of 2008. The third quarter decrease in earnings was attributable to operating losses resulting from mild wind conditions for projects placed in service during 2009.

Earnings for the third quarter of 2009 and 2008 included $1 million and $4 million, respectively, of liquidated damages for availability guarantees provided by Suzlon Wind Energy Corporation. Earnings for the nine months ended September 30, 2009 and 2008 included $17 million and $18 million, respectively, of the Suzlon liquidated damages. At September 30, 2009, EME had a receivable from this vendor of $21 million.

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 $32 million and $97 million for the third quarter and nine months ended September 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 the Big 4 projects decreased $20 million and $39 million for the third quarter and nine months ended September 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. On September 28, 2009, Midway-Sunset entered into a power purchase agreement with Pacific Gas and Electric Company, subject to CPUC approval. For further discussion regarding power sales from the Midway-Sunset, Sycamore and Watson projects, all of which are currently 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 California Public Utilities Commission Decision 07-09-040, dated September 20, 2007, see "Results of Operations and Historical Cash Flow Analysis—Nonutility Power Generation Net Income—Earnings from Unconsolidated Affiliates—Big 4 Projects" in the year-ended 2008 MD&A.

During the third quarter and nine months ended September 30, 2009, EME recorded its share of equity in income of $4 million and $7 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.

EME's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.

Administrative and general expenses decreased $9 million and $12 million for the third quarter and nine months ended September 30, 2009, respectively, compared to the corresponding periods of 2008. The 2009 decreases were primarily due to lower consulting costs. The year-to-date decrease was partially offset by restructuring expenses. In April 2009, EME reduced approximately 75 positions in its regional and corporate offices.

EME's interest income decreased $4 million and $13 million for the third quarter and nine months ended September 30, 2009, respectively, compared to the corresponding periods of 2008. The decreases were primarily attributable to lower interest rates in 2009 compared to 2008.

EME's interest expense to third parties, before capitalized interest, increased $4 million and $6 million for the third quarter and nine months ended September 30, 2009, respectively, 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, and EME's wind financing in June 2009. Capitalized interest decreased $7 million and $15 million for the third quarter and nine months ended September 30, 2009, respectively, compared to the corresponding periods of 2008, due to a reduction in projects under construction.

EME's income tax provision from continuing operations was $27 million and $237 million for the nine months ended September 30, 2009 and 2008, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the nine months ended September 30, 2009 and 2008, EME recognized $40 million and $29 million, respectively, of production tax credits related to wind projects. In addition, EME recognized income tax benefits of $4 million and $5 million during the nine months ended September 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 the

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.

Loss from discontinued operations, net of tax, increased $7 million and $5 million for the third quarter and nine months ended September 30, 2009, respectively, compared to the corresponding periods of 2008. Earnings and losses in 2009 and 2008 included foreign exchange gains (losses) and interest expense 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.

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,


In millions	2009			2008			2009			2008

Financial services and other operating revenue	$	3		$	13		$	20		$	42

Other operation and maintenance		3			8			9			10
Depreciation, decommissioning and amortization		—			1			2			3
Lease terminations and other		—			—			887			(49	)

Total operating expenses		3			9			898			(36	)

Operating Income (Loss)		—			4			(878	)		78
Interest and dividend income		3			5			9			10
Equity in income (loss) from partnerships and unconsolidated subsidiaries – net		3			4			(8	)		1
Other nonoperating income		5			(1	)		4			(1	)
Interest expense – net of amounts capitalized		(3	)		(3	)		(7	)		(7	)
Other nonoperating deductions		(4	)		—			(9	)		—

Income (loss) from continuing operations before income taxes		4			9			(889	)		81
Income tax expense (benefit)		(3	)		4			(290	)		28

Income (loss) from continuing operations		7			5			(599	)		53
Income (loss) from discontinued operations – net of tax		—			—			—			—

Net income (loss)		7			5			(599	)		53

Less: Net income attributable to noncontrolling interests		—			—			—			—

Financial services and other net income (loss) attributable to Edison International	$	7		$	5		$	(599	)	$	53

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—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.

The composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit of state income taxes) for all periods presented. The lower effective tax rate of 33% for the nine months ended September 30, 2009, as compared to the statutory rate, was primarily due to the impacts of the Global Settlement. The lower effective tax rate of 35% for the nine months ended September 30, 2008, as compared to the statutory rate, was primarily due to low income housing tax credits.

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

Cash provided by operating activities increased $482 million in 2009 compared to 2008. The 2009 change was primarily due to the following:

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.

Cash flows from investing activities are driven primarily 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 $2.1 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $80 million for nuclear fuel acquisitions, and $178 million in capital expenditures at EMG. Investing activities also include net purchases of nuclear decommissioning trust investments of $163 million.

Investing activities in 2008 reflect $1.6 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $70 million for nuclear fuel acquisitions, and $628 million in capital expenditures at EMG. Investing activities also include net maturities and sales of short-term investments $58 million and net purchases of nuclear decommissioning trust investments of $50 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 are discussed in Note 1—Summary of Significant Accounting Policies—New Accounting Requirements under "Edison International's Notes to Consolidated Financial Statements."

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.

financing arrangements totaling approximately $206 million for the purchase of 114 wind turbines (240 MW) for the Big Sky wind project. For further information regarding this financing, see "Edison International Notes to Consolidated Financial Statements—Note 16. Subsequent Events." In October 2009, EME also entered into an amendment to one of its turbine supply agreements which no longer obligates EME to purchase 22 wind turbines (46 MW). EME has deferred all remaining 2009 payments to 2010. EME continues to actively negotiate with its turbine suppliers to match turbine delivery and payment dates to the deployment of turbines at individual wind projects.

At September 30, 2009, Edison International recorded a liability for uncertain tax positions of $619 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 tax years 1986 - 2002 with the IRS and resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases in their entirety (see "Edison International: Management Overview—Global Settlement"). Edison International's California and other state income tax returns are open for tax years 1986 through 2008.

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.

During 2009, Edison Capital terminated its interests in the cross-border leases. See "Edison International's Notes to Consolidated Financial Statements—Note 15. Investments in Leveraged Leases, Partnerships and Unconsolidated Subsidiaries" for details of remaining lease investments.

For a discussion of Edison International's environmental matters, refer to "Other Developments—Environmental Matters" in the year-ended 2008 MD&A. There have been no significant developments with respect to environmental matters affecting Edison International since the filing of Edison International's Annual Report on Form 10-K, except as follows:

On October 15, 2009, a California federal district court dismissed the complaint that had been filed by the native Alaskan village of Kivalina and the Kivalina Tribe in February 2008 against numerous defendants, including Edison International, principally in the oil and energy industries. Plaintiffs had alleged GHG emissions from the defendants' business activities contributed to global warming impacts that are melting the Arctic sea ice that protects the village from winter storms. The court dismissed the plaintiffs' federal nuisance claims stating that they were inappropriate for judicial resolution because they required policy choices that were reserved to the legislative or executive branches of the government (the "political question doctrine"). The court also held that the plaintiffs did not have standing to bring the case, in part because of the lack of connection between the defendants' conduct and the harm that plaintiffs alleged was occurring. The court also dismissed plaintiffs' state law nuisance claims, but without prejudice to those claims being re-filed in state court.

Recently, however, the federal Second Circuit and Fifth Circuit Courts of Appeals both issued decisions in cases against GHG emitters, which concluded that plaintiffs in those cases did have standing to bring nuisance claims and that those claims were not precluded by the political question doctrine.

In 2004, several states and environmental organizations filed a complaint in a federal district court in New York, alleging that several electric utilities were liable under a theory of public nuisance for damages caused by the alleged contribution to global warming resulting from carbon dioxide emissions from coal-fired power plants owned and operated by these companies or their subsidiaries. Neither SCE, EME or its subsidiaries were named as defendants in the complaint. The power plants that were the subject of the complaint were not located in physical proximity to the plaintiffs. On September 21, 2009, the Second Circuit Court of Appeals reinstated the lawsuit, holding that the plaintiffs had standing and that their claims did not violate the political question doctrine.

On October 16, 2009, the United States Court of Appeals for the Fifth Circuit reinstated a class action lawsuit that had been dismissed by a federal district court in Mississippi. The plaintiffs claimed that emissions of GHGs from fossil fuel-fired electric generation and other operations allegedly contributed to the destructive force of Hurricane Katrina. The Fifth Circuit decision would allow the plaintiffs to continue to pursue their state law claims of public and private nuisance, trespass and negligence. At the time the action was dismissed by the court in Mississippi, the plaintiffs were seeking to amend their complaint to include Edison International and several affiliates of Edison International as defendants.

Edison International cannot predict whether, and to what extent, any of these decisions will be cited as precedent in other similar lawsuits or result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts as sources of remedies for these sorts of claims.

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.

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 Homer City 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 and third quarters of 2009.

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. In 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 US EPA is currently rewriting the rule.

Clean Water Act – Prohibition on the Use of Ocean-Based Once-Through Cooling

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." The draft policy would establish closed-cycle wet cooling as the best technology available for retrofitting existing once through cooled plants like San Onofre. The Board's stated goal is to vote on a final policy in December 2009. If the draft policy is adopted, it may significantly impact both operations at San Onofre and SCE's ability to procure timely generating capacity from fossil-fuel plants that use ocean water in once-through cooling systems as well as system reliability if other coastal plants are forced to shutdown.

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:

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 $89 million (at September 30, 2009) and purchase certain affordable housing projects for approximately $11 million (at September 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.

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."

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.

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.

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.

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.

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.


(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended September 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


California (State or other jurisdiction of incorporation or organization)		95-4137452 (I.R.S. Employer Identification No.)
2244 Walnut Grove Avenue (P. O. Box 976) Rosemead, California (Address of principal executive offices)		91770 (Zip Code)


Large accelerated filer ý		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o


Class		Outstanding at November 3, 2009
Common Stock, no par value		325,811,206


SCE		Southern California Edison Company
SDG&E		San Diego Gas & Electric
SIP(s)		State Implementation Plan(s)
SO₂		sulfur dioxide
SRP		Salt River Project Agricultural Improvement and Power District
the Tribes		Navajo Nation and Hopi Tribe
TURN		The Utility Reform Network
US EPA		United States Environmental Protection Agency
VIE(s)		variable interest entity(ies)

			Page

PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	1
		Consolidated Statements of Income – Three and Nine Months Ended September 30, 2009 and 2008	1
		Consolidated Statements of Comprehensive Income – Three and Nine Months Ended September 30, 2009 and 2008	2
		Consolidated Balance Sheets – September 30, 2009 and December 31, 2008	3
		Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2009 and 2008	5
		Notes to the Consolidated Financial Statements	7
		Management's Statement	7
		Note 1. Summary of Significant Accounting Policies	7
		Note 2. Derivative Instruments and Hedging Activities	13
		Note 3. Liabilities and Lines of Credit	19
		Note 4. Income Taxes	21
		Note 5. Compensation and Benefits Plans	23
		Note 6. Commitments and Contingencies	25
		Note 7. Consolidated Statement of Changes in Equity	35
		Note 8. Accumulated Other Comprehensive Income	36
		Note 9. Property and Plant	37
		Note 10. Supplemental Cash Flows Information	37
		Note 11. Fair Value Measurements	37
		Note 12. Regulatory Assets and Liabilities	43
		Note 13. Variable Interest Entities	44
		Note 14. Business Segments	47
		Note 15. Investments in Leveraged Leases, Partnerships and Unconsolidated Subsidiaries	49
		Note 16. Subsequent Events	49
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	51
		Edison International: Management Overview	54
		Areas of Business Focus	54
		Global Settlement	58
		Earnings Performance	58

						Page

				Southern California Edison Company		60
				SCE: Regulatory Matters		60
				Current Regulatory Developments		60
				SCE: Other Developments		61
				Wildfire Insurance Issues		61
				SCE: Liquidity		61
				Overview		61
				American Recovery and Reinvestment Act of 2009		62
				Repair Deductions		62
				Capital Expenditures		63
				Credit Ratings		63
				Dividend Restrictions and Debt Covenants		64
				Margin and Collateral Deposits		64
				SCE: Market Risk Exposures		65
				Commodity Price Risk		65
				Interest Rate Risk		66
				Credit Risk		66
				Edison Mission Group		68
				EMG: Liquidity		68
				Liquidity		68
				Capital Expenditures		69
				Credit Ratings		70
				Margin, Collateral Deposits and Other Credit Support for Energy Contracts		71
				Dividend Restrictions in Major Financings		74
				Wind Financing		76
				EMG: Other Developments		76
				RPM CONE		76
				EMG: Market Risk Exposures		77
				Commodity Price Risk		77
				Accounting for Derivative Instruments		84
				Fair Value of Derivative Instruments		85
				Credit Risk		86
				Interest Rate Risk		89
				Edison International (Parent)		90

			Page

		Edison International (Parent): Liquidity	90
		Intercompany Tax-Allocation Agreement	90
		Debt Covenant	91
		Edison International (Consolidated) Results of Operations	92
		Electric Utility Net Income – SCE	92
		Competitive Power Generation Net Income – EME	97
		Financial Services and Other Net Income (Loss) – Edison Capital and other EMG subsidiaries	109
		Edison International (Consolidated) Historical Cash Flow Analysis	110
		New Accounting Requirements	113
		Ccmmitments, Guarantees and Indemnities	113
		Fuel Supply Contracts	113
		Coal Transportation	113
		Turbine Commitments	113
		Capital Improvements	114
		Uncertain Tax Position Net Liability	114
		Off-Balance Sheet Transactions	114
		Other Developments	115
		Environmental Matters	115
		Federal and State Income Taxes	118
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	119
	Item 4.	Controls and Procedures	119
		Disclosure Controls and Procedures	119
		Changes in Internal Controls Over Financial Reporting	119
PART II. – OTHER INFORMATION
	Item 1.	Legal Proceedings	120
		Midwest Generation New Source Review Lawsuit	120
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	121
	Item 6.	Exhibits	122
SIGNATURE			123

In millions	September 30, 2009		December 31, 2008


	(Unaudited)
Cash	$	252	$	138

Money market funds	$	2,159	$	3,583
U.S. government agency securities		—		164
Commercial paper		—		30
Time deposits (certificates of deposit)		—		1

Total cash equivalents	$	2,159	$	3,778

Total cash and equivalents	$	2,411	$	3,916

In millions	September 30, 2009		December 31, 2008


	(Unaudited)
Coal, gas, fuel oil and raw materials	$	183	$	163
Spare parts, materials and supplies		366		390

Total	$	549	$	553

Commodity		Economic Hedges


		(Unaudited)
Electricity options, swaps and forward arrangements	MW		24,308
Natural gas options, swaps and forward arrangements	Bcf		272
Congestion revenue rights⁽¹⁾	MW		516,488
Tolling arrangements⁽²⁾	MW		2,556

		Derivative Assets								Derivative Liabilities

In millions		Short- Term			Long- Term		Subtotal			Short- Term			Long- Term		Subtotal			Net Liability

		(Unaudited)
Non-trading activities
	Economic hedges	$	203		$	237	$	440		$	113		$	632	$	745		$	305
Netting and collateral			(8	)		—		(8	)		(9	)		—		(9	)		(1	)

Total		$	195		$	237	$	432		$	104		$	632	$	736		$	304

		Derivative Assets									Derivative Liabilities

(in millions)		Short- Term			Long- Term			Subtotal			Short- Term			Long- Term			Subtotal			Net Assets

Non-trading activities
	Cash flow hedges	$	297		$	87		$	384		$	59		$	8		$	67		$	317
	Economic hedges		222			44			266			202			39			241			25
Trading activities			341			123			464			287			62			349			115

		$	860		$	254		$	1,114		$	548		$	109		$	657		$	457
Netting and collateral received			(652	)		(147	)		(799	)		(543	)		(89	)		(632	)		(167	)

Total		$	208		$	107		$	315		$	5		$	20		$	25		$	290

In millions	Cash Flow Hedge Activity⁽¹⁾			Income Statement Location


Accumulated other comprehensive income derivative gain at December 31, 2008	$	398
Effective portion of changes in fair value		100
Reclassification from accumulated other comprehensive income to net income		(179	)	Competitive power generation revenues

Accumulated other comprehensive income derivative gain at September 30, 2009	$	319

In millions


Type	Income Statement Location	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009

		(Unaudited)
Economic hedges	Competitive power generation revenue	$	19		$	35
	Fuel expense	$	(2	)	$	12
Trading activities	Competitive power generation revenue	$	16		$	43

In millions	SCE			EMG			Edison International (parent)


	(Unaudited)
Commitment	$	2,894		$	1,100		$	1,426
Less: Commitment from Lehman Brothers subsidiary		—			(36	)		—

	$	2,894		$	1,064		$	1,426
Outstanding borrowings		—			(463	)		(85	)
Outstanding letters of credit		(82	)		(105	)		—

Amount available	$	2,812		$	496		$	1,341

In millions			2009			2008


			(Unaudited)
Balance at January 1			$	2,237		$	2,114
	Tax positions taken during the current year
		Increases		134			75
	Tax positions taken during a prior year
		Increases		135			105
		Decreases		(30	)		(129	)
Decreases for settlements during the period				(1,807	)		—

Balance at September 30			$	669		$	2,165

	Performance Shares			Weighted- Average Grant-Date Fair Value


	(Unaudited)
Nonvested at December 31, 2008		175,177		$	49.95
Granted		178,268		$	21.35
Forfeited		(10,912	)	$	31.04

Nonvested at September 30, 2009		342,533		$	35.41

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		(48	)		4			5			—		(39	)

Balance at September 30, 2009	$	192		$	—		$	(65	)	$	1	$	128

			Amortized Cost				Fair Value


In millions	Maturity Dates		September 30, 2009		December 31, 2008		September 30, 2009		December 31, 2008

			(Unaudited)
Municipal bonds		2009 – 2042	$	513	$	561	$	608	$	629
Stocks		–		825		839		1,681		1,308
United States government issues		2009 – 2051		280		268		301		304
Corporate bonds		2009 – 2049		325		214		414		260
Short-term investments, primarily cash equivalents		2009		20		24		21		23

Total			$	1,963	$	1,906	$	3,025	$	2,524

In millions	2009


	(Unaudited)
Balance at December 31, 2008	$	2,524
Realized gains – net		81
Unrealized gains – net		444
Other-than-temporary impairments		(105	)
Interest, dividends, contributions and other		81

Balance at September 30, 2009	$	3,025

	September 30, 2009				December 31, 2008


In millions	Carrying Amount		Fair Value		Carrying Amount		Fair Value

	(Unaudited)
Long-term debt, including current portion	$	11,290	$	11,319	$	11,124	$	10,812

Project	Capacity


	(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	%

In millions	September 30, 2009			December 31, 2008


	(Unaudited)
Total Assets:
Electric utility	$	33,154		$	32,568
Competitive power generation		9,160			9,014
Financial services and other⁽⁴⁾		1,027			3,091
Parent and other⁽⁶⁾		(569	)		(58	)

Consolidated Edison International	$	42,772		$	44,615

In millions	September 30, 2009			December 31, 2008


	(Unaudited)
Rental receivables – net	$	205		$	3,259
Estimated residual value		21			42
Unearned income		(43	)		(802	)

Investments in leveraged leases	$	183		$	2,499
Deferred income taxes		(168	)		(2,313	)

Net investments in leveraged leases	$	15		$	186




Long-term senior secured debt	A1	A	A+
Short-term (commercial paper)	P-2	A-2	F-1

In millions


Collateral posted as of September 30, 2009⁽¹⁾	$	98
Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade		240

Total posted and potential collateral requirements⁽²⁾	$	338

	September 30, 2009						December 31, 2008


In millions	Assets			Liabilities			Assets		Liabilities

Electricity options, swaps and forward arrangements	$	1		$	20		$	7	$	15
Natural gas options, swaps and forward arrangements		78			161			80		304
Congestion revenue rights and firm transmission rights⁽¹⁾		314			—			81		—
Tolling arrangements⁽²⁾		47			564			63		647
Netting and collateral		(8	)		(9	)		—		(72	)

Total	$	432		$	736		$	231	$	894

	September 30, 2009


In millions	Exposure⁽²⁾		Collateral			Net Exposure

S&P Credit Rating⁽¹⁾
A or higher	$	79	$	(4	)	$	75
A-		313		—			313
BBB+		1		—			1
BBB		—		—			—
BBB-		—		—			—
Below investment grade and not rated		—		—			—

Total	$	393	$	(4	)	$	389

	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

Subsidiary	Financial Ratio	Covenant	Actual


Midwest Generation (Illinois Plants)	Debt to Capitalization Ratio	Less than or equal to 0.60 to 1	0.22 to 1
EME Homer City (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.07 to 1

In millions			September 30, 2009


Consolidated Net Tangible Assets
	Total consolidated assets		$	9,208
	Less:
		Consolidated current liabilities		(987	)
		Intangible assets		(119	)

			$	8,102

10% Threshold			$	810

		24-Hour Northern Illinois Hub Forward Energy Prices⁽¹⁾


2009
	October	$	23.99
	November		26.63
	December		28.74
2010 Calendar "strip"⁽²⁾		$	32.58
2011 Calendar "strip"⁽²⁾		$	34.38

	2009		2010		2011


GWh		3,574		12,638		816
Average price/MWh⁽¹⁾	$	55.04	$	54.30	$	70.61

		24-Hour PJM West Hub Forward Energy Prices⁽¹⁾


2009
	October	$	32.48
	November	$	36.62
	December	$	43.21
2010 Calendar "strip"⁽²⁾		$	48.39
2011 Calendar "strip"⁽²⁾		$	51.52