Edgar Filing: EDISON INTERNATIONAL

Subsidiary

Financial Ratio

Covenant

Actual

Midwest Generation (Illinois plants)

Debt to Capitalization Ratio

Less than or equal
to 0.60 to 1

EME Homer City (Homer City facilities)

Senior Rent Service Coverage Ratio

Greater than 1.7 to 1

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-9936

EDISON INTERNATIONAL

(Exact name of registrant as specified in its charter)


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

(626) 302-2222

(Registrant’s telephone number, including area code)

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 x No ¨

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.

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

(Do not check if a smaller reporting company)

Smaller reporting company ¨

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

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


Class		Outstanding at August 6, 2008
Common Stock, no par value		325,811,206

EDISON INTERNATIONAL

INDEX


		Page No.
Part I. Financial Information

Item 1.	Financial Statements:

	Consolidated Statements of Income – Three and Six Months Ended June 30, 2008 and 2007	1

	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2008 and 2007	2

	Consolidated Balance Sheets – June 30, 2008 and December 31, 2007	3

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2008 and 2007	5

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	96

Item 4.	Controls and Procedures	97

Part II. Other Information

Item 1.	Legal Proceedings	98

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	99

Item 4.	Submission of Matters to a Vote of Security Holders	99

Item 6.	Exhibits	101

Signature		102

GLOSSARY

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)
Btu		British thermal units
CAA		Clean Air Act
CAIR		Clean Air Interstate 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
CPSD		Consumer Protection and Safety Division
CPUC		California Public Utilities Commission
CRRs		congestion revenue rights
D.C. District Court		U.S. District Court for the District of Columbia
DOE		United States Department of Energy
DOJ		Department of Justice
DPV2		Devers-Palo Verde II
DWP		Los Angeles Department of Water & Power
EITF		Emerging Issues Task Force
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
FIN 39-1		Financial Accounting Standards Board Interpretation No. 39-1, Amendment of FASB Interpretation No. 39
FIN 48		Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FAS 109
FTRs		Firm transmission rights
FSP SFAS 142-3		FASB Staff Position No. SFAS 142-3, Determination of the Useful Life of Intangible Assets
GAAP		general accepted accounting principles
GHG		greenhouse gas
GRC		General Rate Case
IRS		Internal Revenue Service
ISO		California Independent System Operator
kWh(s)		kilowatt-hour(s)
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations

MEHC		Mission Energy Holding Company

GLOSSARY (Continued)



Midway-Sunset		Midway-Sunset Cogeneration Company
Midwest Generation		Midwest Generation, LLC
MMBtu		million British thermal units
Mohave		Mohave Generating Station
Moody’s		Moody’s Investors Service
MRTU		Market Redesign Technology Upgrade
MW		megawatts
MWh		megawatt-hours
NOV		notice of violation
NO_x		nitrogen oxide
NRC		Nuclear Regulatory Commission
NYISO		New York Independent System Operator
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
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
San Onofre		San Onofre Nuclear Generating Station
SCE		Southern California Edison Company
SDG&E		San Diego Gas & Electric
SFAS		Statement of Financial Accounting Standards issued by the FASB
SFAS No. 133		Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS No. 141(R)		Statement of Financial Accounting Standards No. 141(R), Business Combinations
SFAS No. 157		Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS No. 158		Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans
SFAS No. 159		Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities
SFAS No. 160		Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements
SFAS No. 161		Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133
SIP(s)		State Implementation Plan(s)
SO₂		sulfur dioxide
TURN		The Utility Reform Network
US EPA		United States Environmental Protection Agency
VIE(s)		variable interest entity(ies)

EDISON INTERNATIONAL

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended June 30,						Six Months Ended June 30,
In millions, except per-share amounts	2008			2007			2008			2007
	(Unaudited)
Electric utility	$	2,754		$	2,459		$	5,105		$	4,681
Nonutility power generation		612			569			1,330			1,241
Financial services and other		16			19			31			37
Total operating revenue		3,382			3,047			6,466			5,959
Fuel		554			438			1,090			924
Purchased power		656			829			1,149			1,146
Provisions for regulatory adjustment clauses – net		279			(33	)		452			255
Other operation and maintenance		1,110			999			2,085			1,879
Depreciation, decommissioning and amortization		333			313			631			627
Gain on buyout of contract and sale of assets		(56	)		—			(73	)		(1	)
Total operating expenses		2,876			2,546			5,334			4,830
Operating income		506			501			1,132			1,129
Interest and dividend income		22			45			36			85
Equity in income from partnerships and unconsolidated subsidiaries – net		9			20			9			37
Other nonoperating income		23			22			49			39
Interest expense – net of amounts capitalized		(165	)		(188	)		(336	)		(386	)
Loss on early extinguishment of debt		—			(241	)		—			(241	)
Other nonoperating deductions		(14	)		(9	)		(26	)		(22	)
Income from continuing operations before tax and minority interest		381			150			864			641
Income tax expense		83			—			244			129
Dividends on preferred and preference stock of utility not subject to mandatory redemption		13			13			25			26
Minority interest		23			46			30			65
Income from continuing operations		262			91			565			421
Income (loss) from discontinued operations – net of tax		(1	)		2			(6	)		5
Net income	$	261		$	93		$	559		$	426
Weighted-average shares of common stock outstanding		326			326			326			326
Basic earnings (loss) per common share:
Continuing operations	$	0.79		$	0.28		$	1.72		$	1.28
Discontinued operations		—			0.01			(0.02	)		0.01
Total	$	0.79		$	0.29		$	1.70		$	1.29
Weighted-average shares, including effect of dilutive securities		329			330			330			331
Diluted earnings (loss) per common share:
Continuing operations	$	0.79		$	0.28		$	1.71		$	1.27
Discontinued operations		—			—			(0.02	)		0.02
Total	$	0.79		$	0.28		$	1.69		$	1.29
Dividends declared per common share	$	0.305		$	0.29		$	0.61		$	0.58

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

EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended June 30,					Six Months Ended June 30,
In millions	2008			2007		2008			2007
	(Unaudited)
Net income	$	261		$	93	$	559		$	426
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments-net		—			—		(3	)		(2	)
Pension and postretirement benefits other than pensions:
Amortization of net gain (loss) and prior service cost included in expense-net		—			—		—			1
Unrealized gains (losses) on cash flow hedges:
Other unrealized gains (losses) arising during the period – net of income tax expense (benefit) of $(212) and $30 for the three months and $(304) and $(85) for the six months ended June 30, 2008 and 2007, respectively		(316	)		48		(454	)		(121	)
Reclassification adjustments included in net income – net of income tax expense of $95 and $7 for the three months and $89 and $19 for the six months ended June 30, 2008 and 2007, respectively		143			10		134			26
Other comprehensive income (loss)		(173	)		58		(323	)		(96	)
Comprehensive income	$	88		$	151	$	236		$	330

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

EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS


In millions	June 30, 2008			December 31, 2007
		(Unaudited)
ASSETS
Cash and equivalents	$	1,070		$	1,441
Short-term investments		13			81
Receivables, less allowance of $32 and $34 for uncollectible accounts at respective dates		1,176			1,033
Accrued unbilled revenue		528			370
Fuel inventory		154			116
Materials and supplies		335			316
Derivative assets		428			109
Restricted cash		3			3
Margin and collateral deposits		185			121
Regulatory assets		203			197
Accumulated deferred income taxes – net		262			167
Other current assets		324			290
Total current assets		4,681			4,244
Nonutility property – less accumulated provision for depreciation of $1,882 and $1,765 at respective dates		5,115			4,906
Nuclear decommissioning trusts		3,152			3,378
Investments in partnerships and unconsolidated subsidiaries		239			272
Investments in leveraged leases		2,454			2,473
Other investments		109			96
Total investments and other assets		11,069			11,125
Utility plant, at original cost:
Transmission and distribution		19,279			18,940
Generation		1,818			1,767
Accumulated provision for depreciation		(5,344	)		(5,174	)
Construction work in progress		2,048			1,693
Nuclear fuel, at amortized cost		251			177
Total utility plant		18,052			17,403
Derivative assets		295			122
Restricted cash		47			48
Rent payments in excess of levelized rent expense under plant operating leases		829			716
Regulatory assets		2,723			2,721
Other long-term assets		1,309			1,144
Total long-term assets		5,203			4,751

Total assets	$	39,005		$	37,523

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

EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS


In millions, except share amounts	June 30, 2008			December 31, 2007
		(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term debt	$	800		$	500
Long-term debt due within one year		177			18
Accounts payable		1,066			979
Accrued taxes		116			49
Accrued interest		192			160
Counterparty collateral		24			42
Customer deposits		224			219
Book overdrafts		324			212
Derivative liabilities		319			125
Regulatory liabilities		1,223			1,019
Other current liabilities		809			933
Total current liabilities		5,274			4,256
Long-term debt		9,292			9,016
Accumulated deferred income taxes – net		5,147			5,196
Accumulated deferred investment tax credits		110			114
Customer advances		145			155
Derivative liabilities		243			101
Power-purchase contracts		22			22
Accumulated provision for pensions and benefits		1,165			1,089
Asset retirement obligations		2,962			2,892
Regulatory liabilities		3,356			3,433
Other deferred credits and other long-term liabilities		1,601			1,595
Total deferred credits and other liabilities		14,751			14,597
Total liabilities		29,317			27,869
Commitments and contingencies (Note 5)
Minority interest		314			295
Preferred and preference stock of utility not subject to mandatory redemption		907			915
Common stock, no par value (325,811,206 shares outstanding at each date)		2,253			2,225
Accumulated other comprehensive loss		(415	)		(92	)
Retained earnings		6,629			6,311
Total common shareholders’ equity		8,467			8,444

Total liabilities and shareholders’ equity	$	39,005		$	37,523

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

EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
In millions	2008			2007
	(Unaudited)
Cash flows from operating activities:
Net income	$	559		$	426
Less: Income (loss) from discontinued operations		(6	)		5
Income from continuing operations		565			421
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization		631			627
Realized loss on impairment of nuclear decommissioning trusts		72			23
Other amortization		51			64
Stock-based compensation		16			19
Minority interest		30			65
Deferred income taxes and investment tax credits		26			(193	)
Equity in income from partnerships and unconsolidated subsidiaries		(9	)		(37	)
Gain on buyout of contract and sale of assets		(73	)		(1	)
Income from leveraged leases		(27	)		(31	)
Levelized rent expense		(113	)		(112	)
Loss on early extinguishment of debt		—			241
Regulatory assets		8			245
Regulatory liabilities		374			120
Derivative assets		(476	)		(140	)
Derivative liabilities		(221	)		(123	)
Other assets		(52	)		(22	)
Other liabilities		51			236
Margin and collateral deposits – net of collateral received		(83	)		(29	)
Receivables and accrued unbilled revenue		(237	)		(189	)
Inventory and other current assets		(36	)		(49	)
Book overdrafts		112			65
Accrued interest and taxes		99			205
Accounts payable and other current liabilities		(2	)		(119	)
Distributions and dividends from unconsolidated entities		8			21
Operating cash flows from discontinued operations		(6	)		5
Net cash provided by operating activities		708			1,312
Cash flows from financing activities:
Long-term debt issued		784			2,905
Premium paid on extinguishment of debt and long-term debt issuance costs		(10	)		(240	)
Long-term debt repaid		(134	)		(2,965	)
Bonds repurchased		(212	)		—
Redemption of preference stock, net		(7	)		—
Rate reduction notes repaid		—			(116	)
Short-term debt financing – net		300			175
Shares purchased for stock-based compensation		(51	)		(183	)
Proceeds from stock option exercises		20			72
Excess tax benefits related to stock-based awards		11			35
Dividends to minority shareholders		(33	)		(32	)
Dividends paid		(199	)		(189	)
Net cash provided (used) by financing activities	$	469		$	(538	)

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

EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
In millions	2008			2007
	(Unaudited)
Cash flows from investing activities:
Capital expenditures	$	(1,460	)	$	(1,335	)
Purchase of interest of acquired companies		(7	)		(23	)
Proceeds from sale of property and interests in projects		112			—
Proceeds from nuclear decommissioning trust sales		1,501			2,017
Purchases of nuclear decommissioning trust investments and other		(1,560	)		(2,084	)
Proceeds from partnerships and unconsolidated subsidiaries, net of investment		30			31
Maturities and sales of short-term investments		70			3,192
Purchase of short-term investments		(2	)		(2,952	)
Restricted cash		—			37
Customer advances for construction and other investments		(232	)		(233	)
Net cash used by investing activities		(1,548	)		(1,350	)
Net decrease in cash and equivalents		(371	)		(576	)
Cash and equivalents, beginning of period		1,441			1,795
Cash and equivalents, end of period	$	1,070		$	1,219

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

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management’s Statement

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and six-month periods ended June 30, 2008 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, 2007 filed with the Securities and Exchange Commission.

Note 1. Summary of Significant Accounting Policies

Basis of Presentation

Edison International’s significant accounting policies were described in Note 1 of “Notes to Consolidated Financial Statements” included in its 2007 Annual Report on Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2008 as discussed below in “Margin and Collateral Deposits” and “New Accounting Pronouncements.”

Certain prior-year reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of FIN No. 39-1. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.

Earnings Per Common Share

Edison International computes EPS using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International’s participating securities are stock-based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. Stock options awarded prior to 2002 and after 2006 were granted without a dividend equivalent feature. As a result of meeting a performance trigger, the options granted in 1998 and 1999 began earning dividend equivalents in 2006. EPS was computed as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
In millions	2008			2007		2008			2007
	(Unaudited)
Basic earnings per share – continuing operations:
Income from continuing operations	$	262		$	91	$	565		$	421
Gain on redemption of preferred stock		—			—		2			—
Participating securities dividends		(3	)		—		(6	)		(4	)
Income from continuing operations available to common shareholders	$	259		$	91	$	561		$	417
Weighted average common shares outstanding		326			326		326			326
Basic earnings per share – continuing operations	$	0.79		$	0.28	$	1.72		$	1.28
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	259		$	91	$	561		$	417
Income impact of assumed conversions		1			1		3			4
Income from continuing operations available to common shareholders and assumed conversions	$	260		$	92	$	564		$	421
Weighted average common shares outstanding		326			326		326			326
Incremental shares from assumed conversions		3			4		4			5
Adjusted weighted average shares – diluted		329			330		330			331
Diluted earnings per share – continuing operations	$	0.79		$	0.28	$	1.71		$	1.27

Stock-based compensation awards to purchase 108,901 and 2,500 shares of common stock for the three months ended June 30, 2008 and 2007, respectively, and 108,901 and 25,000 shares of common stock for the six months ended June 30, 2008 and 2007, 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; therefore, the effect would have been antidilutive.

Intangible Assets

The caption “Other current assets” on Edison International’s consolidated balance sheets includes emission allowances purchased for use by EME of $41 million and $45 million at June 30, 2008 and December 31, 2007, respectively.

The caption “Other long-term assets” on Edison International’s consolidated balance sheets includes EME’s project development rights, option rights, and purchased emission allowances and the total amounted to $108 million and $61 million, at June 30, 2008 and December 31, 2007, respectively.

Based on the CAIR requirements, Midwest Generation purchased $48 million of annual NO_X allowances under the new CAIR annual NO_X program which was vacated by the District of Columbia Circuit Court of Appeals in July 2008. As a result of this decision, the annual NO_X allowances may no longer be required. Midwest Generation is currently evaluating the above decision including whether the purchased annual NOx allowances are impaired which could result in a charge against income during the third quarter ending September 30, 2008.

Margin and Collateral Deposits

Margin and collateral deposits include margin requirements and cash deposited with and received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the related positions. See “New Accounting Pronouncements” below for a discussion of the adoption of FIN No. 39-1. In accordance with FIN No. 39-1, 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 net derivative liabilities totaled $226 million and $38 million at June 30, 2008 and December 31, 2007, respectively. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $23 million at June 30, 2008.

New Accounting Pronouncements

Accounting Pronouncements Adopted

In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting agreements. Edison International adopted FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits with derivative positions on Edison International’s consolidated balance sheets, but had no impact on its consolidated statements of income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which resulted in a decrease in net assets (margin and collateral deposits) of $38 million. The consolidated statements of cash flows for the six months ended June 30, 2007 has been retroactively restated to reflect the balance sheet changes, which had no impact on total operating cash flows from continuing operations.

In February 2007, the FASB issued SFAS No. 159, which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. Edison International adopted this pronouncement effective January 1, 2008. The adoption had no impact because Edison International did not make an optional election to report additional financial assets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. Edison International adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustments to its consolidated financial statements. The accounting requirements for employers’ pension and other postretirement benefit plans are effective at the end of 2008, which is the next measurement date for these benefit plans. The effective date will be January 1, 2009 for asset retirement obligations and other nonfinancial assets and liabilities which are measured or disclosed on a non-recurring basis. For further discussion, see Note 8.

Accounting Pronouncements Not Yet Adopted

acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning on or after January 1, 2009. Early adoption is not permitted.

In December 2007, the FASB issued SFAS No. 160, which requires an entity to present minority interest that reflects 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 interest to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interest 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 be measured at fair value. Edison International will adopt SFAS No. 160 on January 1, 2009. In accordance with this standard, Edison International will reclassify minority interest to a component of shareholders’ equity (at June 30, 2008 this amount was $314 million).

In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. Edison International will adopt SFAS No. 161 in the first quarter of 2009. SFAS No. 161 will impact disclosures only and will not have an impact on Edison International’s consolidated results of operations, financial condition or cash flows.

In April 2008, the FASB issued FSP FAS No. 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other U.S. generally accepted accounting principles. Edison International will adopt FSP FAS No. 142-3 on January 1, 2009. Edison International is currently evaluating the impact, if any, that the adoption of this position could have on its consolidated financial statements.

Property and Plant

Utility Plant

Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor, construction overhead, a portion of administrative and general costs capitalized at a rate authorized by the CPUC, and AFUDC. AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction. Currently, AFUDC debt and equity is capitalized during certain plant construction and reported in interest expense and other nonoperating income, respectively. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset.

On November 26, 2007, the FERC issued an order granting incentives on three of SCE’s largest proposed transmission projects, DPV2, Tehachapi Transmission Project (“Tehachapi”), and Rancho Vista Substation Project (“Rancho Vista”). The order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction of all three projects. On February 29, 2008, the FERC approved SCE’s revision to its Transmission Owner Tariff to collect 100% of construction work in progress (CWIP) for these projects in rate base and earn a return on equity, rather than capitalizing AFUDC. SCE implemented the CWIP rate, subject to refund, on March 1, 2008. For further discussion, see “FERC Transmission Incentives” in Note 5.

Related Party Transactions

During the first quarter of 2008, a subsidiary of EME was awarded, through a competitive bidding process, a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power sales agreement is subject to approval of the CPUC which SCE requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate transaction, the contract is also subject to FERC approval, which was requested on May 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013.

Short-term Investments

At June 30, 2008 and December 31, 2007, Edison International classified all marketable debt securities as held-to-maturity. The securities were carried at amortized cost plus accrued interest which approximated their fair value. Gross unrealized holding gains and losses were not material.

Edison International’s held-to-maturity securities, which all mature within one year, consisted of the following:


In millions	June 30, 2008		December 31, 2007
		(Unaudited)
Commercial paper	$	2	$	32
Certificates of deposit		11		41
Treasury bills		—		7
Corporate bonds		—		1
Total	$	13	$	81

Note 2. Liabilities and Lines of Credit

Long-Term Debt

In January 2008, SCE issued $600 million of 5.95% first and refunding mortgage bonds due in 2038. The proceeds were used to repay SCE’s outstanding commercial paper of approximately $426 million and for general corporate purposes.

The interest rates on one issue of SCE’s pollution control bonds insured by FGIC, totaling $249 million, were reset every 35 days through an auction process. Due to a loss of confidence in the creditworthiness of the bond insurers, there was a significant reduction in market liquidity for auction rate bonds and interest rates on these bonds increased. Consequently, SCE purchased in the secondary market $37 million of its auction rate bonds in December 2007. In the first three months of 2008, SCE purchased the remaining $212 million of its auction rate bonds, converted the issue to a variable rate mode, and terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

Short-Term Debt

SCE’s short-term debt is generally used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements including power-purchase payments. At June 30, 2008, the outstanding short-term debt was $800 million at a weighted-average interest rate of 2.58%. SCE’s short-term debt is supported by a $2.5 billion credit line. See below in “Credit Agreement Amendments.”

Credit Agreement Amendments

On March 12, 2008, both Edison International and SCE amended their existing credit facilities, extending the maturities to February 2013 while retaining existing borrowing costs as specified in the facilities. The

amendments also provide four extension options which, if all exercised, will result in final terminations in February 2017. At June 30, 2008, SCE’s $2.5 billion credit facility supported $197 million in letters of credit and $800 million of short-term debt outstanding, leaving $1.5 billion available for liquidity purposes. At June 30, 2008, all of Edison International’s (parent) $1.5 billion credit facility was available for liquidity purposes.

Note 3. Income Taxes

Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International’s effective tax rate was 24% and 30% for the three- and six-month periods ended June 30, 2008, respectively, as compared to 0% and 23% for the respective periods in 2007. The increased effective tax rates in 2008, as compared to 2007, were primarily due to reductions at SCE during 2007, as discussed below. The higher effective tax rates were partially offset by SCE internally developed software flow-through tax deductions recorded in 2008. The effective tax rates in 2007 were lower than the statutory rate primarily due to progress made in the first quarter of 2007 in an administrative appeal process with the IRS related to the income tax treatment of certain of SCE’s costs associated with environmental remediation; reductions made at SCE during the second quarter of 2007 to reflect receipt of a state Notice of Proposed Adjustment; and also due to property related flow-through items at SCE. In addition, the decreased effective tax rate in the second quarter of 2007 resulted from a reduction in pre-tax income.

Accounting for Uncertainty in Income Taxes

FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. Edison International has filed affirmative tax claims related to tax positions, which, if accepted, could result in refunds of taxes paid or additional tax benefits for positions not reflected on filed original tax returns. FIN 48 requires the disclosure of all unrecognized tax benefits, which includes the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.

Unrecognized Tax Benefits Tabular Disclosure

The following table provides a reconciliation of unrecognized tax benefits from January 1, 2008 to June 30, 2008:


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

The unrecognized tax benefits in the table above reflects affirmative claims related to timing differences of $1.5 billion and $1.6 billion at June 30, 2008 and January 1, 2008, respectively, but have not met the recognition threshold pursuant to FIN 48 and have been denied by the IRS as part of their examinations. These affirmative claims remain unpaid by the IRS and no receivable has been recorded. Edison International is vigorously defending these affirmative claims in IRS administrative appeals proceedings.

It is reasonably possible that Edison International could reach a settlement with the IRS for all or a portion of the unrecognized tax benefits through tax year 2002 within the next 12 months, which could reduce unrecognized tax benefits by up to $1.3 billion.

The total amount of unrecognized tax benefits as of June 30, 2008 and January 1, 2008 that, if recognized, would have an effective tax rate impact is $205 million and $206 million, respectively.

The total amount of accrued interest and penalties were $184 million and $162 million as of June 30, 2008 and January 1, 2008, respectively. The after-tax interest expense recognized and included in income tax expense was $5 million and $13 million for the three- and six-month periods ended June 30, 2008, respectively.

Tax Positions being addressed as part of active examinations and administrative appeals processes

Edison International is challenging certain IRS deficiency adjustments for tax years 1994 – 1999 with the Administrative Appeals branch of the IRS and Edison International is currently under active IRS examination for tax years 2000 – 2002. In addition, the statute of limitations remains open for tax years 1986 – 1993, which has allowed Edison International to file certain affirmative claims related to these tax years.

Most of these tax positions relate to timing differences and, therefore, any amounts that would be paid if Edison International’s position is not sustained (exclusive of any penalties) would be deductible on future tax returns filed by Edison International. In addition, Edison International has filed affirmative claims with respect to certain tax years 1986 through 2005 with the IRS and state tax authorities. Any benefits associated with these affirmative claims would be recorded in accordance with FIN 48 which provides that recognition would occur at the earlier of when Edison International would make an assessment that the affirmative claim position has a more likely than not probability of being sustained or when a settlement of the affirmative claim is consummated with the tax authority. Certain of these affirmative claims have been recognized as part of the implementation of FIN 48.

Currently, Edison International is under administrative appeals with the California Franchise Tax Board for tax years 1997 – 2002 and under examination for tax years 2003 – 2004. Edison International remains subject to examination by the California Franchise Tax Board for tax years 2005 and forward. Edison International is also subject to examination by other state tax authorities, subject to varying statute of limitations.

Edison International filed amended California Franchise Tax returns for tax years 1997 – 2002 to mitigate the possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to listed transactions described in an IRS notice that was published in 2001. These transactions include certain Edison Capital leveraged lease transactions and the SCE subsidiary contingent liability company transaction, described below. Edison International filed these amended returns under protest retaining its appeal rights.

Balancing Account Over-Collections

In response to an affirmative claim related to balancing account over-collections, Edison International received an IRS Notice of Proposed Adjustment in July 2007. This affirmative claim is part of the ongoing IRS examinations and administrative appeals process and all of the tax years included in this Notice of Proposed Adjustment remain subject to ongoing examination and administrative appeals. The cash and earnings impacts of this position are dependent on the ultimate settlement of all open tax issues in these tax years. Edison International expects that resolution of this particular issue could potentially increase earnings and cash flows within the range of $70 million to $80 million and $300 million to $350 million, respectively.

Contingent Liability Company

company for tax years 1997 – 1998. This is being considered by the Administrative Appeals branch of the IRS where Edison International is defending its tax return position with respect to this transaction.

Lease Transactions

As part of a nationwide challenge of cross border lease transactions, the IRS has asserted deficiencies related to Edison International’s deferral of income taxes associated with certain of its cross-border, leveraged leases. For tax years 1994 – 1999, Edison International is challenging the asserted deficiencies in ongoing IRS Appeals proceedings.

These asserted deficiencies relate to Edison Capital’s income tax treatment of both its foreign power plant and electric locomotive sale/leaseback transactions entered into in 1993 and 1994 (Replacement Leases, which the IRS refers to as sale-in/lease-out or SILOs) and its foreign power plants and electric transmission system lease/leaseback transactions entered into in 1997 and 1998 (Lease/Leaseback, which the IRS refers to as lease-in/lease-out or LILOs).

In 1999, Edison Capital entered into a lease/service contract transaction involving a foreign telecommunication system (Service Contract, which the IRS refers to as a SILO). As part of an ongoing examination of 2000 – 2002, the IRS is reviewing Edison International’s income tax treatment of this Service Contract and has issued several data requests, to which Edison International has responded. The IRS has not formally asserted any adjustments, but Edison International believes that the IRS examination team will assert deficiencies related to this Service Contract. The following table summarizes estimated federal and state income taxes deferred from these leases as of December 31, 2007. Repayment of these deferred taxes would be accelerated if the IRS position were to be sustained:


In millions	Tax Years Under Appeal 1994 – 1999		Tax Years Under Audit 2000 – 2002		Unaudited Tax Years 2003 – 2007			Total
Replacement Leases (SILO)	$	44	$	19	$	27		$	90
Lease/Leaseback (LILO)		563		566		(8	)		1,121
Service Contract (SILO)		—		127		253			380
Total	$	607	$	712	$	272		$	1,591

As of June 30, 2008, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $590 million. The IRS has also asserted a 20% penalty on any sustained adjustment.

During the second quarter of 2008, several court developments addressing income taxation of cross-border leveraged leases occurred. The court developments represent increased uncertainty about the tax treatment of SILOs and LILOs generally. Despite these developments, Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law and, in the absence of any settlement with the IRS, will continue to vigorously defend its tax treatment of these leases.

recomputing the cumulative earnings under the leases in accordance with lease accounting rules (FASB Staff Position FAS 13-2), and recording interest related to the current income tax liability. This exposure does not include IRS asserted penalties of 20%, as Edison International does not believe that even if the tax benefits taken by Edison Capital are successfully challenged by the IRS that these penalties would be sustained. The current and future income and cash positions of SCE and EME are virtually unaffected by these leases.

Edison International will continue to monitor and evaluate its lease transactions with respect to future events. Future adverse developments, including further adverse case law developments, could change Edison International’s current conclusions.

As previously disclosed, Edison International has been engaged in settlement negotiations with the IRS. These negotiations seek to resolve the lease issues in their entirety and all other outstanding tax disputes for the years 1994 through 2002, including certain affirmative claims for unrecognized tax benefits. These negotiations have progressed to the point where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolving such tax disputes on a “global” basis, including the lease issues. Final resolution of such disputes, however, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of such settlements by the Staff of the Joint Committee on Taxation, a committee of the United States Congress (the “Joint Committee”).

Were Edison International and the IRS to implement the preliminary understanding regarding the leases, Edison International anticipates that it will be required to terminate the leases as an interim step in the implementation of the overall settlement before executing final agreements with the IRS and before review by the Joint Committee. Edison Capital and its subsidiaries have executed term sheets with the counterparties to its SILOs and LILOs which contemplate termination of the leases subject to the parties agreeing to and executing definitive agreements and to a final settlement agreement with the IRS. Upon termination of the leases, the lessees would be required to make termination payments from certain collateral deposits associated with the leases.

Termination of the leases, which may occur in 2008, would result in Edison International recording an after-tax charge to earnings currently estimated to be at least $650 million, and potentially up to the maximum earnings exposure indicated above. If all settlements included in the global settlement discussions were ultimately concluded consistent with the preliminary understandings, Edison International would expect that the settlement of the disputed lease issues and the resolution of the above-mentioned affirmative claims would result in a portion of the charge initially recorded upon termination of the leases being offset and/or reduced, and the net after-tax earnings charge that would remain is currently expected to be less than half of the maximum after-tax earnings exposure, calculated as of June 30, 2008, discussed above. Were all settlements completed in a manner consistent with the preliminary understandings, the net cash impact upon Edison International as a whole of the settlements and lease terminations would be positive over time, and it is not anticipated that borrowings would be required in connection with implementation of the settlements.

There can be no assurance, however, about the timing of final settlements with the IRS or that such final settlements will be ultimately consummated. Moreover, even if final settlements are reached with the IRS, review by the Joint Committee could result in adjustments. The IRS and Edison International may not reach final agreements that implement the preliminary understandings, or they may reach final agreements but conditions to consummating them may not be satisfied. If Edison International terminated the SILO and LILO leases without consummating the settlements, then it could not seek through litigation with the IRS future deferred tax benefits that may have been otherwise available in the absence of termination.

to commence litigation in certain forums, it would need to make payments of the disputed taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. In the other litigation forum (the Tax Court), no upfront payment would be required. In 2006, Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by a refund claim for the same amount. The IRS did not act on this refund claim within the statutory six month period, which provides Edison International with the option of being able to take legal action to assert its refund claim. To the extent an acceptable settlement is not reached with the IRS, Edison International would expect to file a refund claim for any taxes and penalties paid for the 1994 – 1996 tax years related to the leases. Edison International has not decided whether and to what extent it would make additional payments related to later tax years to fund its right to litigate in certain forums should the global settlement discussed above not be consummated.

Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations and Administrative Appeals

Edison International continues its efforts to resolve open tax issues through tax year 2002. Although the timing for resolving these open tax positions is uncertain, it is reasonably possible that all or a significant portion of these open tax issues through tax year 2002 could be resolved within the next 12 months.

Note 4. Compensation and Benefits Plans

Pension Plans

As of June 30, 2008, Edison International had made $7 million in contributions related to 2007 and $31 million related to 2008 and estimates to make $26 million of additional contributions in the last six months of 2008. Expected contribution funding in 2008 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.

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

Expense components are:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2008			2007			2008			2007
		(Unaudited)
Service cost	$	32		$	31		$	63		$	62
Interest cost		50			47			100			94
Expected return on plan assets		(65	)		(63	)		(131	)		(126	)
Amortization of prior service cost		4			4			8			8
Amortization of net loss		—			1			1			2
Expense under accounting standards		21			20			41			40
Regulatory adjustment – deferred		—			1			—			2
Total expense recognized	$	21		$	21		$	41		$	42

Postretirement Benefits Other Than Pensions

As of June 30, 2008, Edison International had made no contributions related to 2007 and $11 million related to 2008 and estimates to make $43 million of additional contributions in the last six months of 2008. Expected contribution funding in 2008 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.

Expense components are:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2008			2007			2008			2007
		(Unaudited)
Service cost	$	12		$	11		$	23		$	23
Interest cost		35			32			69			64
Expected return on plan assets		(31	)		(30	)		(62	)		(60	)
Amortization of prior service credit		(8	)		(8	)		(15	)		(16	)
Amortization of net loss		4			7			9			13
Total expense recognized	$	12		$	12		$	24		$	24

Stock-Based Compensation

During the first quarter of 2008, Edison International granted its 2008 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 $12 million and $22 million for the three months ended June 30, 2008 and 2007, respectively, and was $19 million and $29 million for the six months ended June 30, 2008 and 2007, respectively. The income tax benefit recognized in the consolidated statements of income was $5 million and $9 million for the three months ended June 30, 2008 and 2007, respectively, and was $8 million and $12 million for the six months ended June 30, 2008 and 2007, respectively. Total stock-based compensation cost capitalized was $1 million and $2 million for the three months ended June 30, 2008 and 2007, respectively, and was $2 million and $3 million for the six months ended June 30, 2008 and 2007, respectively.

Stock Options

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


			Weighted-Average
	Stock Options		Exercise Price		Remaining Contractual Term (Years)	Aggregate Intrinsic Value
	(Unaudited)
Outstanding at December 31, 2007	12,105,642		$	30.55
Granted	2,413,571		$	50.05
Expired	(500	)	$	28.94
Forfeited	(79,875	)	$	48.42
Exercised	(765,067	)	$	26.16
Outstanding at June 30, 2008	13,673,771		$	34.14	6.68
Vested and expected to vest at June 30, 2008	13,177,004		$	33.68	6.61	$	234,188,177
Exercisable at June 30, 2008	8,263,026		$	26.43	5.49	$	206,753,854

Stock options granted in 2008 do not accrue dividend equivalents.

The amount of cash used to settle stock options exercised was $27 million and $77 million for the three months ended June 30, 2008 and 2007, respectively, and was $40 million and $163 million for the six months ended June 30, 2008 and 2007, respectively. Cash received from options exercised was $13 million and $33 million for the three months ended June 30, 2008 and 2007, respectively, and was $20 million and $72 million for the six

months ended June 30, 2008 and 2007, respectively. The estimated tax benefit from options exercised was $5 million and $18 million for the three months ended June 30, 2008 and 2007, respectively, and was $8 million and $36 million for the six months ended June 30, 2008 and 2007, respectively.

Note 5. Commitments and Contingencies

The following is an update to Edison International’s commitments and contingencies. See Note 6 of “Notes to Consolidated Financial Statements” included in Edison International’s 2007 Annual Report on Form 10-K for a detailed discussion.

Lease Commitments

During the second quarter of 2008, SCE entered into power-purchase contracts which are classified as operating leases. The contract terms range from 10 to 40 years. The delivery of energy under one of these contracts is not expected to commence until 2018. These additional commitments are currently estimated to be: remainder of 2008 – $27 million, 2009 – $48 million, 2010 – $48 million, 2011 – $48 million, 2012 – $48 million and thereafter – $1.9 billion.

Other Commitments

During the first six months of 2008, SCE entered into service contracts associated with uranium enrichment and fuel fabrication. As a result, SCE’s additional fuel supply commitments are estimated to be: remainder of 2008 – $15 million, 2009 – $49 million, 2010 – $50 million, 2011 – $96 million, 2012 – $141 million and thereafter – $665 million.

During the second quarter of 2008, SCE entered into a new power-purchase contract. The delivery of energy under this contract is expected to commence in August 2010 with a 10 year term. SCE’s additional commitments upon commencement are estimated to be: 2010 – $188 million, 2011 – $335 million, 2012 – $341 million and thereafter – $2.7 billion.

At June 30, 2008, EME’s subsidiaries had firm commitments to spend approximately $259 million during the remainder of 2008 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. These expenditures are planned to be financed by cash on hand, cash generated from operations or existing subsidiary credit agreements.

EME had entered into various turbine supply agreements with vendors to support its wind and thermal development efforts. At June 30, 2008, EME had secured 533 wind turbines (1,061 MW) and 5 gas-fired turbines (479 MW) for use in future projects for an aggregate purchase price of $1.6 billion, with remaining commitments of $407 million in 2008, $557 million in 2009 and $300 million in 2010. At June 30, 2008, EME had recorded wind turbine deposits of $294 million included in other long-term assets in its consolidated balance sheet.

In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buyout its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million after tax) during the first quarter of 2008. The remaining payments due under this contract are $18 million.

EME’s subsidiaries had entered into contractual agreements during the first six months of 2008 to purchase materials for environmental controls equipment. These commitments are currently estimated to be $188 million, summarized as follows: remainder of 2008 – $7 million, 2009 – $29 million, 2010 – $45 million, 2011 – $45 million, 2012 – $43 million and thereafter – $19 million.

Guarantees and Indemnities

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

Tax Indemnity Agreements

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

Indemnities Provided as Part of the Acquisition of the Illinois Plants

In connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to 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. By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV discussed below under “Midwest Generation New Source Review Notice of Violation.” By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Except as discussed below, EME has not recorded a liability related to this indemnity.

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 2009. Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were approximately 230 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2008. Midwest Generation had recorded a $53 million liability at June 30, 2008 related to this matter.

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

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

In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed the obligations of EME Homer City. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. EME has not recorded a liability related to this indemnity.

Indemnities Provided under Asset Sale Agreements

The asset sale agreements for the sale of EME’s international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At June 30, 2008, EME had recorded a liability of $108 million 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 June 30, 2008, EME had recorded a liability of $12 million related to these matters.

Capacity Indemnification Agreements

EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project’s power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. The obligations under this indemnification agreement as of June 30, 2008, if payment were required, would be $66 million. EME has not recorded a liability related to this indemnity.

Indemnity Provided as Part of the Acquisition of Mountainview

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

Mountainview Filter Cake Indemnity

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

Other Edison International Indemnities

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

Contingencies

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

Environmental Remediation

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

Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that additional costs would be recovered from customers or that Edison International’s consolidated financial position and results of operations would not be materially affected.

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

As of June 30, 2008, Edison International’s recorded estimated minimum liability to remediate its 44 identified sites at SCE (24 sites) and EME (20 sites primarily related to Midwest Generation) was $64 million, $59 million of which was related to SCE including $24 million related to San Onofre. This remediation liability is undiscounted. 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 $155 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 30 immaterial sites whose total liability ranges from $3 million (the recorded minimum liability) to $9 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $33 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 $56 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.

Edison International 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 $31 million. Recorded costs for the 12 months ended June 30, 2008 were $25 million.

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 consolidated results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Federal and State Income Taxes

As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income taxes associated with certain lease and kind of lease transactions. See Note 3 for further details.

FERC Transmission Incentives

On November 16, 2007, the FERC issued an order granting incentives on three of SCE’s largest proposed transmission projects:

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A 125 basis point ROE adder on SCE’s future proposed base ROE (“ROE Adder”) for DPV2, which is a high voltage (500 kV) transmission line from the Valley substation to the Devers substation near Palm Springs, California to a new substation near Palo Verde, west of Phoenix, Arizona;

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A 125 basis point ROE Adder for the Tehachapi Transmission Project, which is an eleven segment project consisting of newly-constructed and upgraded transmission lines and associated substations to interconnect renewable generation projects near the Tehachapi and Big Creek area; and

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A 75 basis point ROE Adder for the Rancho Vista Substation Project, which is a new 500 kV substation in the City of Rancho Cucamonga.

The order also grants a higher return on equity on SCE’s entire transmission rate base in SCE’s next FERC transmission rate case for SCE’s participation in the CAISO. On August 1, 2008, SCE filed a revision to its Transmission Owner Tariff with a requested effective date of October 1, 2008. In addition, the order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, of all three projects and 100% recovery of prudently-incurred abandoned plant costs for DPV2 and Tehachapi, if either or both of these projects are cancelled due to factors beyond SCE’s control.

FERC Construction Work in Progress Mechanism

On December 21, 2007, SCE filed a revision to its Transmission Owner Tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects. In the CWIP filing, SCE proposed a single-issue rate adjustment ($45 million or a 14.4% increase) to SCE’s currently authorized base transmission revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders approved for Tehachapi, DPV2 and Rancho Vista). SCE projects that it will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively, from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to projected consulting and legal costs associated with SCE’s continued efforts to obtain regulatory approvals necessary to construct the DPV2 Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on March 1, 2008, subject to refund on the limited issue of whether SCE’s proposed ROEs are reasonable. On March 28, 2008, the CPUC filed a Petition for Rehearing with the FERC on the FERC’s acceptance of SCE’s proposed ROE for CWIP. Briefs addressing the appropriate ROE were filed by SCE and intervenors in May 2008.

In addition, in the order, SCE was directed by FERC to make a compliance filing to provide greater detail on the costs reflected in CWIP rates for 2008. SCE made the compliance filing on March 31, 2008. On April 21, 2008, the CPUC filed a protest of the compliance filing at FERC and requested an evidentiary hearing to be set to further review the costs. SCE filed a response to the CPUC’s protest on May 6, 2008 arguing that the FERC should deny the CPUC’s request for a further hearing.

SCE cannot predict the outcome of the matters in this proceeding.

Investigations Regarding Performance Incentives Rewards

SCE was eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability. SCE conducted investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below.

Customer Satisfaction

SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE’s transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The

results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or penalties for customer satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million over the period 1997 – 2000. Potential customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of approximately $10 million for 2003.

Following its internal investigation, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5 million of the PBR rewards pending that are both attributable to the design organization’s portion of the customer satisfaction rewards for the entire PBR period (1997 – 2003). In addition, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards associated with meter reading.

SCE has taken remedial action as to the customer satisfaction survey misconduct by disciplining employees and/or terminating certain employees, including several supervisory personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls over data collection and processing. Performance incentive rewards for customer satisfaction expired in 2003 pursuant to the 2003 GRC.

Employee Injury and Illness Reporting

In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE’s employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has recognized $20 million in employee safety incentives for 1997 through 2000 and, based on SCE’s records, may be entitled to an additional $15 million for 2001 through 2003.

On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE’s performance under the PBR incentive mechanism for injury and illness reporting. SCE disclosed in the investigative findings to the CPUC that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.

As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism and return to ratepayers the $20 million it has already received. SCE has also proposed to withdraw the pending rewards for the 2001 – 2003 time frames.

SCE has taken remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance, disciplining employees who committed wrongdoing and terminating one employee. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004.

System Reliability

In light of the problems uncovered with the PBR mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability for the years 1997 – 2003. SCE received $8 million in reliability incentive awards for the period 1997 – 2000 and applied for a reward of $5 million for 2001. For 2002, SCE’s data indicated that it earned no reward and incurred no penalty. For 2003, based on the application of the PBR mechanism, it would incur a penalty of $3 million and accrued a charge for that amount in 2004. On February 28, 2005, SCE provided its final investigation report to the CPUC concluding that the reliability reporting system was working as intended.

CPUC Investigation

On June 15, 2006, the CPUC instituted a formal investigation to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, employee safety and system reliability portions of PBR. In June 2006, the CPSD of the CPUC issued its report regarding SCE’s PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUC’s DRA and The Utility Reform Network, filed testimony on these matters recommending various refunds and penalties be imposed on SCE. In their testimony, the various parties made refund and penalty recommendations that range up to the following amounts: refund or forgo $48 million in rewards for customer satisfaction, impose $70 million in penalties for customer satisfaction, refund or forgo $35 million in rewards for employee safety, impose $35 million in penalties for employee safety, impose $102 million in statutory penalties, refund $84 million related to amounts collected in rates for employee bonuses (“results sharing”), refund $4 million of miscellaneous survey expenses, and require $10 million of new employee safety programs. These recommendations total up to $388 million. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors.

On October 1, 2007, a POD was released ordering SCE to refund $136 million, before interest, and pay a statutory penalty of $40 million. Included in the amount to be refunded are $28 million related to customer satisfaction rewards, $20 million related to employee safety rewards, and $77 million related to results sharing. The decision requires that the proposed results sharing refund of $77 million (based on year 2000 data) be adjusted for attrition and escalation which increases the results sharing refund to $88 million. Interest as of June 30, 2008, based on amounts collected for customer satisfaction, employee safety incentives and results sharing, including escalation and attrition adjustments, would add an additional $31 million to this amount. The POD also requires SCE to forgo $35 million in rewards for which it would have otherwise been eligible. Included in the amount to be forgone is $20 million related to customer satisfaction rewards and $15 million related to employee safety rewards.

On October 31, 2007, SCE appealed the POD to the CPUC. The CPSD and an intervenor also filed appeals. The CPSD appeal requested that: (1) the statutory penalty be increased from $40 million to $83 million (2) a penalty be imposed under the PBR customer satisfaction and employee safety mechanisms in the amount of $48 million and $35 million, respectively, and (3) SCE refund/forgo rewards earned under the customer satisfaction and employee safety mechanisms of $48 million and $35 million, respectively. The appealing intervenor asked that the statutory penalty be increased to as much as $102 million. Oral argument on the appeals took place on January 30, 2008, and it is uncertain when the CPUC will issue a decision.

SCE cannot predict the outcome of the appeal. Based on SCE’s proposed refunds, the combined recommendations of the CPSD and other intervenors, as well as the POD, the potential refunds and penalties could range from $52 million up to $388 million. SCE has recorded an accrual at the lower end of this range of potential loss and is accruing interest (approximately $17 million as of June 30, 2008) on collected amounts.

The system reliability component of PBR was not addressed in the POD. Pursuant to an earlier order in the case, system reliability incentives will be addressed in a second phase of the proceeding, which commenced with the filing of SCE’s opening testimony in September 2007. In that testimony, SCE confirmed that its PBR system reliability results, which reflected rewards of $13 million for 1997 through 2002 and a penalty of $3 million in 2003 were valid. An indefinite suspension of the schedule for the second phase of the proceeding pending resolution of the appeals of the POD has been granted. SCE cannot predict the outcome of the second phase.

EME Homer City New Source Review Notice of Violation

Significant Deterioration requirements of the Clean Air Act. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. EME Homer City intends to meet with the US EPA to discuss the alleged violations. EME Homer City is investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at this time what effect this matter may have 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 the defense of the claims.

ISO Disputed Charges

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. The order reversed an arbitrator’s award that had affirmed the ISO’s characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those charges to scheduling coordinators in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from scheduling coordinators in the affected zone to the responsible participating transmission owner, SCE. The potential cost to SCE, net of amounts SCE expects to receive through the PX, SCE’s scheduling coordinator at the time, is estimated to be approximately $20 million to $25 million, including interest. On April 20, 2005, the FERC stayed its April 20, 2004 order during the pendency of SCE’s appeal filed with the Court of Appeals for the D.C. Circuit. On March 7, 2006, the Court of Appeals remanded the case back to the FERC at the FERC’s request and with SCE’s consent. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the limited purpose of allowing the FERC to give it further consideration. In a future order, FERC may deny the rehearing request or grant the requested relief in whole or in part. SCE believes that the most recent substantive FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot predict the final outcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in its reliability service rates. SCE cannot predict whether recovery of these charges in its reliability service rates would be permitted.

Leveraged Lease Investments

At June 30, 2008, Edison Capital had a net leveraged lease investment, before deferred taxes, of $53 million in three aircraft leased to American Airlines. American Airlines reported net losses for its first and second quarters in 2008 and previously reported losses for a number of years prior to 2006. A default in the leveraged lease by American Airlines could result in a loss of some or all of Edison Capital’s lease investment. At June 30, 2008, American Airlines was current in its lease payments to Edison Capital.

Midway-Sunset Cogeneration Company

San Joaquin Energy Company, a wholly owned subsidiary of EME, owns a 50% general partnership interest in Midway-Sunset, which owns a 225 MW cogeneration facility near Fellows, California. Midway-Sunset is a party to several proceedings pending at the FERC because Midway-Sunset was a seller in the PX market during 2000 and 2001, both for its own account and on behalf of SCE and PG&E, the utilities to which the majority of Midway-Sunset’s power was contracted for sale. As a seller into the PX market, Midway-Sunset is potentially liable for refunds to purchasers in these markets.

liability in the FERC refund proceedings. Midway-Sunset concurrently entered into a separate agreement with SCE and PG&E that provides for pro-rata reimbursement to Midway-Sunset by the two utilities of the portions of the agreed to refunds that are attributable to sales made by Midway-Sunset for the benefit of the utilities (Midway-Sunset did not retain any proceeds from power sold into the PX market on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed through those proceeds to the utilities). The settlement, which had been approved previously by the CPUC, was approved by the FERC on April 2, 2008.

During the period in which Midway-Sunset’s generation was sold into the PX market, amounts SCE received from Midway-Sunset for its pro-rata share of such sales were credited to SCE’s customers against power purchase expenses through the ratemaking mechanism in place at that time. During the second quarter of 2008, SCE reimbursed Midway-Sunset for its pro-rata share of the Midway-Sunset liability in the amount of approximately $43 million. In addition, SCE, as party to the Midway-Sunset settlement agreement, received a $20 million generator refund. The amount reimbursed to and received from Midway-Sunset (net amount of $23 million) were charged/refunded to ratepayers through regulatory mechanisms. SCE’s reimbursement to Midway-Sunset and the refund payment received from Midway-Sunset did not impact earnings.

Midwest Generation New Source Review Notice of Violation

On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install best available control technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the US EPA, and the United States DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. As a result, Midwest Generation is investigating the claims made by the US EPA in the NOV and has identified several defenses which it will raise if the government files suit. Midwest Generation cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.

On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by several Chicago-based environmental action groups stating that, in light of the NOV, the groups are examining the possibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumably on the same or similar theories advanced by the US EPA in the NOV.

By letter dated August 8, 2007, Commonwealth Edison advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV.

Navajo Nation Litigation

The Navajo Nation filed a complaint in June 1999 in the D.C. District Court 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.

In April 2004, the D.C. District Court denied SCE’s motion for summary judgment and concluded that a 2003 U.S. Supreme Court decision in an on-going related lawsuit by the Navajo Nation against the U.S. Government did not preclude the Navajo Nation from pursuing its RICO and intentional tort claims. In September 2007, the Federal Circuit reversed a lower court decision on remand in the related lawsuit, finding that the U.S. Government had breached its trust obligation in connection with the setting of the royalty rate for the coal supplied to Mohave. Subsequently, the Federal Circuit denied the U.S. Government’s petition for rehearing. On May 13, 2008, the U.S. Government filed a petition seeking review by the U.S. Supreme Court of the Federal Circuit’s September 2007 decision. The Navajo Nation’s response to the petition was due on August 4, 2008.

Pursuant to a joint request of the parties, the D.C. District Court granted a stay of the action in October 2004 to allow the parties to attempt to negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. In a joint status report filed on November 9, 2007, the parties informed the court that their mediation efforts had terminated and subsequently filed a joint motion to lift the stay. The parties have also filed recommendations for a scheduling order to govern the anticipated resumption of litigation. The Court granted the motion to lift the stay on March 6, 2008, reinstating the case to the active calendar, but has deferred setting an overall schedule for the action pending a determination of disputes concerning the discoverability of certain Navajo documents. SCE cannot predict the outcome of the Navajo Nation’s and Hopi Tribe’s complaints against SCE or the ultimate impact on these complaints of the Supreme Court’s 2003 decision and the on-going litigation by the Navajo Nation against the U.S. Government in the related case.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $10.8 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. The current maximum deferred premium for each nuclear incident is approximately $101 million per reactor, but not more than $15 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 will be adjusted for inflation at least once every five years beginning August 20, 2003. The next inflation adjustment should occur no later than August 20, 2008. Based on its ownership interests, SCE could be required to pay a maximum of approximately $201 million per nuclear incident. However, it would have to pay no more than approximately $30 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 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.

Palo Verde Nuclear Generating Station Outage and Inspection

The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. The combination of the results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, was completed in December 2007. In addition, Palo Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant personnel and self-assessments of its programs and procedures. The NRC and APS defined and agreed to inspection and survey corrective actions that the NRC embodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track to complete the corrective actions required to close the Confirmatory Action Letter by mid-2009. Palo Verde operation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in 2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. SCE is unable to estimate how long SCE will continue to incur these costs.

Procurement of Renewable Resources

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

SCE filed its compliance report in March 2008. Through the use of flexible compliance rules, SCE demonstrated full compliance for the procurement year 2007 and forecasted full compliance for the procurement years 2008 to 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. 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 failure 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 filing. Under the CPUC’s current rules, the maximum penalty for failing to achieve renewable procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties.

RPM Buyers’ Complaint

On May 30, 2008, a group of entities referring to themselves as the “RPM Buyers” filed a complaint at the FERC asking that PJM’s RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust and unreasonable capacity prices. The RPM Buyers alleged that the absence of price discipline provided by new capacity resources, together with the ability of existing resources to withhold some capacity within the RPM rules, produced capacity prices in the transition period that are not comparable to those that would have been produced in a competitive market or determined under cost-based regulation, and have requested that the FERC order refunds based on that difference.

and adjudicated in the contested proceedings involving the RPM settlement. A number of other parties, including PJM, also responded to the RPM Buyers’ complaint asking that the same be dismissed. This matter is currently pending before the FERC. EME cannot predict the outcome of this matter.

Scheduling Coordinator Tariff Dispute

Pursuant to the Amended and Restated Exchange Agreement, SCE serves as a scheduling coordinator for the DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized scheduling coordinator and line loss charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges had been billed to the DWP under a FERC tariff that was subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC.

In January 2008, an agreement between SCE and the DWP was executed settling the dispute discussed above. The settlement had been previously approved by the FERC in July 2007. The settlement agreement provides that the DWP will be responsible for line losses and SCE would be responsible for the scheduling coordinator charges. During the fourth quarter of 2007, SCE reversed and recognized in earnings (under the caption “Purchased power” in the consolidated statements of income) $30 million of an accrued liability representing line losses previously collected from the DWP that were subject to refund. As of December 31, 2007, SCE had an accrued liability of approximately $22 million (including $3 million of interest) representing the estimated amount SCE will refund for scheduling coordinator charges previously collected from the DWP. SCE made its first refund payment on February 20, 2008 and the second refund payment was made on February 27, 2008. SCE previously received FERC approval to recover the scheduling coordinator charges from all transmission grid customers through SCE’s transmission rates and on December 11, 2007, the FERC accepted SCE’s proposed transmission rates reflecting the forecast levels of costs associated with the settlement. Upon signing of the agreement in January 2008, SCE recorded a regulatory asset and recognized in earnings the amount of scheduling coordinator charges to be collected through rates. SCE filed a refund report with the FERC on March 4, 2008. FERC approved the refund report on July 8, 2008.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its obligation to begin acceptance of spent nuclear fuel not later than 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 through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the 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 case was stayed through April 7, 2006, when SCE and the DOE filed a Joint Status Report in which SCE sought to lift the stay and the government opposed lifting the stay. On June 5, 2006, the Court of Federal Claims lifted the stay on SCE’s case and established a discovery schedule. In a Joint Status Report filed on July 1, 2008, the parties requested a trial date in mid-November 2008. On August 6, 2008, the Court set a trial date of April 14 – 28, 2009.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation where all of Unit 1’s spent fuel located at San Onofre and some of Unit 2 and 3’s spent fuel is stored. SCE, as operating agent, plans to transfer fuel from the Unit 2 and 3 spent fuel pools to the independent

storage installation on an as-needed basis to maintain full core off-load capability for Units 2 and 3. There are now sufficient dry casks and modules available at the independent spent fuel storage installation to meet plant requirements through the end of 2008. SCE plans to add storage capacity incrementally to meet the plant requirements until 2022 (the end of the current NRC operating license).

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

Note 6. Accumulated Other Comprehensive Income (Loss) Information

Edison International’s accumulated other comprehensive income (loss) consists of:


In millions	Unrealized Gain (Loss) on Cash Flow Hedges			Foreign Currency Translation Adjustment	Pension and PBOP– Net Loss	Pension and PBOP– Prior Service Cost		Accumulated Other Comprehensive Income (Loss)
		(Unaudited)
Balance at December 31, 2007	$	(60	)	$ (1)	$ (34)	$	3	$	(92	)
Current period change		(320	)	(3)	—		—		(323	)
Balance at June 30, 2008	$	(380	)	$ (4)	$ (34)	$	3	$	(415	)

Unrealized losses on cash flow hedges, net of tax, at June 30, 2008, included unrealized losses on commodity hedges related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in these markets are greater than the contract prices. As EME’s hedged positions for continuing operations are realized, $257 million, after tax, of the net unrealized losses on cash flow hedges at June 30, 2008 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized losses will decrease 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.

Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net losses of $18 million and $9 million during the second quarters of 2008 and 2007, respectively, and $31 million and $10 million during the six months ended June 30, 2008 and 2007, respectively, representing the amount of cash flow hedges’ ineffectiveness for continuing operations, reflected in nonutility power generation revenues in Edison International’s consolidated income statements.

Note 7. Supplemental Cash Flows Information

Edison International’s supplemental cash flows information is:


	Six Months Ended June 30,
In millions	2008		2007
		(Unaudited)
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	386	$	362
Tax payments (receipts)		128		(19	)

Noncash investing and financing activities:
Details of obligation under capital lease:
Capital lease asset purchased	$	—	$	10
Capital lease obligation issued		—		(10	)
Dividends declared but not paid:
Common stock	$	99	$	94
Preferred and preference stock of utility not subject to mandatory redemption		13		13
Details of assets acquired:
Fair value of assets acquired	$	—	$	29

In connection with certain wind projects acquired during the second quarter of 2008 and the first quarter of 2007, the purchase price included payments that were due upon the start and/or completion of construction. Accordingly, EME accrued for estimated payments during the first six months of 2008 and 2007 which were due upon commencement of construction and/or completion of construction scheduled during 2008 through 2009.

Note 8. Fair Value Measurements

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price” in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity’s nonperformance risk.

The standard establishes a hierarchy for fair value measurements. Financial assets and liabilities carried at fair value on a recurring basis are classified and disclosed in the three categories outlined below:

•

Level 1 – Observable inputs that reflect quoted market prices (unadjusted) for identical assets and liabilities in active markets;

•

Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly; and

•

Level 3 – Unobservable inputs using data that is not corroborated by market data and primarily based on internal company analysis.

Edison International’s assets and liabilities carried at fair value primarily consist of derivative positions for both SCE and EME. These positions may include forward sales and purchases of physical power, options and forward price swaps which settle only on a financial basis (including futures contracts). In assessing the fair value of Edison International’s derivative financial instruments, Edison International 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. In addition, SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed income securities.

Level 1 includes derivatives that are exchange traded in active markets, as well as SCE’s nuclear decommissioning trust investments in equity and U.S. treasury securities. The fair values for these derivatives and equity securities are determined using quoted exchange transaction market prices. U.S. treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market.

Level 2 includes traded derivatives using over-the-counter markets and exchange traded derivatives not classified as Level 1. The fair value of these derivatives is determined using forward market prices adjusted for credit risk. The majority of EME’s Level 2 derivatives are entered into for hedging purposes. Level 2 also includes SCE’s nuclear decommissioning trust investments in other fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

Level 3 includes the majority of SCE’s derivatives, including over-the-counter options, bilateral contracts, FTRs and CRRs in the California market, capacity and QF contracts. The fair value of these SCE derivatives is determined using uncorroborated broker quotes and models that mainly extrapolate short-term observable inputs. Level 3 also includes derivatives that trade infrequently such as FTRs and over-the-counter derivatives at illiquid locations and long-term power agreements. For illiquid FTRs, Edison International reviews objective criteria related to system congestion on a quarterly basis 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 hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is 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. 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.

When appropriate, valuations are adjusted for various factors including liquidity, bid/offer spreads and credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. The following table sets forth financial assets and liabilities that were accounted for at fair value as of June 30, 2008 by level within the fair value hierarchy.


In millions	Level 1			Level 2			Level 3			Netting and Collateral⁽¹⁾			Total at June 30, 2008
		(Unaudited)
Assets at Fair Value
Derivative contracts	$	4		$	312		$	469		$	(25	)	$	760
Nuclear decommissioning trusts⁽²⁾		2,080			997			—			—			3,077
Long-term disability plan		—			6			—			—			6
Total assets⁽³⁾		2,084			1,315			469			(25	)		3,843
Liabilities at Fair Value
Derivative contracts		(9	)		(734	)		(83	)		228			(598	)
Net assets	$	2,075		$	581		$	386		$	203		$	3,245

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

(2)	Excludes net assets of $75 million of cash and equivalents, interest and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases.

(3)	Excludes $32 million of cash surrender value of life insurance investments for deferred compensation.

The following table sets forth a summary of changes in the fair value of Level 3 derivative contracts, net for the three- and six-month periods ended June 30, 2008.


In millions	Three Months Ended June 30, 2008			Six Months Ended June 30, 2008
		(Unaudited)
Fair value of derivative contracts, net at beginning of period	$	190		$	98
Total realized/unrealized gains (losses):
Included in earnings⁽¹⁾		59			92
Included in regulatory assets and liabilities⁽²⁾		112			165
Included in accumulated other comprehensive loss		(4	)		(6	)
Purchases and settlements, net		36			47
Transfers in or out of Level 3		(7	)		(10	)
Fair value of derivative contracts, net at end of period	$	386		$	386
Change during the period in unrealized gains related to net derivative contracts, held at June 30, 2008⁽³⁾	$	183		$	213

(1)

$59 million and $92 million reported in “Nonutility power generation” revenue on Edison International’s consolidated statements of income for the three- and six-month periods ended June 30, 2008, respectively.

(2)

$112 million and $165 million reported in “Purchased power” expense and, due to expected recovery through regulatory mechanisms, are offset in “Provisions for regulatory adjustment clauses – net” on Edison International’s consolidated statements of income for the three- and six-month periods ended June 30, 2008, respectively.

(3)

$34 million and $37 million reported in “Nonutility power generation” revenue and $149 million and $176 million reported in “Purchased power” expense on Edison International’s consolidated statements of income for the three- and six-month periods ended June 30, 2008, respectively. Due to expected recovery through regulatory mechanisms, the amounts in “Purchased power” are offset in “Provisions for regulatory adjustment clauses – net.”

Nuclear Decommissioning Trusts

SCE has collected 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.

Trust investments (at fair value) include:


In millions	Maturity Dates	June 30, 2008		December 31, 2007
			(Unaudited)
Municipal bonds	2008 – 2044	$	570	$	561
Stocks	–		1,841		1,968
United States government issues	2008 – 2049		362		552
Corporate bonds	2008 – 2047		304		241
Short-term	2008		75		56
Total		$	3,152	$	3,378

Note: Maturity dates as of June 30, 2008.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Net earnings were $26 million and $34 million for the three months ended June 30, 2008 and 2007, respectively, and $57 million and $71 million for the six months ended June 30, 2008 and 2007, respectively. Proceeds from sales of securities (which are reinvested) were $668 million and $987 million for the three months ended June 30, 2008 and 2007, respectively, and $1.5 billion and $2.0 billion for the six months ended June 30, 2008 and 2007, respectively. Cumulative unrealized holding gains, net of losses, were $950 million and $1.1 billion at June 30, 2008 and December 31, 2007, respectively. Realized losses for other-than-temporary impairments were $27 million and $15 million for the three months ended June 30, 2008 and 2007, respectively, and $72 million and $23 million for the six months ended June 30, 2008 and 2007, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.

Note 9. Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:


In millions	June 30, 2008		December 31, 2007
		(Unaudited)
Current:
Regulatory balancing accounts	$	167	$	99
Energy derivatives		8		71
Purchased-power settlements		4		8
Deferred FTR proceeds		12		15
Other		12		4
		203		197
Long-term:
Regulatory balancing accounts		11		15
Flow-through taxes – net		1,155		1,110
Unamortized nuclear investment – net		391		405
Nuclear-related asset retirement obligation investment – net		287		297
Unamortized coal plant investment – net		83		94
Unamortized loss on reacquired debt		320		331
SFAS No. 158 pensions and postretirement benefits		237		231
Energy derivatives		61		70
Environmental remediation		56		64
Other		122		104
		2,723		2,721
Total Regulatory Assets	$	2,926	$	2,918

Regulatory liabilities included in the consolidated balance sheets are:


In millions	June 30, 2008		December 31, 2007
		(Unaudited)
Current:
Regulatory balancing accounts	$	895	$	967
Rate reduction notes – transition cost overcollection		20		20
Energy derivatives		248		10
Deferred FTR costs		56		19
Other		4		3
		1,223		1,019
Long-term:
Regulatory balancing accounts		7		—
Asset retirement obligations		502		793
Costs of removal		2,256		2,230
SFAS No. 158 pensions and other postretirement benefits		314		308
Energy derivatives		202		27
Employee benefit plans		75		75
		3,356		3,433
Total Regulatory Liabilities	$	4,579	$	4,452

Note 10. Preferred and Preference Stock Not Subject to Mandatory Redemption

In January 2008, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 per share. SCE retired this preferred stock in January 2008 and recorded a $2 million gain on the cancellation of reacquired capital stock (reflected in the caption “Common stock” on the consolidated balance sheets). There is no sinking fund requirement for redemptions or repurchases of preferred stock.

Note 11. Business Segments

Edison International’s reportable business segments include its electric utility operation segment (SCE), a nonutility power generation segment (EME), and a financial services provider segment (Edison Capital). Included in the nonutility power generation segment are the activities of MEHC, the holding company of EME. MEHC’s only substantive activities were its obligations under the senior secured notes which were paid in full on June 25, 2007. MEHC does not have any substantive operations. Edison International evaluates performance of its business segments 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.

Segment information for the three- and six-month periods ended June 30, 2008 and 2007 was:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2008			2007			2008			2007
		(Unaudited)
Operating Revenue:
Electric utility	$	2,754		$	2,459		$	5,105		$	4,681
Nonutility power generation		612			569			1,330			1,241
Financial services		16			18			31			35
All others⁽¹⁾		—			1			—			2
Consolidated Edison International	$	3,382		$	3,047		$	6,466		$	5,959
Net Income (Loss):
Electric utility⁽²⁾	$	157		$	144		$	307		$	325
Nonutility power generation⁽³⁾		72			(73	)		217			65
Financial services		38			26			47			45
All others⁽¹⁾		(6	)		(4	)		(12	)		(9	)
Consolidated Edison International	$	261		$	93		$	559		$	426

(1)	Includes amounts from nonutility subsidiaries, as well as Edison International (parent) that are not significant as a reportable segment.

(2)	Net income available for common stock.

(3)	Includes earnings (loss) from discontinued operations of $(1) million and $2 million for the three months ended June 30, 2008 and 2007, respectively and $(6) million and $5 million for the six months ended June 30, 2008 and 2007, respectively.

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

INTRODUCTION

This MD&A for the three- and six-month periods ended June 30, 2008 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2007, and as compared to the three- and six-month periods ended June 30, 2007. This discussion presumes that the reader has read or has access to Edison International’s MD&A for the calendar year 2007 (the year-ended 2007 MD&A), which was included in Edison International’s 2007 annual report to shareholders and incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the Securities and Exchange Commission.

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

•

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

•

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

•

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

•

market risks affecting SCE’s energy procurement activities;

•

access to capital markets and the cost of capital;

•

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

•

governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market;

•

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

•

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

•

the cost and availability of labor, equipment and materials;

•

the ability to obtain sufficient insurance, including insurance relating to SCE’s nuclear facilities;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

general political, economic and business conditions;

•

weather conditions, natural disasters and other unforeseen events;

•

changes in the fair value of investments and other assets; and

•

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

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

Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. Edison International’s principal operating subsidiaries are SCE, a rate-regulated electric utility, and EMG. EMG is the holding company for its principal wholly owned subsidiaries, EME, which is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities, and Edison Capital, a provider of capital and financial services.

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

This MD&A is presented in 8 major sections. The company-by-company discussion of SCE, EMG, and Edison International (parent) includes discussions of liquidity, market risk exposures, and other matters (as relevant to each principal business segment). The remaining sections discuss Edison International on a consolidated basis. The consolidated sections should be read in conjunction with the discussion of each company’s section.


		PAGE
Current Developments		41
Southern California Edison Company		46
Edison Mission Group		56
Edison International (Parent)		73
Results of Operations and Historical Cash Flow Analysis		75
New Accounting Pronouncements		86
Commitments, Guarantees and Indemnities		87
Other Developments		89

CURRENT DEVELOPMENTS

The following section provides a summary of current developments related to Edison International’s principal business segments. This section is intended to be a summary of those current developments that management believes are of most importance. This section is not intended to be an all-inclusive list of all current developments related to each principal business segment and should be read together with all sections of this MD&A.

EDISON INTERNATIONAL: CURRENT DEVELOPMENTS

Federal and State Income Taxes

Since the late 1990s, the IRS has been challenging tax return positions related to cross-border leveraged lease transactions. During the second quarter of 2008, several court developments addressing income taxation of cross-border leveraged leases occurred. As previously disclosed, Edison Capital had entered into several cross-border leveraged lease transactions: a foreign power plant and an electric locomotive sale/leaseback transaction entered into in 1993 and 1994 (which the IRS refers to as a sale-in/lease-out or “SILO” transaction), foreign power plants and an electric transmission system lease/leaseback transaction entered into in 1997 and 1998 (which the IRS refers to as a lease-in/lease-out or “LILO” transaction), and a lease/service contract transaction entered into in 2000 – 2002 involving a foreign telecommunications system (which the IRS also refers to as a “SILO” transaction).

The court developments represent increased uncertainty about the tax treatment of SILOs and LILOs generally. The IRS continues to challenge tax benefits taken by Edison Capital in its 1993 – 1994 and 1997 – 1998 transactions and is expected to challenge Edison Capital’s 2000-2002 transactions. Despite these developments, Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law and, in the absence of any settlement with the IRS, will continue to vigorously defend its tax treatment of these leases.

Recent developments, however, underscore the uncertain nature of tax conclusions in this area. Edison International believes that its maximum earnings exposure related to these leases, measured as of June 30, 2008, is approximately $1.25 billion after taxes. The exposure includes recomputing the cumulative earnings under the leases in accordance with lease accounting rules, and recording related interest. This exposure does not include IRS asserted penalties of 20%, as Edison International does not believe that even if the tax benefits taken by Edison Capital are successfully challenged by the IRS that these penalties would be sustained. The current and future income and cash positions of SCE and EME are virtually unaffected by these leases.

As previously disclosed, Edison International has been engaged in settlement negotiations with the IRS. These negotiations seek to resolve the lease issues in their entirety and all other outstanding tax disputes for the years 1994 through 2002, including certain affirmative claims for unrecognized tax benefits. See “Edison International Notes to Consolidated Financial Statements—Note 3. Income Taxes.” These negotiations have progressed to the point where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolving such tax disputes on a “global” basis, including the lease issues. Final resolution of such disputes, however, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of such settlements by the Staff of the Joint Committee on Taxation, a committee of the United States Congress (the “Joint Committee”).

the overall settlement before executing final agreements with the IRS and before review by the Joint Committee. Edison Capital and its subsidiaries have executed term sheets with the counterparties to its SILOs and LILOs which contemplate termination of the leases subject to the parties agreeing to and executing definitive agreements and to a final settlement agreement with the IRS. Upon termination of the leases, the lessees would be required to make termination payments from certain collateral deposits associated with the leases.

To the extent that an acceptable settlement is not reached with the IRS, Edison International will continue to vigorously defend its tax treatment of the leases and is prepared to take legal action. If Edison International were to commence litigation in certain forums, it would need to make payments of the disputed taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. In the other litigation forum (the Tax Court), no upfront payment would be required. In 2006, Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by a refund claim for the same amount. The IRS did not act on this refund claim within the statutory six month period, which provides Edison International with the option of being able to take legal action to assert its refund claim. To the extent an acceptable settlement is not reached with the IRS, Edison International would expect to file a refund claim for any taxes and penalties paid for the 1994 – 1996 tax years related to the leases. Edison International has not decided whether and to what extent it would make additional payments related to later tax years to fund its right to litigate in certain forums should the global settlement discussed above not be consummated. See “Federal and State Income Taxes” for further information.

Enterprise-Wide Software System Project

Progress continued during 2008 for the installation of SAP’s Enterprise Resource Planning system. On July 1, 2008, Edison International implemented SAP’s financial, supply chain, and certain work management modules at SCE. In addition, Edison International also implemented the human resources module at SCE and EMG. Edison International expects to implement additional SAP modules in the future.

SCE: CURRENT DEVELOPMENTS

2009 General Rate Case Proceeding

On November 19, 2007, SCE filed its GRC application and subsequently revised its requested 2009 base rate revenue requirement to $5.162 billion. After considering the effects of sales growth and other offsets, SCE’s request would be a $695 million increase over current authorized base rate revenue. On April 15, 2008, the DRA submitted testimony recommending that SCE’s 2009 base rate revenue requirement be increased by approximately $19 million, $676 million less than SCE’s revised request, mainly due to: reductions in capital-related costs, operating and maintenance expense, administrative and general expense, and other miscellaneous proposed reductions. Testimony submitted by TURN, another intervenor, seeks to reduce SCE’s 2009 request by an additional $195 million over the DRA proposed adjustments, mainly due to reduced depreciation expense. See “SCE: Regulatory Matters—Current Regulatory Developments—2009 General Rate Case Proceeding” for further discussion.

2009 FERC Rate Case

On August 1, 2008, SCE filed a revision to its Transmission Owner Tariff with a requested effective date of October 1, 2008 to reflect a proposed $129 million increase in its retail transmission revenue requirements (or a 39% increase over the current retail transmission revenue requirement). If the FERC approves this requested increase, this would amount to a 1.2% system average rate increase due to an increase in transmission capital-related costs as well as the increases in transmission operating and maintenance expenses that SCE expects to incur in 2009 to maintain grid reliability. The proposed transmission revenue requirement is based on an overall return on equity of 12.7%, which is composed of a 12.0% base ROE and 0.7% in transmission incentives previously approved by the FERC (see “SCE: Regulatory Matters—Current Regulatory Developments—FERC Construction Work in Progress Mechanism” for further information). As discussed in “SCE: Liquidity—Capital Expenditures,” SCE is experiencing significant growth in actual and planned expenditures to replace and expand its transmission infrastructure.

Solar Photovoltaic Program

On March 27, 2008, SCE filed an application with the CPUC to implement its Solar Photovoltaic (PV) Program to develop up to 250 MW of utility-owned Solar PV generating facilities ranging in size from 1 to 2 MW each. Targeted at commercial and industrial rooftop space in SCE’s service territory, SCE’s program will use rooftop space from entities that would not otherwise be typical candidates for the net energy metering tariff, which allows customers to offset their usage with electricity generated at their own facilities. SCE proposes to develop these projects at a rate of approximately 50 MW per year at an average cost of $3.50/watt. The estimated base case capital cost for the Solar PV Program is $875 million over the period of the program (2008 – 2013). SCE proposes a reasonableness threshold of $963 million. Subject to CPUC approval, the capital expenditures will be eligible to be included in SCE’s earning asset base if the actual costs of the program are equal to or lower than the reasonableness threshold amount. SCE also proposes to apply the CPUC-approved 100 basis point incentive adder for qualifying utility-owned renewable energy investments. SCE also requested to track costs spent on projects prior to the receipt of the CPUC’s final decision in a memorandum account for potential future recovery. SCE expects a decision on the memorandum account in the fourth quarter of 2008. SCE expects to continue to move forward with projects in advance of the final CPUC decision. Several parties have filed protests to SCE’s Solar PV program application. A scoping memorandum was issued on July 27, 2008 which identified issues to be addressed in the proceeding as well as set evidentiary hearings for November 2008 and a final decision for March 2009. SCE cannot predict the final outcome of this proceeding.

Impacts on Customer Rates

Natural gas prices have significantly increased during 2008 over forecasted prices used to set current generation rate levels and are subject to considerable volatility for the remainder of 2008 and in 2009. The increase in natural gas prices and the effect on power prices have, and are expected to continue to negatively impact SCE’s

ERRA balancing account, which is expected to result in customer rate increases. For further discussion of the ERRA regulatory matters and the impact on customer rates, see “SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates” and “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings.”

EMG: CURRENT DEVELOPMENTS

Industry Developments

Commodity Prices

The 24-hour average market prices for energy at the Northern Illinois Hub and PJM West Hub increased 18% and 23%, respectively, during the six months ended June 30, 2008, compared to the corresponding period in 2007. In addition, the forward energy market prices for 2009 for these locations increased 21% and 41%, respectively, at June 30, 2008 from December 31, 2007. At June 30, 2008, EME had entered into hedge contracts that are recorded at fair value in its consolidated financial statements. Since forward energy prices have increased at June 30, 2008, the hedge contracts are reflected as a liability, with the effective portion of the contracts recorded as a reduction of shareholder’s equity ($379 million after tax). Subsequent to June 30, 2008, forward energy market prices decreased (forward market prices for 2009 at July 29, 2008 decreased 18% and 22%, respectively, for the above locations from June 30, 2008) reflecting the volatile nature of commodity prices. See “EMG: Market Risk Exposures—Commodity Price Risk” for further discussion. During the three-month period ended June 30, 2008 of historically high forward energy market prices, EME increased its hedge position by approximately 11.2 million megawatt hours.

Regulatory Developments

In July 2008, the District of Columbia Circuit Court of Appeals vacated the US EPA’s CAIR and remanded it to the US EPA. In addition, because Pennsylvania and Illinois promulgated their regulations in response to the CAIR, there is substantial uncertainty as to the impact of the Court’s decision on these state regulations. Notwithstanding these developments, the Illinois plants and Homer City facilities continue to be governed by state rules as well as the existing “SIP Call” ozone season NO_X cap-and-trade program (which was due to be replaced by the CAIR). For further discussion, see “Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule.”

Based on the CAIR requirements, Midwest Generation purchased $48 million of annual NO_X allowances under the new CAIR annual NO_X program which was vacated by the court ruling discussed above. As a result of this decision, the annual NO_X allowances may no longer be required. Midwest Generation is currently evaluating the above decision including whether the purchased annual NO_X allowances are impaired which could result in a charge against income during the third quarter ending September 30, 2008.

Extension of Production Tax Credits

New wind projects currently receive federal subsidies in the form of production tax credits. Production tax credits for a ten-year period are available for new projects placed in service prior to December 31, 2008. There have been proposals to extend the deadline for production tax credits beyond the end of 2008, but such proposals have not been enacted. Although EME believes there is significant support for extending production tax credits, congressional action may be delayed until next year, and there can be no guarantee that it will occur at all. EME supports extension of production tax credits, without an interruption, to encourage construction of renewable energy projects and plans to monitor legislative developments.

EME Growth Activities

Renewable Energy

At June 30, 2008, EME had 695 MW of wind projects in service and another 390 MW of wind projects under construction, with scheduled completion dates during 2008. As of the same date, EME had a development pipeline of potential wind projects with an estimated 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. This development pipeline is supported by turbine purchase commitments totaling 1,061 MW for new wind projects. The majority of the turbines are scheduled to be delivered before the end of 2010.

Key activities during the second quarter of 2008 with respect to wind projects were:

•

Completed the acquisition of a 240 MW planned wind project in Illinois, referred to as the Big Sky project with payments tied to various milestones. In addition, EME has commenced pre-construction activities for equipment purchases, site development and interconnection activities. Release of the project for full construction is pending a decision on selection of turbines. For further discussion refer to “Commitments, Guarantees and Indemnities—Turbine Commitments.” The total commitments at June 30, 2008, excluding turbines, are approximately $97 million, including the project acquisition costs. Upon completion, the project plans to sell electricity into the PJM market as a merchant generator or to local utilities under power sales contracts.

•

Acquired and/or completed development and commenced construction with completion scheduled for 2008 of the 19 MW Buffalo Bear wind project located in Oklahoma and the 80 MW Elkhorn Ridge project located in Nebraska. The estimated capital cost of these projects, excluding capitalized interest, is expected to be approximately $168 million. EME owns 66.67% of the Elkhorn Ridge wind project and 100% of the Buffalo Bear wind project. Each project will, after its completion, sell electricity pursuant to power sales agreements.

•

Completed construction and commenced operations of the 29 MW Forward wind project located in Pennsylvania, the 20 MW Odin wind project located in Minnesota, and Phase I (80 MW) of the Goat wind project in Texas.

Subsequent to June 30, 2008, EME commenced construction of the 100 MW High Lonesome wind project located in New Mexico and completed construction and commenced operations of the 61 MW Mountain Wind I wind project located in Wyoming.

In addition, EME submitted bids in competitive solicitations to supply power from solar projects under development in California and has had a number of its proposals short-listed. Initial site and equipment selection have been completed along with preliminary economic feasibility studies. Further project development activities are underway to obtain transmission interconnection, control of sites, and construction costs estimates, as well as the negotiation of power sales agreements with local utilities.

Thermal Energy

During the first quarter of 2008, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power sales agreement is subject to approval of the CPUC which SCE requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate transaction, the contract is also subject to FERC approval, which was requested on May 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013. During the second quarter of 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project.

SOUTHERN CALIFORNIA EDISON COMPANY

SCE: LIQUIDITY

Overview

As of June 30, 2008, SCE had cash and equivalents of $185 million ($112 million of which was held by SCE’s consolidated VIEs). As of June 30, 2008, long-term debt, including current maturities of long-term debt, was $5.47 billion. On March 12, 2008, SCE amended its existing $2.5 billion credit facility, extending the maturity to February 2013 while retaining existing borrowing costs as specified in the facility. The amendment also provides four extension options which, if all exercised, will result in a final termination in February 2017. At June 30, 2008, the credit facility supported $197 million in letters of credit and $800 million of short-term debt outstanding, leaving $1.5 billion available for liquidity purposes.

SCE’s estimated cash outflows during the 12-month period following June 30, 2008 are expected to consist of:

•

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

•

Dividend payments to SCE’s parent company. The Board of Directors of SCE declared a $25 million dividend to Edison International which was paid in January 2008 and two $100 million dividends which were paid in April 2008 and July 2008, respectively;

•

Fuel and procurement-related costs (see “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings”); and

•

General operating expenses.

SCE expects to meet its continuing obligations, including cash outflows for operating expenses and power-procurement, through cash and equivalents on hand, operating cash flows and short-term borrowings. Projected capital expenditures are expected to be financed through operating cash flows and the issuance of short- and long-term debt and preferred equity.

On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (2008 Stimulus Act). The 2008 Stimulus Act includes a provision that provides accelerated bonus depreciation for certain capital expenditures incurred during 2008. Edison International expects that certain capital expenditures incurred by SCE during 2008 will qualify for this accelerated bonus depreciation, which would provide additional cash flow benefits estimated to be approximately $175 million for 2008. Any cash flow benefits resulting from this accelerated depreciation should be timing in nature and therefore should result in a higher level of accumulated deferred income taxes reflected on SCE’s consolidated balance sheets. Timing benefits related to deferred taxes will be incorporated into future ratemaking proceedings, impacting future period cash flow and rate base.

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

Capital Expenditures

As discussed under the heading “SCE: Liquidity—Capital Expenditures” in the year-ended 2007 MD&A, SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its distribution and transmission infrastructure, and to construct and replace generation assets. SCE’s 2008 through 2012 capital forecast includes total spending of up to $19.9 billion, including capital spending for SCE’s Solar PV Program. Recovery of certain of these expenditures is subject to regulatory approvals. During the three- and six-month periods ended June 30, 2008, SCE spent $608 million and $1.17 billion, respectively, in capital expenditures related to its 2008 capital plan. SCE projected capital expenditures for the next five years are as follows: remainder of 2008 – $1.7 billion, 2009 – $4.1 billion, 2010 – $4.5 billion, 2011 – $4.6 billion and 2012 – $3.8 billion.

Credit Ratings

At June 30, 2008, SCE’s credit ratings were as follows:


	Moody’s Rating	S&P Rating	Fitch Rating
Long-term senior secured debt	A2	A	A+
Short-term (commercial paper)	P-2	A-2	F-1

SCE cannot provide assurance that its current credit ratings will remain in effect for any given period of time or that one or more of these ratings will not be changed. These credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.

Dividend Restrictions and Debt Covenants

The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International (see “Edison International (Parent): Liquidity” for further discussion). 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 determines compliance with this capital structure based on a 13-month weighted-average calculation. At June 30, 2008, SCE’s 13-month weighted-average common equity component of total capitalization was 50.5% resulting in the capacity to pay $307 million in additional dividends.

SCE has a debt covenant in its credit facility that requires a debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At June 30, 2008, SCE’s debt to total capitalization ratio was 0.46 to 1.

Margin and Collateral Deposits

SCE has entered into certain margining agreements for power and gas trading activities in support of its procurement plan as approved by the CPUC. SCE’s margin deposit requirements under these agreements can vary depending upon the level of unsecured credit extended by counterparties and brokers, changes in market prices relative to contractual commitments, and other factors. During the first quarter of 2008, SCE implemented FIN 39-1 and elected the option to net collateral with the fair value of derivative assets/liabilities under master netting arrangements. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $18 million at June 30, 2008. In addition, at June 30, 2008, SCE had deposits of $204 million (consisting of $7 million in cash that was not offset against net derivative positions and was reflected in “Margin and collateral deposits” on the consolidated balance sheets and $197 million in letters of credit) with counterparties and other brokers. Cash deposits with brokers and counterparties earn interest at various rates.

Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2008, due to changes in wholesale power and natural gas prices. SCE estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2008, could increase by approximately $555 million over the remaining life of the contracts using a 95% confidence level.

The credit risk exposure from counterparties for power and gas trading activities are measured as the difference between the contract price and current fair value of open positions. 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 June 30, 2008, the amount of exposure as described above, broken down by the credit ratings of SCE’s counterparties, was as follows:


In millions		June 30, 2008
S&P Credit Rating
A or higher		$ 114
A-		12
BBB+		13
BBB		7
BBB-		—
Below investment grade and not rated		112
Total		$ 258

SCE has tolling contracts in which SCE purchases the output of a plant from the counterparty. SCE’s structured transactions may be for multiple years which increases the volatility of the fair value position of the transaction. A number of the counterparties with which SCE has structured transactions do not currently have an investment grade rating or are below investment grade. SCE seeks to mitigate this risk through diversification of its structured transactions, when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from contracts.

SCE requires that counterparties with below investment grade ratings or those that do not currently have an investment grade rating post collateral. In the event of default by the counterparty, SCE would be able to use that collateral to pay for the commodity purchased or to pay the associated obligation in the event of default by the counterparty. Furthermore, all of the contracts that SCE has entered into with counterparties are entered into under SCE’s short-term and long-term procurement plan which has been approved by the CPUC. As a result, SCE would qualify for regulatory recovery for any defaults by counterparties on these transactions. In addition, SCE closely monitors any changes that may affect the counterparties’ ability to perform.

SCE: REGULATORY MATTERS

Current Regulatory Developments

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

Impact of Regulatory Matters on Customer Rates

The following table summarizes SCE’s system average rates and the portion related to CDWR which is not recognized as revenue by SCE, but included in the SCE system average rate, at various dates in 2007 and 2008:


Date	SCE System Average Rate	Portion Related to CDWR
January 1, 2007	14.5¢ per-kWh	3.1¢ per-kWh
February 14, 2007	13.9¢ per-kWh	3.0¢ per-kWh
January 1, 2008	13.8¢ per-kWh	2.9¢ per-kWh
March 1, 2008	13.9¢ per-kWh	2.9¢ per-kWh
April 7, 2008	13.8¢ per-kWh	2.9¢ per-kWh
June 1, 2008	13.7¢ per-kWh	2.8¢ per-kWh

The rate changes in 2008 resulted from the following:

•

March 2008: Increase to the FERC jurisdictional base transmission rates to include adopted CWIP incentives. See “—FERC Construction Work in Progress Mechanism” for further discussion.

•

April 2008: Consolidation of the 2008 authorized CPUC jurisdictional revenue requirements. This decrease was primarily related to an increase in estimated 2008 kWh sales which more than offset a small increase in 2008 CPUC authorized revenue requirements.

•

June 2008: Decrease to the CDWR-related rates.

SCE expects to file an ERRA Trigger Application in the third quarter of 2008 due to higher gas and power prices than the forecast prices used to set current generation rate levels and expects to increase customer rates before year-end 2008.

2009 General Rate Case Proceeding

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—2009 General Rate Case Proceeding” in the year-ended 2007 MD&A, SCE filed its GRC application on November 19, 2007. The application requested a 2009 base rate revenue requirement of $5.199 billion. Hearings were completed in June 2008 and briefing is expected to be completed on August 8, 2008. At the end of the hearings, SCE agreed to several adjustments to its request and revised its forecasts to reflect lower customer growth and meter connections due to the economic downturn in southern California. SCE’s revised request for 2009 is $5.162 billion. After considering the effects of sales growth and other offsets, SCE’s revised request would be a $695 million increase over current authorized base rate revenue. If the CPUC approves these requested increases and allocates them to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 15.57% and 5.96%, respectively. The revised request would result in 2010 and 2011 base rate revenue requirement increases, net of sales growth, of $197 million and $257 million, respectively. As a result of SCE’s revised request, the DRA’s recommended increase of approximately $19 million, which was submitted on April 15, 2008, now represents a difference of $676 million from SCE’s revised base rate revenue. The $676 million difference is mainly due to reductions proposed by DRA including: a reduction in capital-related costs of approximately $186 million, which includes recommended changes in methods for calculating depreciation expense; a reduction in operating and maintenance expense of approximately $286 million; a reduction in administrative and general expense of approximately $192 million mainly related to a reduction in pension and benefits, the elimination of results sharing as well as a reduction in long-term incentives and other executive compensation; and other miscellaneous proposed reductions. Additionally, as a result of SCE’s revised request, TURN’s recommendation now seeks to reduce SCE’s revised 2009 request by an additional $195 million over the DRA adjustments, primarily due to a further reduction in depreciation expenses. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted although a final decision is expected prior to year-end.

2008 Cost of Capital Proceeding

On December 21, 2007, the CPUC granted SCE’s requested rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common equity for 2008. The CPUC also authorized SCE’s 2008 cost of long-term debt of 6.22%, cost of preferred equity of 6.01% and a return on common equity of 11.5%. The impact of this Phase I decision resulted in a $7 million decrease in SCE’s 2008 annual revenue requirement. On May 29, 2008, the CPUC issued a final decision on Phase II of the proceeding, replacing the former annual cost of capital application with a multi-year mechanism, which would not require a new cost of capital application to be filed until April 2010. The decision also adopted a trigger mechanism which provides for an automatic adjustment to return on equity and embedded costs of long-term debt and preferred stock during the intervening years between the cost of capital filings if certain thresholds are reached.

Energy Efficiency Shareholder Risk/Reward Incentive Mechanism

As discussed under the heading “SCE: Regulatory Matters—Energy Efficiency Shareholder Risk/Reward Incentive Mechanism” in the year-ended 2007 MD&A, the CPUC issued a decision in September 2007 that adopted an Energy Efficiency Risk/Reward Incentive mechanism. The mechanism allows for both incentives and economic penalties based on SCE’s performance toward meeting CPUC goals for energy efficiency.

Under this mechanism, SCE is scheduled to file an advice letter in September 2008 requesting recovery of the earnings claim for the 2006 and 2007 timeframe, however, the timing of claims is linked to the completion of CPUC reports. The first progress payment, for SCE’s 2006-2007 energy efficiency portfolio performance, will be based on a CPUC report scheduled to be complete in August 2008. SCE currently projects, based on preliminary results and through the advice letter process (see below for discussion of an alternative dispute resolution process), that it will record a progress payment in the range of $41 million to $49 million in the fourth quarter of 2008 for the first two years (2006 – 2007) of the program cycle. Delays in the CPUC report expected in August 2008 could cause a delay in recognizing earnings for the progress payment.

On July 3, 2008, the Natural Resources Defense Council filed a request with the CPUC for an alternative dispute resolution process to address the first interim earnings claim for the 2006-2008 energy efficiency program cycle. The alternative dispute resolution process may be requested by a party at any time and is a voluntary process which may be utilized by parties to ensure a timely solution to cases. The alternative dispute resolution process could modify or negate the use of the advice letter process, including the results of the CPUC report expected in August 2008. Depending on the outcome of the alternative dispute resolution process, the parties may revert to the advice letter process. Under the alternative dispute resolution process, the progress payment amount, as well as timing of recognition, may differ from SCE’s current projection.

FERC Construction Work in Progress Mechanism

As discussed under the headings “SCE: Regulatory Matters—Current Regulatory Developments—FERC Transmission Incentives” and “—FERC Construction Work in Progress Mechanism” in the year-ended 2007 MD&A, on December 21, 2007, SCE filed a revision to its Transmission Owner Tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects. In the CWIP filing, SCE proposed a single-issue rate adjustment ($45 million or a 14.4% increase) to SCE’s currently authorized base transmission revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders approved for Tehachapi, DPV2 and Rancho Vista). SCE projects that it will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively, from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to projected consulting and legal costs associated with SCE’s continued efforts to obtain regulatory approvals necessary to construct the DPV2 Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on March 1, 2008, subject to refund on the limited issue of whether SCE’s proposed ROEs are reasonable. On March 28, 2008, the CPUC filed a Petition for Rehearing with the FERC on the FERC’s acceptance of SCE’s proposed ROE for CWIP. Briefs addressing the appropriate ROE were filed by SCE and intervenors in May 2008.

SCE cannot predict the outcome of the matters in this proceeding.

Energy Resource Recovery Account Proceedings

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2007 MD&A, the ERRA is the balancing account mechanism to track and recover SCE’s fuel and procurement-related costs. At June 30, 2008, the ERRA was undercollected by $95 million, which was 1.8% of SCE’s prior year’s generation revenue. Based on a forecast of procurement costs, SCE’s ERRA balancing account is estimated to be undercollected by more than 5% by the end of August 2008, and 14.5% by the end of December 2008. This significant undercollection is due to higher gas and power prices than the forecast prices used to set current generation rate levels. SCE expects to file an ERRA Trigger Application in the third quarter of 2008 and expects to increase customer rates before year-end 2008.

Peaker Plant Generation Projects

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Peaker Plant Generation Projects” in the year-ended 2007 MD&A, in response to a CPUC order, SCE constructed four of the five combustion turbine peaker plants, four of which were placed online in August 2007 to help meet peak customer demands and other system requirements. SCE anticipates submitting updated testimony in connection with its December 2007 cost recovery application to revise the total recorded costs as of mid-2008, for the first four peaker plants, to approximately $261 million with additional projected costs for those peaker plants of approximately $2 million. In its cost recovery application, SCE proposed to continue tracking the capital costs of the fifth peaker plant according to the interim cost tracking mechanism that was previously approved by the CPUC for all five peaker projects while they were in construction. Additionally, SCE proposed to file a separate cost recovery application for the fifth peaker after it is installed or its final disposition is otherwise determined (see below for further discussion on the status of the fifth peaker plant). As of June 30, 2008, SCE has incurred capital costs of approximately $38 million for the fifth peaker. Several parties have filed protests or other filings in response to SCE’s cost recovery application. SCE expects to fully recover its costs from these projects, but cannot predict the outcome of regulatory proceedings. SCE expects a CPUC decision on its cost recovery application in late 2008.

SCE has continued to pursue the construction of the fifth peaker plant. The required development permit was denied by the City of Oxnard in July 2007 and SCE appealed the denial to the California Coastal Commission. The Commission heard SCE’s appeal on August 6, 2008, but did not reach a final decision and continued the matter until at least October 2008.

Procurement of Renewable Resources

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Procurement of Renewable Resources” in the year-ended 2007 MD&A, 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.

California Proposition 7- Solar and Clean Energy Initiative

A renewable initiative has qualified for the November 4, 2008 California ballot that would impose a 50% Renewable Portfolio Standard (RPS) on all electric utilities in the state, including investor-owned and municipally-owned utilities. The measure would set an RPS of 20% by 2010, 40% by 2020, and 50% by 2025. It would also reduce, but uncap, penalties for not meeting the annual RPS requirement. Additionally, it would set the minimum price of renewable energy at market price and authorize purchases up to 10% above market price. The measure would also require utilities to sign 20-year bilateral agreements for offers meeting that threshold. Finally, it would shift jurisdiction for setting a market price and permitting transmission from the CPUC to the CEC. The measure is opposed by a coalition of environmentalists, renewable power developers, labor, taxpayer groups, and utilities, and has not received any significant endorsements among these sectors. It is also opposed by both political parties. While the fiscal impacts of the initiative are unknown at this time, SCE is evaluating them and is actively participating in the campaign against the measure.

FERC Refund Proceedings

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—FERC Refund Proceedings” in the year-ended 2007 MD&A, SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets during the energy crisis in California in 2000 – 2001 or who benefited from the manipulation by receiving inflated market prices. SCE is required to refund to customers 90% of certain refunds realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive.

In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates, most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In the second quarter of 2008, SCE received distributions of approximately $25 million on its allowed bankruptcy claim. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions.

In May 2008, SCE and a number of other parties entered into a settlement of the FERC refund proceeding issues with NEGT Energy Trading-Power, L.P. (NEGT) and a related party, both of which are debtors in a Chapter 11 proceeding pending in the Maryland bankruptcy court. Under the terms of the settlement, NEGT will provide refunds valued at $66 million, a portion of which will be paid in the form of an allowed, unsecured claim in the Chapter 11 bankruptcy proceeding. SCE’s share of this amount is expected to be approximately $19 million. NEGT will also assign to SCE and the other parties to the settlement a corporate guarantee and surety bond that, subject to collection, will provide an additional $14 million. SCE’s share of the $14 million is yet to be determined. The settlement was approved by the Maryland bankruptcy court on July 24, 2008 but remains subject to approval by the FERC.

Market Redesign Technology Upgrade

As discussed under the heading “SCE: Regulatory Matters—Market Redesign Technology Upgrade” in the year ended 2007 MD&A, in early 2006, the ISO began a program to redesign and upgrade the wholesale energy market across ISO’s controlled grid, known as the MRTU. The programs under the MRTU initiative are designed to implement market improvements to assure grid reliability, more efficient and cost-effective use of resources, and to create technology upgrades that would strengthen the entire ISO computer system. The MRTU was scheduled for implementation in the fall of 2008, however, the ISO recently announced a further delay beyond 2008. Discussions will be held in September 2008 to determine the timing of the MRTU implementation.

SCE: OTHER DEVELOPMENTS

Palo Verde Nuclear Generating Station Outage and Inspection

As discussed under the heading “SCE: Other Developments—Palo Verde Nuclear Generating Station Inspection” in the year-ended 2007 MD&A, the NRC held three special inspections of Palo Verde, between March 2005 and February 2007. The combination of the results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, was completed in December 2007. In addition, Palo Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant personnel and self-assessments of its programs and procedures. The NRC and APS defined and agreed to inspection and survey corrective actions that the NRC embodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track to complete the corrective actions required to close the Confirmatory Action Letter by mid-2009. Palo Verde operation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in 2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. SCE is unable to estimate how long SCE will continue to incur these costs.

SCE: MARKET RISK EXPOSURES

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

Interest Rate Risk

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity purposes, to fund business operations and to finance capital expenditures.

In July 2007, SCE entered into interest rate-locks to mitigate interest rate risk associated with future financings. Due to declining interest rates in late 2007, at December 31, 2007, these interest rate locks had unrealized losses of $33 million. In January and February 2008, SCE settled these interest rate-locks resulting in realized losses of $33 million. A related regulatory asset was recorded in this amount and SCE expects to amortize and recover this amount as interest expense associated with its 2008 financings.

Commodity Price Risk

As discussed in the year-ended 2007 MD&A, SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillary services to meet its peak energy requirements as well as exposure to natural gas prices associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including SCE’s Mountainview plant.

SCE has an active hedging program in place to minimize ratepayer exposure to spot-market price spikes; 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 spot-market prices, SCE enters into energy options, tolling arrangements, forward physical contracts, and congestion rights (FTRs and 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.

In September 2007, the ISO allocated CRRs for the period March 2008 through December 2017 to SCE which will entitle SCE to receive (or pay) the value of transmission congestion between specific locations. These rights will act as an economic hedge against transmission congestion costs in the MRTU environment which was expected to be operational March 31, 2008, but was delayed. The CRRs meet the definition of a derivative under SFAS No. 133. In accordance with SFAS No. 157, SCE recognized the CRRs at a zero fair value due to liquidity reserves. Liquidity reserves against CRRs fair values were provided since there were no quoted long-term market prices for the CRRs allocated to SCE. Although an auction was held in December 2007, the auction results did not provide sufficient evidence of long-term market prices.

During the first quarter of 2008, the ISO held an auction for FTRs. SCE participated in the ISO auction and paid $62 million to secure FTRs for the period April 2008 through March 2009. The FTRs will be replaced with CRRs in the MRTU environment. SCE recognized the FTRs at fair value. SCE anticipates amounts paid for FTRs that will no longer be valid in the MRTU environment will be refunded to SCE and has recognized this amount as a receivable from the ISO.

Any future fair value changes, given a MRTU market, will be recorded in purchased-power expense and offset through the provision for regulatory adjustments clauses as the CPUC allows these costs to be recovered from or refunded to customers through a regulatory balancing account mechanism. As a result, fair value changes are not expected to affect earnings.

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale. Certain derivative instruments do not meet the normal purchases and sales exception because demand variations and CPUC mandated resource adequacy requirements may result in physical delivery of excess energy that may not be in quantities that are expected to be used over a reasonable period in the normal course of business and may then be resold into the market. In addition, certain contracts do not meet the definition of clearly and closely related under SFAS No. 133 since pricing for certain renewable contracts is based on an unrelated commodity. The derivative instrument fair values are marked to market at each reporting period. Any fair value changes for recorded derivatives are recorded in purchased-power expense and offset through the provision for regulatory adjustment clauses – net; therefore, fair value changes do not affect earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment.

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


	June 30, 2008						December 31, 2007
In millions	Assets			Liabilities			Assets		Liabilities
Energy options	$	16		$	31		$	6	$	49
FTRs		90			—			22		—
Forward physicals (power) and tolling arrangements		73			6			7		8
Gas options, swaps and forward arrangements		416			4			46		22
Netting and collateral		(20	)		(2	)		—		(2	)
Total	$	575		$	39		$	81	$	77

Quoted market prices, if available, are used for determining the fair value of contracts, as discussed above. If quoted market prices are not available, internally maintained standardized or industry accepted models are used to determine the fair value. The models are updated with spot prices, forward prices, volatilities and interest rates from regularly published and widely distributed independent sources. SCE implemented SFAS No. 157 during the first quarter of 2008. Under SFAS No. 157, when actual market prices, or relevant observable inputs are not

available it is appropriate to use unobservable inputs which reflect management assumptions, including extrapolating limited short-term observable data and developing correlations between liquid and non-liquid trading hubs. The derivative assets and liabilities whose fair value is based on unobservable inputs are classified as level 3 measurements under SFAS No. 157. The amount of SCE’s level 3 derivative assets and liabilities measured using significant unobservable inputs as a percentage of the total derivative assets and total derivative liabilities measured at fair value was 53% and 100%, respectively. During the first six months of 2008, the level 3 fair values increased as a result of changes in realized and unrealized gains. SCE recorded net realized and unrealized gains of $361 million for the three months ended June 30, 2008 and net realized and unrealized losses of $63 million for the three months ended June 30, 2007. SCE recorded net realized and unrealized gains of $512 million and $42 million for the six months ended June 30, 2008 and 2007, respectively. The changes in net realized and unrealized gains on economic hedging activities were primarily due to increases in forward natural gas prices in 2008, compared to the same period in 2007. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings.

EDISON MISSION GROUP

EMG: LIQUIDITY

Liquidity

At June 30, 2008, EMG and its subsidiaries had cash and cash equivalents and short-term investments of $805 million, EMG had a total of $968 million of available borrowing capacity under its credit facilities. EMG’s consolidated debt at June 30, 2008 was $4.0 billion. In addition, EME’s subsidiaries had $3.7 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 27 years.

Capital Expenditures

At June 30, 2008, the estimated capital expenditures through 2010 by EME’s subsidiaries related to existing projects, corporate activities and turbine commitments were as follows:


In millions	July through December 2008		2009		2010
Illinois plants
Plant capital expenditures	$	40	$	78	$	27
Environmental expenditures		47		61		263

Homer City Facilities
Plant capital expenditures		18		63		26
Environmental expenditures		7		9		9

New Projects
Projects under construction		157		4		—
Turbine commitments		407		557		300
Other capital expenditures		37		14		9
Total	$	713	$	786	$	634

Expenditures for Existing Projects

Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, railroad interconnection, replacement of major boiler components, mill inerting projects and ash site disposal development. Environmental expenditures relate to environmental projects such as mercury emission monitoring and control and a selenium removal system at the Homer City facilities and various projects at the Illinois plants to achieve specified emissions reductions such as installation of mercury controls. EME plans to fund these expenditures with debt financings, cash on hand or cash generated from operations. For further discussion regarding these and possible additional capital expenditures, including environmental control equipment at the Homer City facilities, refer to “Edison International: Management’s Overview,” and “Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule—Illinois,” and “Other Developments—Environmental Matters—Air Quality Regulation—Mercury Regulation” in the year ended December 31, 2007 MD&A.

Expenditures for New Projects

EME expects to make substantial investments in new projects during the next several years. At June 30, 2008, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 1,061 MW. The turbine commitments generally represent approximately two-thirds of the

total capital costs of EME’s wind projects. As of June 30, 2008, 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. 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, an interconnection agreement(s) or other 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.

In addition, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with SCE for the output of the Walnut Creek project. During the second quarter of 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project included in turbine commitments in the above table. Subject to obtaining approval for the power sales contract, EME intends to construct the project with total installed costs, excluding interest during construction, estimated in the range of $500 million to $600 million.

Credit Ratings

Overview

Credit ratings for EMG’s direct and indirect subsidiaries at June 30, 2008, were as follows:


	Moody’s Rating	S&P Rating	Fitch Rating
EME	B1	BB-	BB-
Midwest Generation	Baa3	BB+	BBB-
EMMT	Not Rated	BB-	Not Rated
Edison Capital	Ba1	BB+	Not Rated

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.

EMG 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.

Credit Rating of EMMT

The Homer City sale-leaseback documents restrict EME Homer City’s ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from S&P or Moody’s or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME’s internal credit scoring procedures. These documents include a requirement that the counterparty to such transactions, 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. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME Homer City to sell directly into the market or through EMMT; 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 participant that will allow EME Homer City to enter into such sales, under specified conditions, through December 31, 2008. EME Homer City continues to be in compliance with the terms of the consent. EME is permitted to sell the output of the

Homer City facilities into the spot market at any time. See “EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities.”

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into contracts in support of EME’s hedging and energy trading activities (including forward contracts, transmission contracts and futures contracts), EME’s subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. 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 accounts payable and unrealized losses in connection with these hedging and trading activities. At June 30, 2008, EMMT had deposited $51 million in cash with brokers in margin accounts in support of futures contracts and had deposited $126 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $1 million in support of commodity contracts at June 30, 2008.

Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2008, if wholesale energy prices increase or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2008 could increase by approximately $360 million over the remaining life of the contracts using a 95% confidence level.

Midwest Generation has cash on hand and a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois plants. At June 30, 2008, Midwest Generation had available $447 million of borrowing capacity under this credit facility. As of June 30, 2008, Midwest Generation had $151 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and $521 million of borrowing capacity available under a $600 million working capital facility to provide credit support to subsidiaries.

Dividend Restrictions in Major Financings

General

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

Key Ratios of EMG’s Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME’s principal subsidiaries required by financing arrangements at June 30, 2008 or for the 12 months ended June 30, 2008:

Edison Capital’s ability to make dividend payments is currently restricted by covenants in its financial instruments, which require Edison Capital, through a wholly owned subsidiary, to maintain a specified minimum net worth of $200 million. Edison Capital satisfied this minimum net worth requirement as of June 30, 2008.

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 “EMG: Liquidity—Dividend Restrictions in Major Financings” in the year-ended 2007 MD&A.

EMG: OTHER DEVELOPMENTS

PJM Matters

On April 4, 2008, the FERC issued an order rejecting PJM’s request to revise its RPM to reflect PJM’s claimed rise in its CONE values. CONE is one of the two components used by PJM to determine its Variable Resource Requirement curve for the RPM auction. PJM also proposed to add a new section to its tariff permitting PJM to unilaterally request a CONE increase for use in its May 2008 RPM auction for the 2011/2012 delivery year. In rejecting the proposal, the FERC found that PJM had not met timing provisions in its existing tariff to provide sufficient time for stakeholder review of the analysis and advance planning and that it had also failed to establish that its proposal to revise that provision was necessary on a one-time emergency basis to ensure reliable service.

The effect of FERC’s actions on future RPM auctions cannot be determined at this time. The CONE as established for the May 2008 RPM auction for the 2011/2012 delivery year is lower than the PJM request.

RPM Buyers’ Complaint

On July 10, 2008, EME responded to the RPM Buyers’ complaint asking that the same be dismissed based upon various legal precedents. In particular EME argued that the complaint represents little more than a collateral attack on the FERC’s orders approving the RPM settlement and rules and that all of the major factors the RPM Buyers alleged produced unjust and unreasonable prices in the base residual auctions were previously litigated and adjudicated in the contested proceedings involving the RPM settlement. A number of other parties, including PJM, also responded to the RPM Buyers’ complaint asking that the same be dismissed.

This matter is currently pending before the FERC. EME cannot predict the outcome of this matter.

EME Homer City New Source Review Notice of Violation

On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant Deterioration requirements of the Clean Air Act. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. EME Homer City intends to meet with the US EPA to discuss the alleged violations. EME Homer City is investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at this time what effect this matter may have 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 the defense of the claims.

EMG: MARKET RISK EXPOSURES

Introduction

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

Commodity Price Risk

Introduction

EME’s merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored 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 is expected to vary.

EME uses “earnings 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 in respect of 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 earnings 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 limits and counterparty credit exposure limits.

Hedging Strategy

To reduce its exposure to market risk, EME hedges a portion of its electricity sales through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its electricity sales, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through:

•

the use of contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange,

•

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

•

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

•

participation in capacity auctions.

The extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether the types of hedge transactions set forth above at forward market prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot market sales. Second, EME’s ability to enter into hedging transactions depends upon its and Midwest Generation’s credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging transactions.

In the case of hedging transactions related to the generation and capacity of the Illinois plants, Midwest Generation is permitted to use its working capital facility and cash on hand to provide credit support for these hedging transactions entered into by EMMT under an energy services agreement between Midwest Generation and EMMT. Utilization of this credit facility in support of hedging transactions provides additional liquidity support for implementation of EME’s contracting strategy for the Illinois plants. In addition, Midwest Generation may grant liens on its property in support of hedging transactions associated with the Illinois plants. In the case of hedging transactions related to the generation and capacity of the Homer City facilities, credit support is provided by EME pursuant to intercompany arrangements between it and EMMT. See “—Credit Risk” below.

Energy Price Risk Affecting Sales from the Illinois Plants

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

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

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

The following table depicts the average historical market prices for energy per megawatt-hour during the first six months of 2008 and 2007.


	24-Hour Northern Illinois Hub Historical Energy Prices⁽¹⁾
	2008		2007
January	$	47.09	$	35.75
February		54.46		56.64
March		58.58		42.04
April		53.87		48.91
May		44.49		44.49
June		56.06		39.76
Six-Month Average	$	52.42	$	44.60

(1)

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

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

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at June 30, 2008:


	24-Hour Northern Illinois Hub Forward Energy Prices⁽¹⁾
2008
July	$	81.00
August		77.04
September		62.27
October		59.88
November		56.23
December		64.39
2009 Calendar “strip”⁽²⁾	$	62.17

(1)

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

(2)

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

The following table summarizes Midwest Generation’s hedge position at June 30, 2008:


	2008			2009			2010			2011
	GWh	Average price/ MWh		GWh	Average price/ MWh		GWh	Average price/ MWh		GWh	Average price/ MWh
Energy Only Contracts ⁽¹⁾
Northern Illinois Hub-AEP/ Dayton Hub	5,427	$	61.30	11,378	$	66.53	7,961	$	67.39	203	$	76.20
Load Requirements Services Contracts ⁽²⁾⁽³⁾
Northern Illinois Hub	2,220		64.37	1,571		63.65	—		—	—		—
Total estimated GWh	7,647			12,949			7,961			203

(1)

The energy only contracts include forward contracts for the sale of power and futures contracts during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge positions at June 30, 2008 are not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.

(2)

Under a load requirements services contract, the amount of power sold is a portion of the retail load of the purchasing utility and thus can vary significantly with variations in that retail load. Retail load depends upon a number of factors, including the time of day, the time of the year and the utility’s number of new and continuing customers. Estimated GWh have been forecast based on historical patterns and on assumptions regarding the factors that may affect retail loads in the future. The actual load will vary from that used for the above estimate, and the amount of variation may be material.

(3)

The average price per MWh under a load requirements services contract (which is subject to a seasonal price adjustment) represents the sale of a bundled product that includes, but is not limited to, energy, capacity and ancillary services. Furthermore, as a supplier of a portion of a utility’s load, Midwest Generation will incur charges from PJM as a load-serving entity. For these reasons, the average price per MWh under a load requirements services contract is not comparable to the sale of power under an energy only contract. The average price per MWh under a load requirements services contract represents the sale of the bundled product based on an estimated customer load profile.

Energy Price Risk Affecting Sales from the Homer City Facilities

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

The following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and in PJM West Hub (EME Homer City’s primary trading hub) during the first six months of 2008 and 2007:


	Historical Energy Prices⁽¹⁾ 24-Hour PJM
	Homer City				West Hub
	2008		2007		2008		2007
January	$	54.32	$	40.30	$	66.80	$	44.63
February		61.74		64.27		68.29		73.93
March		65.37		55.00		70.48		61.02
April		61.99		52.42		69.12		58.74
May		49.37		48.12		59.84		53.89
June		78.72		45.88		98.50		60.19
Six-Month Average	$	61.92	$	51.00	$	72.17	$	58.73

(1)

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

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

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at June 30, 2008:


	24-Hour PJM West Hub Forward Energy Prices⁽¹⁾
2008
July	$	113.97
August		115.98
September		93.37
October		90.30
November		82.49
December		95.45
2009 Calendar “strip”⁽²⁾	$	94.90

(1)

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

(2)

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

The following table summarizes EME Homer City’s hedge position at June 30, 2008:


	2008	2009	2010
GWh	3,636	4,096	2,654
Average price/MWh⁽¹⁾	$ 60.84	$ 82.84	$ 90.52

(1)

The above hedge positions include forward contracts for the sale of power during different periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, although there is significant variability of power prices during different periods of time. Accordingly, the above hedge position at June 30, 2008 is not directly comparable to the 24-hour PJM West Hub prices set forth above.

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

Capacity Price Risk

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

The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at June 30, 2008:


	Fixed Price Capacity Sales
	Through RPM Auction, Net				Non-unit Specific Capacity Sales		Variable Capacity Sales
	MW	Price per MW-day			MW	Price per MW-day	MW	Price per MW-day
July 1, 2008 to May 31, 2009
Midwest Generation	2,978	$	122.36	⁽¹⁾	880	$ 64.35	—	—
EME Homer City	820	$	111.92		—	—	905	$ 65.76	⁽²⁾
June 1, 2009 to May 31, 2010
Midwest Generation	4,614	$	102.04		715	71.46	—	—
EME Homer City	1,670	$	191.32		—	—	—	—
June 1, 2010 to May 31, 2011
Midwest Generation	4,929	$	174.29		—	—	—	—
EME Homer City	1,813	$	174.29		—	—	—	—
June 1, 2011 to May 31, 2012
Midwest Generation	4,582	$	110.00		—	—	—	—
EME Homer City	1,771	$	110.00		—	—	—	—

(1)

The original price of $111.92 was affected by Midwest Generation’s participation in a supplemental RPM auction during the first quarter of 2008 which resulted in purchasing certain capacity amounts at a price of $10 per MW-day, thereby reducing the aggregate forward capacity sales for this period and increasing the effective capacity price to $122.36.

(2)	Actual contract price is a function of NYISO capacity auction clearing prices in June 2008 through July 2008 and forward over-the-counter NYISO capacity prices on June 30, 2008 for August 2008 through May 2009.

Revenue 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, and the CONE.

Midwest Generation entered into hedge transactions in advance of the RPM auctions with counterparties that are settled through PJM. In addition, the load service requirements contracts entered into by Midwest Generation with Commonwealth Edison include energy, capacity and ancillary services (sometimes referred to as a “bundled product”). Under PJM’s business rules, Midwest Generation sells all of its available capacity (defined as unit capacity less forced outages) into the RPM and is subject to a locational reliability charge for the load under these contracts. This means that the locational reliability charge generally offsets the related amounts sold in the RPM, which Midwest Generation presents on a net basis in the table above.

Prior to the RPM auctions for the relevant delivery periods, EME Homer City sold a portion of its capacity to an unrelated third party for the delivery period of June 1, 2008 through May 31, 2009. EME Homer City is not receiving the RPM auction clearing price for this previously sold capacity. The price EME Homer City is receiving for these capacity sales is a function of NYISO capacity clearing prices resulting from separate NYISO capacity auctions.

Basis Risk

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

•

sales of actual generation in the amounts covered by the forward contracts with reference to PJM spot prices at the busbar of the plant involved, plus,

•

sales to third parties at the price under such hedging contracts at designated settlement points (generally the PJM West Hub for the Homer City facilities and the Northern Illinois Hub or AEP/Dayton Hub for the Illinois plants) less the cost of power at spot prices at the same designated settlement points.

Under PJM’s market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. Effective June 1, 2007, PJM implemented marginal losses which adjust the algorithm that calculates locational marginal prices to include a component for marginal transmission losses in addition to the component included for congestion. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as “basis risk.” During the six months ended June 30, 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 14%, compared to 13% during the six months ended June 30, 2007. The monthly average difference during the

12 months ended June 30, 2008 ranged from 7% to 22%. In contrast to the Homer City facilities, during the past 12 months, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois plants, although the implementation of marginal losses on June 1, 2007 has lowered energy prices at the Illinois plants busbars.

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. A financial transmission right is a financial instrument that entitles the holder to receive the difference of actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME’s hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

Coal and Transportation Price Risk

The Illinois plants and the Homer City facilities purchase coal primarily obtained from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements extending through 2011. The following table summarizes the amount of coal under contract at June 30, 2008 for the remainder of 2008 and the following three years.


	Amount of Coal Under Contract in Millions of Tons⁽¹⁾
	July through December 2008	2009	2010	2011
Illinois plants	10.3	11.7	11.7	—
Homer City facilities⁽²⁾	3.2	4.5	0.4	0.1

(1)

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

(2)

At June 30, 2008, there are options to purchase additional coal of 1.7 million tons in 2010 and 1.2 million tons in 2011.

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian coal, which are related to the price of coal purchased for the Homer City facilities, increased substantially during 2008 from 2007 year-end prices. The price of Northern Appalachian coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO₂ per MMBtu sulfur content) increased to $149 per ton at July 25, 2008 from $55.25 per ton at December 21, 2007, as reported by the Energy Information Administration. 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 increased during 2008 from 2007 year-end prices. The price of PRB coal increased to $12.50 per ton at July 25, 2008 from $11.50 per ton at December 21, 2007, as reported by the Energy Information Administration. The 2008 increase in North Appalachian coal prices were primarily attributable to: 1) increased international and Atlantic basin coal demand, 2) port and rail infrastructure problems and monsoon flooding in Australia, 3) a record cold winter in China, and 4) an energy crisis in South Africa.

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 more than 50% of the delivered cost of PRB coal to the Illinois plants).

Emission Allowances Price Risk

The federal Acid Rain Program requires electric generating stations to hold SO₂ allowances, and Illinois and Pennsylvania regulations implemented the federal NO_X SIP Call requirement. As part of the acquisition of the

Illinois plants and the Homer City facilities, EME obtained the rights to the 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.

The average price of purchased SO₂ allowances decreased to $309 per ton during the first six months of 2008 from $512 per ton during 2007. The price of SO₂ allowances, determined by obtaining broker quotes and information from other public sources, was $330 per ton as of June 30, 2008. Following the District of Columbia Circuit Court of Appeals’ decision in July 2008, discussed above under “Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule,” the price of SO₂ allowances has further declined.

For a discussion of environmental regulations related to emissions, refer to “Other Developments—Environmental Matters” in the year-ended 2007 MD&A.

Accounting for Energy Contracts

EME uses a number of energy contracts to manage exposure from changes in the price of electricity, including forward sales and purchases of physical power and forward price swaps which settle only on a financial basis (including futures contracts). EME follows SFAS No. 133, and under this Standard these energy contracts are generally defined as derivative financial instruments. Importantly, SFAS No. 133 requires changes in the fair value of each derivative financial instrument to be recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that qualifies for cash flow hedge accounting is recognized currently in earnings. For further discussion of derivative financial instruments, refer to “Critical Accounting Estimates and Policies—Derivative Financial Instruments and Hedging Activities” in the year-ended 2007 MD&A.

SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from energy contracts as part of operating revenue. The results of derivative activities are recorded as part of cash flows from operating activities in the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities for the second quarters of 2008 and 2007 and six months ended June 30, 2008 and 2007:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2008			2007			2008			2007
Illinois plants
Non-qualifying hedges	$	2		$	4		$	2		$	(18	)
Ineffective portion of cash flow hedges		(5	)		—			(10	)		—
Homer City
Non-qualifying hedges		1			2			2			1
Ineffective portion of cash flow hedges		(7	)		(5	)		(9	)		(3	)
Total unrealized gains (losses)	$	(9	)	$	1		$	(15	)	$	(20	)

At June 30, 2008, unrealized losses of $54 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($22 million for the remainder of 2008, $18 million for 2009, and $14 million for 2010).

Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

The following table summarizes the fair values for outstanding derivative financial instruments used in EME’s continuing operations for purposes other than trading, by risk category:


In millions	June 30, 2008	December 31, 2007
Commodity price:
Electricity contracts	$ (686)	$ (137)

In assessing the fair value of EME’s non-trading derivative financial 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 electricity contracts at June 30, 2008 as compared to December 31, 2007 is attributable to an increase in the average market prices for power as compared to contracted prices at June 30, 2008, which is the valuation date. The following table summarizes the maturities and the related fair value, primarily based on actively traded prices, of EME’s commodity derivative assets and liabilities as of June 30, 2008:


In millions	Total Fair Value	Maturity <1 year	Maturity 1 to 3 years	Maturity 4 to 5 years		Maturity >5 years
Prices actively quoted	$ (683)	$ (452)	$ (231)	$	—	$	—
Price based on models and other valuation methods	(3)	1	(4)		—		—
Total	$ (686)	$ (451)	$ (235)	$	—	$	—

Prices actively quoted in the preceding table includes derivatives whose fair value is based on quoted market prices and forward market prices adjusted for credit risk.

Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities as of June 30, 2008 and December 31, 2007, are set forth below:

June 30, 2008

December 31, 2007

In millions

Assets

Liabilities

Assets

Liabilities

Electricity contracts

231

138

141

The change in the fair value of trading contracts for the six months ended June 30, 2008, was as follows:


In millions
Fair value of trading contracts at January 1, 2008	$	132
Net gains from energy trading activities		95
Amount realized from energy trading activities		(121	)
Other changes in fair value		(13	)
Fair value of trading contracts at June 30, 2008	$	93

EME adopted SFAS No. 157 effective January 1, 2008. The standard established a hierarchy for fair value measurements.

In the table below, prices actively quoted includes both exchange traded derivatives and non-exchange traded derivatives which are priced based on forward market prices adjusted for credit risk. Also in the table, fair value based on models and other valuation methods includes illiquid firm transmission rights and over-the-counter derivatives at illiquid locations and long-term power agreements which would be considered Level 3 derivative positions. For illiquid firm transmission rights, EME determines fair value based on the hypothetical sale of illiquid positions. For long-term power agreements, EME’s subsidiary recorded 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.

The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of June 30, 2008):


In millions	Total Fair Value			Maturity <1 year			Maturity 1 to 3 years			Maturity 4 to 5 years			Maturity >5 years
Prices actively quoted	$	(31	)	$	(28	)	$	(2	)	$	(1	)	$	—
Prices based on models and other valuation methods		124			47			21			24			32
Total	$	93		$	19		$	19		$	23		$	32

Credit Risk

In conducting EME’s hedging and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted price if the non-performing counterparty were unable to pay the resulting liquidated 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 would be incurred if counterparties failed to perform pursuant to the terms of their 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. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME manages the credit risk on the portfolio 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 activities (excluding load requirements services contracts) are measured as either: (i) the sum of 60 days of accounts receivable, current fair value of open positions, and a credit value at risk, or (ii) the sum of delivered and unpaid accounts receivable and the current fair value of open positions. EME’s subsidiaries enter into master agreements and other arrangements in conducting hedging and trading activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME’s credit risk exposure from counterparties is based on net

exposure under these agreements. At June 30, 2008, the amount of exposure as described above, broken down by the credit ratings of EME’s counterparties, was as follows:


In millions	June 30, 2008
S&P Credit Rating
A or higher	$	14
A-		70
BBB+		95
BBB		18
BBB-		38
Below investment grade		4
Total	$	239

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 plant.

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 capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 49% of EME’s consolidated operating revenue for the six months ended June 30, 2008. Moody’s rates PJM’s debt Aa3. PJM, an independent system operator with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At June 30, 2008, EME’s account receivable due from PJM was $99 million.

EME also derived a significant source of its revenue from the sale of energy, capacity and ancillary services generated at the Illinois plants to Commonwealth Edison under load requirements services contracts. Sales under these contracts accounted for 15% of EME’s consolidated operating revenue during the six months ended June 30, 2008. Commonwealth Edison’s senior unsecured debt ratings are BBB- by S&P and Ba1 by Moody’s. At June 30, 2008, EME’s account receivable due from Commonwealth Edison was $24 million. For the six months ended June 30, 2008, a third customer accounted for 11% of EME’s consolidated operating revenue.

Edison Capital’s investments may be affected by the financial condition of other parties, the performance of the asset, economic conditions and other business and legal factors. Edison Capital generally does not control operations or management of the projects in which it invests and must rely on the skill, experience and performance of third party project operators or managers. These third parties may experience financial difficulties or otherwise become unable or unwilling to perform their obligations. Edison Capital’s investments generally depend upon the operating results of a project with a single asset. These results may be affected by general market conditions, equipment or process failures, disruptions in important fuel supplies or prices, or another party’s failure to perform material contract obligations, and regulatory actions affecting utilities purchasing power from the leased assets. Edison Capital has taken steps to mitigate these risks in the structure of each project through contract requirements, warranties, insurance, collateral rights and default remedies, but such measures may not be adequate to assure full performance. In the event of default, lenders with a security interest in the asset may exercise remedies that could lead to a loss of some or all of Edison Capital’s investment in that asset.

Interest Rate Risk

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. 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 $3.79 billion at June 30, 2008, compared to the carrying value of $4.0 billion.

EDISON INTERNATIONAL (PARENT)

EDISON INTERNATIONAL (PARENT): LIQUIDITY

The parent company’s liquidity and its ability to pay interest and principal on debt, if any, operating expenses and dividends to common shareholders are affected by dividends and other distributions from subsidiaries, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to capital markets or external financings. As of June 30, 2008, Edison International (parent) had no debt outstanding (excluding intercompany related debt).

Edison International (parent)’s cash requirements for the 12-month period following June 30, 2008 are expected to consist of:

•

Dividends to common shareholders. The Board of Directors of Edison International declared a $0.305 per share quarterly dividend in December 2007, February 2008, and April 2008. The dividends were paid in January 2008, April 2008, and July 2008, respectively;

•

Intercompany related debt; and

•

General and administrative expenses.

Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, external borrowings and dividends and/or borrowings from its subsidiaries. At June 30, 2008, Edison International (parent) had approximately $90 million of cash and cash equivalents on hand. On March 12, 2008, Edison International (parent) amended its existing $1.5 billion credit facility, extending the maturity to February 2013 while retaining existing borrowing costs as specified in the facility. The amendment also provides four extension options which, if all exercised, will result in a final termination of February 2017. At June 30, 2008, the entire credit facility was available for liquidity purposes. The ability of subsidiaries to make dividend payments to Edison International is dependent on various factors as described below.

SCE may pay dividends to Edison International subject to CPUC restrictions. The CPUC regulates SCE’s capital structure by requiring that SCE maintain prescribed percentages of common equity, preferred equity and long-term debt in the utility’s capital structure. SCE may not make any distributions to Edison International that would reduce the common equity component of SCE’s capital structure below the authorized level on a 13-month weighted average basis (see “SCE: Liquidity—Dividend Restrictions and Debt Covenants” for further discussion). The CPUC has also mandated that SCE’s dividend policy shall continue to be established by SCE’s Board of Directors as if SCE were a stand-alone utility and that the capital requirements of SCE be given first priority by the Boards of Directors of Edison International and SCE as necessary to meet its obligation to serve its customers. Other factors at SCE that affect the amount and timing of dividend payments by SCE to Edison International include, among other things, SCE’s capital requirements, SCE’s access to capital markets, payment of dividends on SCE’s preferred and preference stock, and actions by the CPUC. The Board of Directors of SCE declared a $25 million dividend which was paid in January 2008 and two $100 million dividends which were paid in April 2008 and July 2008, respectively.

EMG’s ability to pay dividends is dependent on its subsidiaries’ ability to pay dividends to EMG. EME’s corporate credit facility contains covenants that restrict its ability, and the ability of several of its subsidiaries, to pay dividends in the case of any event of default under the facility. As of June 30, 2008, EME was not in default under its credit facility (see “EMG: Liquidity—Dividend Restrictions in Major Financings” for further discussion). In addition, Edison Capital loaned $120 million to Edison International in January 2008 (total outstanding as of June 30, 2008 is $170 million).

EDISON INTERNATIONAL (PARENT): OTHER DEVELOPMENTS

Federal and State Income Taxes

Edison International remains subject to examination and administrative appeals by the IRS for tax years 1994 and forward. Edison International is challenging certain IRS deficiency adjustments for tax years 1994 – 1999 with the Administrative Appeals branch of the IRS and Edison International is currently under active IRS examination for tax years 2000 – 2002. In addition, the statute of limitations remains open for tax years 1986 – 1993, which has allowed Edison International to file certain affirmative claims related to these years. See “Other Developments—Federal and State Income Taxes” for further discussion of these matters.

EDISON INTERNATIONAL (CONSOLIDATED)

The following sections of the MD&A are on a consolidated basis and should be read in conjunction with the individual subsidiary discussion.

RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS

The following subsections of “Results of Operations and Historical Cash Flow Analysis” provide a discussion on the changes in various line items presented on the Consolidated Statements of Income, as well as a discussion of the changes on the Consolidated Statements of Cash Flows.

Results of Operations

The table below presents Edison International’s earnings for the three- and six-month periods ended June 30, 2008 and 2007, and the relative contributions by its subsidiaries.


In millions	Earnings (Loss)
Three-Month Period Ended June 30,	2008			2007
Earnings (Loss) from Continuing Operations:
SCE	$	157		$	144
EMG		112			(49	)
Edison International (parent) and other		(7	)		(4	)
Edison International Consolidated Earnings from Continuing Operations		262			91
Earnings (Loss) from Discontinued Operations		(1	)		2
Edison International Consolidated	$	261		$	93

In millions	Earnings (Loss)
Six-Month Period Ended June 30,	2008			2007
Earnings (Loss) from Continuing Operations:
SCE	$	307		$	325
EMG		271			106
Edison International (parent) and other		(13	)		(10	)
Edison International Consolidated Earnings from Continuing Operations		565			421
Earnings (Loss) from Discontinued Operations		(6	)		5
Edison International Consolidated	$	559		$	426

Earnings (Loss) from Continuing Operations

Edison International’s earnings from continuing operations were $262 million and $565 million for the three- and six-month periods ended June 30, 2008, respectively, compared with earnings of $91 million and $421 million for the comparable periods in 2007.

SCE’s earnings from continuing operations were $157 million and $307 million for the three- and six-month periods ended June 30, 2008, compared to $144 million and $325 million for the respective periods in 2007. SCE’s quarter and year-to-date earnings reflect lower taxes and interest, partially offset by lower operating income. The year-to-date earnings also reflect a $31 million tax benefit recognized in 2007 related to the income tax treatment of certain costs including those associated with environmental remediation.

EMG’s earnings from continuing operations were $112 million and $271 million for the three- and six-month periods ended June 30, 2008, respectively, compared with losses of $49 million for the three months ended

June 30, 2007 and earnings of $106 million for the respective periods in 2007. EMG’s quarter and year-to-date increases were mainly due to a $148 million, after tax, loss on early extinguishment of debt recorded in 2007, higher gross margin at EMG’s Illinois plants from higher generation and average realized energy and capacity prices. The second quarter earnings also reflect lower interest expense and a $23 million after-tax impact from the gain on sale of Edison Capital’s Beaver Valley lease and the year-to-date earnings reflect higher energy trading income at EMMT. The quarter and year-to-date increases were partially offset by lower operating revenue and higher plant maintenance expense at EMG’s Homer City.

Operating Revenue

Electric Utility Revenue

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


	Three Months Ended June 30,					Six Months Ended June 30,
In millions	2008		2007			2008		2007
Electric utility revenue
Retail billed and unbilled revenue	$	2,244	$	2,174		$	4,143	$	4,133
Balancing account over/under collections		164		(43	)		257		(56	)
Sales for resale		143		102			325		166
SCE’s VIEs		117		111			214		205
Other (including inter company transactions)		86		115			166		233
Total	$	2,754	$	2,459		$	5,105	$	4,681

SCE’s retail sales represented approximately 87% and 86% of electric utility revenue for the three- and six-month periods ended June 30, 2008, respectively, compared to approximately 86% for both of the comparable periods in 2007. Due to warmer weather during the summer months and SCE’s rate design, electric utility revenue during the third quarter of each year is generally higher than other quarters.

Total electric utility revenue increased by $295 million and $424 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007 (as shown in the table above). The variances for the revenue components are as follows:

•

Retail billed and unbilled revenue increased $70 million and $10 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The quarter and year-to-date increases reflect a rate increase (including impact of tiered rate structure) of $44 million and a decrease of $4 million, respectively, and a sales volume increase of $26 million and $14 million, respectively. The increase for the quarter was due to warmer weather experienced in June 2008 resulting in increased volumes sold at a higher rate due to SCE’s tiered rate structure.

•

Balancing account over/under collections increased $207 million and $313 million for the three- and six-month periods ended June 30, 2008, respectively. SCE recognizes revenue, subject to balancing account treatment, equal to the amount of the actual costs incurred and up to its authorized revenue requirement. Any revenue collected in excess of actual costs incurred or above the authorized revenue requirement is not recognized as revenue and is deferred and recorded as regulatory liabilities. Costs incurred in excess of revenue billed are deferred in a balancing account and recorded as regulatory assets for recovery in future rates. If amounts collected are below the authorized revenue requirement the difference is recognized as revenue and recorded as regulatory assets for recovery in future rates (See “—Provision for Regulatory Adjustment Clauses – Net” discussed below). For the three- and six-month periods ended June 30, 2008, SCE recognized approximately $164 million and $257 million, respectively, compared to a deferral of approximately $43 million and $56 million for the respective periods in 2007. The change in balancing account revenue is primarily due to SCE recognizing deferred revenue resulting from prior year overcollections.

•

Sales for resale represents the sale of excess energy. Excess energy from SCE sources which may exist at certain times is resold in the energy markets. Sales for resale revenue increased due to higher excess energy in 2008, compared to the same periods in 2007, resulting from increased kWh purchases from new contracts, as well as increased sales from least cost dispatch energy. Revenue from sales for resale is refunded to customers through the ERRA balancing account and does not impact earnings.

•

The decrease in other revenue for the three- and six-month periods ended June 30, 2008 was primarily related to lower net investment earnings and higher other-than-temporary impairment losses from SCE’s nuclear decommissioning trust due to a volatile stock market environment. Due to regulatory treatment, investment impairment losses and trust earnings and losses are offset in depreciation, decommissioning and amortization expense and as a result, have no impact on net income.

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 none of these collections are recognized as revenue by SCE. These amounts were $539 million and $1.1 billion for the three- and six-month periods ended June 30, 2008, respectively, compared to $503 million and $1.1 billion for the same respective periods in 2007.

Nonutility Power Generation Revenue

The following table sets forth the major components of nonutility power generation revenue:


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2008		2007		2008		2007
EMG’s Illinois plants	$	391	$	334	$	859	$	765
EMG’s Homer City facilities		127		176		312		374
EMMT		51		36		92		62
Other		43		23		67		40
Nonutility power generation	$	612	$	569	$	1,330	$	1,241

Nonutility power generation revenue increased $43 million and $89 million for the three- and six-month periods ended June 30, 2008, respectively, as compared to the same periods in 2007.

Nonutility power generation revenue from EMG’s Illinois plants increased $57 million and $94 million for the three- and six-month periods ended June 30, 2008, respectively. The increase was primarily attributable to higher generation and higher average realized energy and capacity prices.

Nonutility power generation revenue from EMG’s Homer City facilities decreased $49 million and $62 million for the three- and six-month periods ended June 30, 2008, respectively. The 2008 decreases were primarily attributable to lower generation and lower average realized energy prices as compared to 2007. Higher forced outages, lower off-peak dispatch and extended planned overhauls in 2008 contributed to lower generation. The average realized energy prices for the second quarter and six months ended June 30, 2008 were below the 24-hour PJM West Hub average market prices primarily due to effective hedge prices being below current market prices and the impact of higher basis (increase in energy prices at PJM West Hub greater than increase in prices at the Homer City busbar). For further discussion, see “EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities.”

EMG’s Illinois plants and Homer City recorded unrealized gains (losses) of $(9) million and $(15) million for the three- and six-month periods ended 2008, respectively, compared to $1 million and $(20) million for the respective periods in 2007. In 2008, unrealized losses were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges under SFAS No. 133. The ineffective portion of hedge contracts was primarily attributable to changes in the difference between energy

prices at the hedge locations (the settlement point under forward or futures contracts) and the energy prices at the busbars (the delivery point where power generated and delivered into the transmission system). In 2007, unrealized gains (losses) were primarily due to power contracts that did not qualify for hedge accounting under SFAS No. 133 (sometimes referred to as economic hedges). These energy contracts were entered into to hedge the price risk related to projected sales of power. At June 30, 2008, unrealized losses of $54 million were recognized primarily from the ineffective portion of cash flow hedges related to subsequent periods and to a lesser extent from economic hedges. See “EMG: Market Risk Exposures—Commodity Price Risk” for more information regarding forward market prices.

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 independent system operators. Nonutility power generation revenue from energy trading activities at EMMT increased $15 million and $30 million for the three- and six-month periods ended 2008, respectively, compared to the corresponding periods in 2007. The 2008 increase in nonutility power generation revenue from energy trading activities resulted from increased congestion and market volatility in key markets.

In April 2008, EMMT entered into three load services requirements contracts in Maryland with local utilities. Under the terms of the load services requirements contracts, EMMT is obligated to supply a portion of each utility’s load at fixed prices that vary based on periods specified in the contracts. EMMT is obligated to pay for the cost of supply at each utility’s load zones including, energy, capacity, ancillary services and renewable energy credits. The estimated load for the period October 1, 2008 through September 30, 2010 is approximately 4 million megawatt hours. EMMT has entered into futures contracts to substantially hedge the energy price risk related to these contracts. The above contracts are recorded as derivatives with the change in fair value reflected in trading income above.

EMG’s other project revenue increased by $20 million and $27 million for the three- and six-month periods ended June 30, 2008, respectively. The quarter and year-to-date increases were primarily due to the commencement of commercial operation of wind projects that did not have comparable results in 2007.

Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenue 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. 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” for further discussion regarding market prices.

Operating Expenses

Fuel Expense


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2008		2007		2008		2007
SCE	$	397	$	285	$	746	$	595
EMG		157		153		344		329
Edison International Consolidated	$	554	$	438	$	1,090	$	924

SCE’s fuel expense increased $112 million and $151 million for the three- and six-month periods ended June 30, 2008, respectively, as compared to the same periods in 2007. The quarter and year-to-date increases were mainly

due to an increase at SCE’s Mountainview plant of $50 million and $85 million, respectively, resulting from higher gas costs in 2008; and higher gas costs at SCE’s VIEs which resulted in increases of $60 million and $65 million, respectively.

EMG’s fuel expense increased $15 million for the six months ended June 30, 2008, as compared to the same period in 2007. The year-to-date increase was mainly due to higher coal and transportation costs per megawatt hour at EMG’s Illinois plants mainly due to cost escalations included in the transportation contracts.

Purchased-Power Expense

The following is a summary of SCE purchased-power expense:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2008			2007			2008			2007
Purchased-power	$	1,064		$	792		$	1,708		$	1,242
Unrealized (gains) losses on economic hedging activities – net		(333	)		40			(486	)		(94	)
Realized (gains) losses on economic hedging activities – net		(28	)		23			(26	)		52
Energy settlements and refunds		(47	)		(26	)		(47	)		(54	)
Total purchased-power expense	$	656		$	829		$	1,149		$	1,146

Total purchased-power expense decreased $173 million for the three months ended June 30, 2008 and increased $3 million for the six months ended June 30, 2008, as compared to the same periods in 2007.

Purchased power, in the table above, increased $272 million and $466 million for the three- and six-month periods ended June 30, 2008, respectively, as compared to the same periods in 2007. The quarter and year-to-date increases were due to: higher bilateral energy purchases of $205 million and $250 million, respectively, resulting from higher costs per kWh due to higher gas prices and increased kWh purchases from new contracts entered into in late 2007; higher QF purchased-power expense of $30 million and $90 million, respectively, resulting from increased kWh purchases and an increase in the average spot natural gas prices for certain contracts (as discussed further below); and higher ISO-related energy costs of $30 million and $115 million, respectively. SCE energy settlement refunds and generator settlements increased by $21 million for the three months ended June 30, 2008 (see “SCE: Regulatory Matters—Current Regulatory Developments—FERC Refund Proceedings” for further discussion).

Net realized and unrealized gains on economic hedging activities, in the table above, was $361 million for the three months ended June 30, 2008, compared to losses of $63 million for the three months ended June 30, 2007. Net realized and unrealized gains on economic hedging activities, in the table above, was $512 million and $42 million for the six months ended June 30, 2008 and 2007, respectively (see “SCE: Market Risk Exposures—Commodity Price Risk” for further discussion). The changes in net realized and unrealized gains on economic hedging activities were primarily due to increases in forward natural gas prices in 2008, compared to the same period in 2007. Due to expected recovery through regulatory mechanisms realized and unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings (see “SCE: Market Risk Exposures—Commodity Price Risk” for further discussion).

Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments to gas-fired QFs are generally tied to spot natural gas prices. Energy payments for most renewable QFs are at a fixed price of 5.37¢ per-kWh. In late 2006, certain renewable QF contracts were amended and energy payments for these contracts are at a fixed price of 6.15¢ per-kWh, effective May 2007.

Provisions for Regulatory Adjustment Clauses – Net

Provisions for regulatory adjustment clauses – net increased $312 million for the three-month period ended June 30, 2008, and increased $197 million for the six-month period ended June 30, 2008, compared to the same periods in 2007. The quarter and year-to date variances reflect a decrease of $55 million and $115 million, respectively, as a result of the rate reduction notes being fully repaid as of December 31, 2007 (See “SCE: Liquidity—Rate Reduction Notes” in the year-ended 2007 MD&A). The quarter variance also reflects net unrealized gains on economic hedging activities of approximately $333 million in 2008, compared to losses of $40 million for the same period in 2007 (discussed above in “—Purchased-Power Expense”); higher FTR costs of $10 million; and approximately $15 million resulting from lower net undercollections primarily due to the Midway-Sunset settlement which was charged/refunded to ratepayers through regulatory mechanisms (see “Other Developments: Midway-Sunset Cogeneration Company” for further information). The year-to-date variance also reflects net unrealized gains on economic hedging activities of approximately $486 million and $94 million for the six months ended June 30, 2008 and 2007, respectively (discussed above in “—Purchased-Power Expense”); approximately $29 million related to a generator settlement recorded in 2007; higher FTR costs of $45 million; lower exchange energy of $10 million; and $15 million of higher net undercollections of purchased-power, fuel, and operation and maintenance expenses resulting from higher procurement costs which are being recovered through regulatory mechanisms, partially offset by the Midway-Sunset settlement discussed above.

Other Operation and Maintenance Expense


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2008		2007		2008		2007
SCE	$	812	$	715	$	1,553	$	1,372
EMG		288		273		515		493
Edison International (parent) and other		10		11		17		14
Edison International Consolidated	$	1,110	$	999	$	2,085	$	1,879

SCE’s other operation and maintenance expense increased $97 million and $181 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. Certain of SCE’s operation and maintenance expense accounts are recovered through regulatory mechanisms approved by the CPUC and do not impact earnings. The costs associated with these regulatory balancing accounts increased $50 million and $60 million for the three- and six-month periods ended June 30, 2008 mainly related to higher demand-side management costs and energy efficiency costs. The increases in operation and maintenance expense also reflect: higher administrative and general costs (including health care costs and other employee-related expenses) of $30 million and $40 million for the three- and six-month periods ended June 30, 2008, respectively; higher customer service costs (including labor and uncollectible accounts) of $5 million and $15 million, respectively; and higher transmission and distribution maintenance costs of approximately $5 million and $20 million for the three- and six-month periods ended June 30, 2008, respectively. The year-to-date increase also reflects higher generation expenses of $30 million related to maintenance and refueling outage expenses at San Onofre and higher overhaul and outage costs at Four Corners and Palo Verde.

EMG’s other operation and maintenance expense increased $15 million and $22 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The 2008 increases were mainly due to higher plant maintenance expenses at EME’s Homer City facilities resulting from higher forced outages and extended planned overhauls in 2008. The increases also reflect higher labor costs and consulting expense resulting from EME’s growth activities.

Depreciation, Decommissioning and Amortization Expense


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2008		2007		2008		2007
SCE	$	286	$	271	$	539	$	546
EMG		47		42		92		80
Edison International (parent) and other		—		—		—		1
Edison International Consolidated	$	333	$	313	$	631	$	627

SCE’s depreciation, decommissioning and amortization expense increased $15 million and decreased $7 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The quarter and year-to-date variances were mainly due to an increase in depreciation expense of $20 million and $40 million, respectively, resulting from additions to transmission and distribution assets (see “SCE: Liquidity—Capital Expenditures” for a further discussion); and a $17 million cumulative depreciation rate adjustment recorded in the second quarter of 2008. The quarter and year-to-date variances were partially offset by a decrease of $20 million and $60 million, respectively, in nuclear decommissioning trust earnings and higher other-than-temporary impairment losses associated with the nuclear decommissioning trust funds primarily related to a volatile stock market environment. Due to its regulatory treatment, investment impairment losses and trust earnings and losses are recorded in electric utility revenue and are offset in decommissioning expense and have no impact on net income.

EMG’s depreciation and amortization expense increased $5 million and $12 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007, primarily attributable to higher depreciation expense for wind projects.

Gain on buyout of contract and sale of assets

Gain on buyout of contract and sale of assets increased $56 million and $72 million for the three- and six-month periods ended June 30, 2008, respectively. The 2008 quarter and year-to-date increases were primarily due to a $41 million gain on a termination of a lease. 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 exercise price is equal to the greater of a fixed amount and fair market value. The termination date of the lease under the early buy out option was June 1, 2008. Based on the fixed amount, the cash proceeds and net income from the termination of the lease (second quarter 2008) was $72 million and $23 million (after tax), respectively. The quarter and year-to-date increases also reflect approximately $7 million in gains on the sale of investments at Edison Capital and gains of $8 million from the sale of SO₂ emission allowances at SCE. Due to regulatory treatment, gains from the sale of emission allowances are offset in provision for regulatory adjustment clauses – net and, as a result, have no impact on net income. The year-to-date increase also reflects a gain of $15 million recorded during the first quarter of 2008 related to a buyout of a fuel contract (see “Commitments, Guarantees and Indemnities—Fuel Supply Contracts” for further discussion).

Other Income and Deductions

Interest and dividend income


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2008		2007		2008		2007
SCE	$	5	$	8	$	10	$	17
EMG		17		36		25		66
Edison International (parent) and other		—		1		1		2
Edison International Consolidated	$	22	$	45	$	36	$	85

SCE’s interest income decreased $3 million and $7 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The 2008 decreases were mainly due to lower undercollections balances in certain balancing accounts and lower interest rates applied to those undercollections.

EMG’s interest and dividend income decreased $19 million and $41 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The 2008 decreases were primarily attributable to lower average short-term investment balances and lower interest rates in 2008 compared to 2007.

Equity in Income from Partnerships and Unconsolidated Subsidiaries – Net

Equity in income from partnerships and unconsolidated subsidiaries – net decreased $11 million and $28 million for the three- and six-month periods ended June 30, 2008, compared to the same periods in 2007. The decrease in 2008 was mainly due to gains from Edison Capital’s global infrastructure funds recorded in the first and second quarters of 2007.

Other Nonoperating Income


	Three Months Ended June 30,					Six Months Ended June 30,
In millions	2008		2007			2008		2007
SCE	$	23	$	23		$	43	$	40
EMG		—		(1	)		6		(1	)
Edison International Consolidated	$	23	$	22		$	49	$	39

EMG’s other nonoperating income increased $7 million for the six months ended June 30, 2008, compared to the same period in 2007. The increase was due to an estimated insurance recovery of approximately $6 million recorded during the first quarter of 2008 primarily related to the outages at EMG’s Illinois plants (Powerton Station). On December 18, 2007, Unit 6 at the Powerton Station had a duct failure resulting in a suspension of operations at this unit through February 12, 2008. Scheduled maintenance work for the spring of 2008 was accelerated to minimize the aggregate impact of the outage.

Interest Expense – Net of Amounts Capitalized


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2008		2007		2008		2007
SCE	$	96	$	105	$	193	$	213
EMG		68		82		141		171
Edison International (parent) and other		1		1		2		2
Edison International Consolidated	$	165	$	188	$	336	$	386

SCE’s interest expense – net of amounts capitalized decreased $9 million and $20 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The quarter and year-to-date decreases were mainly due to lower overcollections of certain balancing accounts and lower interest rates applied to those overcollections in the first and second quarters of 2008 compared to the same periods in 2007.

EMG’s interest expense – net of amounts capitalized decreased $14 million and $30 million for the three- and six-month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The 2008 decreases were primarily attributable to MEHC’s redemption in full of its senior secured notes in June 2007. The variances are also attributable to $2.7 billion of new debt entered into by EME as part of its refinancing activities in May 2007 (see “EMG: Liquidity—EMG Financing Developments” in the year-ended 2007 MD&A).

Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt in the amount of $241 million for both the three- and six-month periods ended June 30, 2007 related to the early repayment of EME’s 7.73% senior notes due June 15, 2009, Midwest Generation’s 8.75% second priority senior secured notes due May 1, 2034, and MEHC’s 13.5% senior secured notes due July 15, 2008.

Income Tax Expense (Benefit) – Continuing Operations


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2008			2007			2008			2007
SCE	$	30		$	61		$	111		$	114
EMG		57			(54	)		140			22
Edison International (parent) and other		(4	)		(7	)		(7	)		(7	)
Edison International Consolidated	$	83		$	—		$	244		$	129

Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International’s effective tax rate was 24% and 30% for the three- and six-month periods ended June 30, 2008, respectively, as compared to 0% and 23% for the respective periods in 2007. The increased effective tax rates in 2008, as compared to 2007, were primarily due to reductions at SCE during 2007 as discussed below. The higher effective tax rates were partially offset by SCE internally developed software flow-through tax deductions recorded in 2008. The effective tax rates in 2007 were lower than the statutory rate primarily due to progress made in the first quarter of 2007 in an administrative appeal process with the IRS related to the income tax treatment of certain of SCE’s costs associated with environmental remediation; reductions made at SCE during the second quarter of 2007 to reflect receipt of a state Notice of Proposed Adjustment; and also due to property related flow-through items at SCE. In addition, the decreased effective tax rate in the second quarter of 2007 resulted from a reduction in pre-tax income.

As a matter of course, Edison International is regularly audited by federal, state and foreign taxing authorities. For further discussion of this matter, see “Other Developments—Federal and State Income Taxes.”

Minority Interest

Minority interest decreased $23 million and $35 million for the three- and six-month periods ended June 30, 2008, respectively, as compared to the same periods in 2007. The decrease was a result of lower earnings from two of SCE’s VIE projects due to lower pricing. The year-to-date decrease was also due to lower earnings from another SCE VIE project attributable to a planned outage in the first quarter of 2008.

Earnings from the Watson project are based on revised pricing effective January 1, 2008. Watson Cogeneration and SCE have disputed the commencement date of the prior contract which in turn affected the expiration date (Watson Cogeneration’s position is April 2008 whereby SCE’s position is December 2007). See “Market Risk Exposures—Big 4 Projects Power Purchase Agreements” in the year-ended 2007 MD&A for further discussion.

Income from Discontinued Operations

Edison International’s earnings (losses) from discontinued operations were $(1) million and $(6) million for the three- and six- month periods ended June 30, 2008, respectively, compared to $2 million and $5 million for the same periods in 2007. The losses in 2008 were primarily due to adjustments for foreign exchange losses and interest expense associated with contract indemnities related to EME’s sale of its international projects in December 2004. The income in 2007 was largely attributable to distributions received from EMG’s Lakeland project. For further discussion regarding the Lakeland project, see “Discontinued Operations” in the year-ended 2007 MD&A.

Historical Cash Flow Analysis

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

Cash Flows from Operating Activities

Net cash provided (used) by operating activities:


	Six Months Ended June 30,
In millions	2008			2007
Continuing operations	$	714		$	1,307
Discontinued operations		(6	)		5
Total	$	708		$	1,312

Cash provided by operating activities from continuing operations decreased $593 million in the first six months of 2008, compared to the first six months of 2007. The decrease was mainly due to ERRA undercollections in 2008, compared to ERRA overcollections in 2007. The increase in natural gas prices and the indirect affect on power prices have resulted in SCE using cash to pay for these higher costs in excess of amounts received from customers (see “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings”). The decrease is also attributable to an increase in required margin and collateral deposits in 2008 for EME’s hedging and trading activities due to higher forward market prices, and to the purchase of additional NO_X emission allowances in 2008 by EMG’s Illinois plants. The 2008 change was also due to the timing of cash receipts and disbursements related to working capital items.

Cash Flows from Financing Activities

Net cash provided (used) by financing activities:


	Six Months Ended June 30,
In millions	2008		2007
Continuing operations	$	469	$	(538)

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

Financing activities in 2008 were as follows:

•

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

•

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

•

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

•

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

•

Other financing activities in 2008 include dividend payments of $199 million paid by Edison International to its common shareholders and $51 million for stock purchased for stock-based compensation.

Financing activities in 2007 were as follows:

•

During the first half of 2007 SCE’s net issuances of commercial paper classified as short-term debt was $175 million.

•

In May 2007, EME issued $2.7 billion of senior notes, which was mostly used to repay $587 million of EME’s outstanding senior notes, repay $1 billion of Midwest Generation’s second priority senior secured notes, fund a dividend to MEHC which purchased approximately $796 million of its 13.5% senior secured notes, and repay $328 million of Midwest Generation’s senior secured term loan facility. In addition, EME and MEHC paid tender premiums and financing costs of $239 million related to the debt refinancing.

•

Other financing activities in 2007 include dividend payments of $189 million paid by Edison International to its common shareholders and $183 million for stock purchased for stock-based compensation.

Cash Flows from Investing Activities

Net cash used by investing activities:


	Six Months Ended June 30,
In millions	2008		2007
Continuing operations	$	1,548	$	1,350

Cash flows from investing activities are affected by capital expenditures, SCE’s funding of nuclear decommissioning trusts, and proceeds and maturities of investments.

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

Investing activities in 2007 reflect $1.1 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $28 million for nuclear fuel acquisitions, and $244 million in capital expenditures at EMG. Investing activities also include net maturities and sales of marketable securities of

$240 million at EMG, net purchases of nuclear decommissioning trust investments and other of $67 million, and $11 million in payments made towards the purchase price of the Wildorado wind project during the second quarter of 2007.

NEW ACCOUNTING PRONOUNCEMENTS

Accounting Pronouncements Adopted

Accounting Pronouncements Not Yet Adopted

In December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning on or after January 1, 2009. Early adoption is not permitted.

COMMITMENTS, GUARANTEES AND INDEMNITIES

The following is an update to Edison International’s commitments, guarantees and indemnities. See the section, “Commitments, Guarantees and Indemnities” in the year-ended 2007 MD&A for a detailed discussion.

Fuel Supply Contracts

In connection with the acquisition of the Illinois plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buyout its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million after tax) during the first quarter of 2008. The remaining payments due under this contract are $18 million.

Power-Purchase Contracts

Operating and Capital Leases

Turbine Commitments

EME and General Electric Company entered into an agreement during the second quarter of 2008 with respect to the purchase of 200 wind turbines (totaling 300 MW) together with related services and warranties. The wind turbines are to be delivered in 2010. The agreement contains certain delivery schedules and performance guarantees, along with provisions for liquidated damages if those guarantees are not met by General Electric. EME may terminate the purchase of individual turbines, or groups of turbines, for convenience; upon such termination, EME would be obligated to pay agreed termination charges to General Electric.

Included as part of the wind projects or turbine purchase commitments described above, EME had purchased 325 turbines from Suzlon Wind Energy Corporation (Suzlon), of which 180 are in service or at project sites under construction, and 71 turbines from Clipper Turbine Works, Inc. (Clipper). Rotor blade cracks were identified on certain Suzlon wind turbines, and rotor blade and gearbox problems were identified on certain Clipper wind turbines. Clipper, at its cost, has commenced its remediation plans that are designed to correct the current deficiencies. EME is continuing to work with Suzlon to analyze the root causes of the performance issues and address commercial matters that result from the impact of these issues on EME and its projects. During the second quarter of 2008, EME signed an agreement with Suzlon supplementing certain of EME’s wind turbine agreements with Suzlon, including providing EME with enhanced warranty and credit protections with respect to the rotor blade crack issues. Under this agreement, EME obtained the right to elect not to purchase some or all of the wind turbines that were to be delivered in 2009 without payment of cancellation fees. On May 30, 2008, EME notified Suzlon of its election not to purchase 150 turbines (315 MW) due to the time needed to complete the root cause analysis. For further discussion, see “EMG: Liquidity—Capital Expenditures—Wind Turbine Performance Issues” in the year-ended 2007 MD&A.

Capital Improvements

Other Commitments

Uncertain Tax Position Net Liability

At June 30, 2008, Edison International’s recorded net liability for uncertain tax positions was $425 million. Edison International currently cannot reliably predict the timing of cash flows associated with the resolution of uncertain tax positions due to the uncertainty as to the timing for resolving tax issues with the IRS related to ongoing examinations and administrative appeals. See “Other Developments—Federal and State Income Taxes” for further information.

OTHER DEVELOPMENTS

Environmental Matters

The operating subsidiaries of Edison International are subject to numerous federal and state environmental laws and regulations, which require them 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. Edison International believes that its operating subsidiaries are in substantial compliance with existing environmental regulatory requirements. However, the US EPA has issued a NOV to Midwest Generation and Commonwealth Edison, the former owner of Midwest Generation’s coal-fired power plants, alleging violations of the CAA and certain opacity and particulate matter standards. For information on the US EPA NOV issued to Midwest Generation, see “EMG: Other Developments—Midwest Generation Potential Environmental Proceeding” in the year-ended 2007 MD&A.

The domestic power plants owned or operated by Edison International’s operating subsidiaries, in particular their coal-fired plants, may be affected by recent developments in federal and state environmental laws and regulations. These laws and regulations, including those relating to SO₂ and NO_X emissions, mercury emissions, ozone and fine particulate matter emissions, regional haze, water quality, and climate change, may require significant capital expenditures at these facilities. The developments in certain of these laws and regulations are discussed in more detail below. These developments will continue to be monitored to assess what implications, if any, they will have on the operation of domestic power plants owned or operated by SCE, EME, or their subsidiaries, or the impact on Edison International’s consolidated results of operations or financial position.

For a discussion of Edison International’s environmental matters, refer to “Other Developments—Environmental Matters” in the year-ended 2007 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:

Climate Change

Litigation Developments

On February 28, 2008, the Native Village of Kivalina and the City of Kivalina, located off the coast of Alaska, filed a complaint in federal court in California against 24 defendants, including Edison International, who directly or through subsidiaries engage in electric generating, oil and gas, or coal mining lines of business. The complaint contends that the alleged global warming impacts of the GHG emissions associated with the defendants’ business activities are destroying the plaintiffs’ village through the melting of Arctic ice that had previously protected the village from winter storms. The plaintiffs further allege that the village will soon need to be abandoned or relocated at a cost of between $95 million and $400 million. Edison International cannot predict the outcome of this litigation.

State Specific Legislative Initiatives

SCE and EME are evaluating the CARB’s reporting regulations adopted pursuant to AB 32 and the draft scoping plan described below to assess the total cost of compliance.

AB 32 requires the CARB to approve a scoping plan for achieving the maximum technologically feasible and cost-effective reductions in GHG emissions on or before January 1, 2009. On June 26, 2008, the CARB released a draft scoping plan containing preliminary recommendations for measures that California will use to reduce GHG. The preliminary recommendations include: a California cap-and-trade program linked to the Western Climate Initiative covering electricity, transportation, residential/commercial, and industrial sources by 2020; California light-duty vehicle GHG standards; increased energy efficiency, including increasing combined heat and power use; a 33% by 2020 Renewable Portfolio Standard for both investor-owned and publicly owned utilities; a low-carbon fuel standard; measures to reduce high global warming potential gases; sustainable forest

measures; water sector measures; vehicle efficiency measures, goods movement measures; heavy/medium duty vehicle measures; the Million Solar Roofs program; local government actions and regional targets; supporting implementation of a high-speed rail system; recycling and waste measures; agriculture measures; and energy efficiency and co-benefits audits for large industrial sources. Other measures under evaluation for inclusion in the proposed scoping plan include, among other things, more aggressive energy efficiency programs and a coal emission reduction standard. The draft scoping plan is subject to public comment. CARB will consider adopting the proposed scoping plan in November 2008.

AB 32 also required the CARB to adopt regulations requiring the reporting and verification of statewide GHG emissions on or before January 1, 2008. On December 6, 2007 the CARB approved regulations for the mandatory reporting of GHG emissions, including the reporting of GHG emissions for the electricity sector. The CARB directed its staff to make some technical modifications to the proposed regulations, which had been issued in October 2007. The CARB staff issued revised regulations for public comment on May 15, 2008. Further revised regulations with changes based on public comments were issued by the CARB staff for public comment on June 30, 2008.

A renewable initiative that would impose a 50% RPS on all California electric utilities has qualified for the November 2008 ballot (see “SCE: Regulatory Matters—California Proposition 7—Solar and Clean Energy Initiative” for further discussion).

Air Quality Regulation

On July 1, 2008, EME began operating activated carbon injection technology to reduce mercury emissions at the Fisk, Crawford, and Waukegan stations. EME anticipates that the same technology will be implemented at the rest of the Illinois plants in the third quarter of 2009 and at the Homer City facilities in 2010.

Clean Air Interstate Rule

In July 2008, the District of Columbia Circuit Court of Appeals vacated the US EPA’s CAIR and remanded it to the US EPA. EME cannot predict whether the US EPA or any other party will seek a rehearing or appeal of the decision. The decision raises significant questions as to whether the US EPA will be able to design cap-and-trade programs for NO_X and SO₂ that are authorized and consistent with the CAA provisions that address upwind contributions to downwind states’ noncompliance with national ambient air quality standards for ozone and fine particulate matter. Because the CAIR was vacated, the Court’s decision means that the existing “SIP Call” ozone season NO_X cap-and-trade program, which was due to be replaced by the CAIR, will continue (assuming the decision is upheld).

EME is in the process of evaluating the impact of the D.C. Circuit’s decision on Midwest Generation and EME Homer City. Because Pennsylvania and Illinois promulgated their regulations in response to the CAIR, there is substantial uncertainty as to the impact of the decision on these state regulations. This is particularly true of Pennsylvania’s regulatory program, which is modeled on the federal CAIR and is dependent on the interstate emissions trading program established by the CAIR. Illinois also adopted the CAIR emissions trading programs, but in addition requires Midwest Generation to achieve reductions of NO_X and SO₂ (and mercury) through environmental control retrofits and plant shutdowns pursuant to a Combined Pollutant Standard. However, if the US EPA is required to propose a new regulation to address interstate transport of air pollution, EME cannot be certain that the emissions reductions currently required by the Combined Pollutant Standard will be sufficient to meet such revised regulations. In addition, the US EPA has allowed states to rely on compliance with the CAIR to satisfy obligations under other CAA programs, including regional haze regulations and reasonably available control technology requirements. Depending on what happens with respect to the CAIR, the Illinois plants and the Homer City facilities may be subject to additional requirements pursuant to these programs.

Based on the CAIR requirements, Midwest Generation purchased $48 million of annual NO_X allowances under the new CAIR annual NO_X program, which was vacated by the court ruling discussed above. As a result of this decision, the annual NO_X allowances may no longer be required. Midwest Generation is currently evaluating the above decision, including whether the purchased annual NO_X allowances are impaired, which could result in a charge against income during the third quarter ending September 30, 2008.

Illinois

As discussed under the heading “Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule—Illinois” in the year-ended 2007 MD&A, Midwest Generation entered into an agreement with the Illinois Environmental Protection Agency on December 11, 2006, to reduce mercury, NO_X and SO₂ emissions at Midwest Generation’s Illinois coal-fired power plants. On July 1, 2008, EME began operating activated carbon injection technology to reduce mercury emissions at the Fisk, Crawford, and Waukegan stations. EME anticipates that the same technology will be implemented at the rest of the Illinois plants in the third quarter of 2009, and at the Homer City facilities in 2010.

Ambient Air Quality Standards

Illinois

On March 12, 2008, the US EPA signed a final rule that implements revisions to the primary and secondary national ambient air quality standards for ozone, originally proposed on July 11, 2007. With regard to the primary standard for ozone, the US EPA has reduced the 8-hour standard to 0.075 parts per million (ppm) from the current standard of 0.84 ppm. The rule became effective on May 27, 2008. Attainment dates for the new standards range between 2013 and 2030, depending on the severity of the non-attainment. Based on 2005-2007 data, Chicago is likely to be in non-attainment with the new standard. Available data indicates that the area in which the Homer City facilities are located is likely to be in attainment. EME intends to consider the new standards as part of its overall plan for environmental compliance.

Water Quality Regulation

Clean Water Act—Cooling Water Intake Structures

California

On March 21, 2008 the California State Water Resources Control Board released its draft scoping document and preliminary draft Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling. This state policy is being developed in advance of the issuance of a final rule from the US EPA on standards for cooling water intake structures at existing large power plants. As anticipated, the Scoping Document establishes closed cycle wet cooling as the best technology available for retrofitting existing once-through cooled plants like SONGS. Additionally, the target levels for compliance with the state policy correspond to the high end of the ranges originally proposed in the US EPA’s rule. Nuclear-fueled power plants, including SONGS, would have until January 1, 2021 to comply with the policy. The policy development schedule included in the scoping document scheduled workshops and the submission of public comments in May 2008 and a public hearing in September 2008. The State Board vote has been informally delayed and is currently anticipated to occur in 2009. SCE continues to work with key government policy makers. This policy may significantly impact both operations at SONGS and SCE’s ability to procure timely supplies of generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems.

Environmental Remediation

regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that additional costs would be recovered from customers or that Edison International’s consolidated financial position and results of operations would not be materially affected.

Federal and State Income Taxes

Tax Positions being addressed as part of active examinations and administrative appeals processes

Balancing Account Over-Collections

Contingent Liability Company

The IRS has asserted deficiencies with respect to a transaction entered into by a former SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company for tax years 1997 – 1998. This is being considered by the Administrative Appeals branch of the IRS where Edison International is defending its tax return position with respect to this transaction.

Lease Transactions


In millions	Tax Years Under Appeal 1994 – 1999		Tax Years Under Audit 2000 – 2002		Unaudited Tax Years 2003 – 2007			Total
Replacement Leases (SILO)	$	44	$	19	$	27		$	90
Lease/Leaseback (LILO)		563		566		(8	)		1,121
Service Contract (SILO)		—		127		253			380
Total	$	607	$	712	$	272		$	1,591

As of June 30, 2008, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $590 million. The IRS has also asserted a 20% penalty on any sustained adjustment.

Recent developments, however, underscore the uncertain nature of tax conclusions in this area. Edison International believes that its maximum earnings exposure related to these leases, measured as of June 30, 2008, is approximately $1.25 billion after taxes, calculated by reclassifying deferred income taxes to current, recomputing the cumulative earnings under the leases in accordance with lease accounting rules (FASB Staff Position FAS 13-2), and recording interest related to the current income tax liability. This exposure does not include IRS asserted penalties of 20%, as Edison International does not believe that even if the tax benefits taken by Edison Capital are successfully challenged by the IRS that these penalties would be sustained. The current and future income and cash positions of SCE and EME are virtually unaffected by these leases.

As previously disclosed, Edison International has been engaged in settlement negotiations with the IRS. These negotiations seek to resolve the lease issues in their entirety and all other outstanding tax disputes for the years 1994 through 2002, including certain affirmative claims for unrecognized tax benefits. See “Edison International Notes to Consolidated Financial Statements—Note 3. Income Taxes.” These negotiations have progressed to the point where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolving such tax disputes on a “global” basis, including the lease issues. Final resolution of such disputes, however, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of such settlements by the Staff of the Joint Committee on Taxation, a committee of the United States Congress (the “Joint Committee”).

Midway-Sunset Cogeneration Company

On December 20, 2007, Midway-Sunset entered into a settlement agreement in the amount of $86 million (including interest) with SCE, PG&E, SDG&E and certain California state parties to resolve Midway-Sunset’s liability in the FERC refund proceedings. Midway-Sunset concurrently entered into a separate agreement with SCE and PG&E that provides for pro-rata reimbursement to Midway-Sunset by the two utilities of the portions of the agreed to refunds that are attributable to sales made by Midway-Sunset for the benefit of the utilities (Midway-Sunset did not retain any proceeds from power sold into the PX market on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed through those proceeds to the utilities). The settlement, which had been approved previously by the CPUC, was approved by the FERC on April 2, 2008.

Priority Reserve Ruling

In July 2008, the Los Angeles Superior Court found that actions taken by the South Coast Air Quality Management District in promulgating rules that had made available a “Priority Reserve” of emissions credits for new power generation projects did not satisfy California environmental laws. SCE is in the process of evaluating the impact of the decision on certain power-purchase agreements that resulted from its new generation RFO and the potential implications for its long-term resource adequacy requirements. Separately, EMG is evaluating the potential impact on EME’s Walnut Creek project.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

Management Changes

The following management changes recently took place at Edison International and EMG:

•

Effective as of the close of business on July 31, 2008, Theodore F. Craver, Jr. became Edison International’s Chairman, President and Chief Executive Officer, succeeding John E. Bryson upon his retirement. Mr. Craver became President of Edison International on April 1, 2008.

•

Effective August 1, 2008, W. James Scilacci, Jr. became Edison International’s Executive Vice President, Chief Financial Officer and Treasurer succeeding Thomas R. McDaniel, upon his retirement.

•

Effective April 1, 2008, Ronald L. Litzinger became Chairman, President and Chief Executive Officer for EMG succeeding Theodore F. Craver, Jr.

•

Effective August 1, 2008, John P. Finneran Jr. became Senior Vice President and Chief Financial Officer for EMG succeeding W. James Scilacci, Jr.

•

Effective August 1, 2008 Robert L. Adler became Edison International’s Executive Vice President and General Counsel, succeeding J.A. Bouknight, Jr., upon his retirement.

All management changes have been internal to Edison International, with the exception of Mr. Adler. There were no revisions to Edison International’s disclosures controls and procedures or internal control over financial reporting associated with these management changes.

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There were no changes in Edison International’s internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-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.

PART II. – OTHER INFORMATION

Item 1. Legal Proceedings

Catalina South Coast Air Quality Management District Potential Environmental Proceeding

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

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

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

Settlement negotiations with the SCAQMD regarding the penalties are ongoing and the SCAQMD has not yet proposed any specific fines to be imposed on SCE.

FERC Investigatory Proceeding against EMMT

On July 12, 2005, EMMT received a letter from the staff of the FERC Office of Enforcement (FERC Staff) stating that, by the letter, it was commencing a preliminary, non-public investigation of certain bidding practices of EMMT. In October 2006, EMMT was advised that the FERC Staff was prepared to recommend that the FERC initiate a formal investigatory proceeding and seek monetary sanctions against EMMT for alleged violation of the Energy Policy Act of 2005 and the FERC’s rules regarding market behavior, all with respect to certain bidding practices previously employed by EMMT. In ensuing exchanges between EMMT and the FERC Staff, EMMT provided information explaining that the business purpose for its bidding practices was the sale for risk mitigation purposes of a certain amount of power in the real-time rather than the day-ahead market.

Discussions with the FERC Staff led to a settlement agreement, which was accepted and adopted by the FERC in an order issued May 19, 2008. In the settlement agreement EMMT, Midwest Generation, and EME acknowledged that during the course of the investigation, although they had had no intent to mislead the FERC Staff, they had at times failed to provide complete and accurate information in response to FERC Staff inquiries, as required by FERC’s regulation (18 CFR § 35.41(b) (2007)). The settlement agreement required the payment of $7 million in civil penalties for violation of 18 CFR § 35.41(b) (2007) and development and implementation of a comprehensive regulatory compliance program at an estimated cost of $2 million. The order and settlement agreement operate to terminate the investigation with no assertion of findings of violation of FERC’s rules with respect to the bidding practices that were the subject of the investigation.

On June 18 and 19 2008, various parties, including the Attorney General of the State of Illinois, the Pennsylvania Public Utility Commission, Delaware Public Service Commission, New Jersey Board of Public Utilities, Indiana

Utility Regulatory Commission, the Public Utilities Commission of Ohio, the Virginia State Corporation Commission and the Illinois Commerce Commission filed various interventions and protests seeking to intervene in the FERC investigation docket, for the purpose of seeking clarification that the order and settlement agreement did not foreclose third party rights to seek redress against EMMT, Midwest Generation, and EME for any alleged market manipulation as a result of the bidding behavior or, in the alternative, obtaining an order reopening the investigation docket to allow further investigation into the bidding behavior. On July 3, 2008, EMMT, Midwest Generation, and EME responded to the filings of the various parties requesting that the filings should be dismissed based upon the applicable law and case precedent. On July 16, 2008, the FERC issued an order, commonly referred to as a tolling order, that granted rehearing of the order for the limited purpose of affording additional time for consideration of the matters raised in these filings. Absent the issuance of the tolling order, the timely filed rehearing requests would be deemed denied by operation of law. In the tolling order, the FERC noted that the pending rehearing requests will be addressed on their merits in a future order.

EME Homer City New Source Review Notice of Violation

Information about the EME Homer City New Source Review Notice of Violation appears in the MD&A under the heading “EMG: Other Developments—EME Homer City New Source Review Notice of Violation.”

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

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

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


Period	(a) Total Number of Shares (or Units) Purchased¹	(b) Average Price Paid per Share (or Unit)¹		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1, 2008 to April 30, 2008	386,672	$	50.86	—	—
May 1, 2008 to May 31, 2008	1,422,918	$	52.15	—	—
June 1, 2008 to June 30, 2008	856,505	$	51.63	—	—
Total	2,666,095	$	51.79	—	—

⁽¹⁾

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

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

At Edison International’s Annual Meeting of Shareholders on April 24, 2008, three matters were put to a vote of the shareholders: the election of twelve directors, ratification of the appointment of the independent public accounting firm and a shareholder proposal on “Shareholder Say on Executive Pay.”

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


	Number of Votes
Name	For	Withheld
John E. Bryson	276,668,907	9,664,559
Vanessa C.L. Chang	277,533,937	8,799,529
France A. Córdova	279,939,249	6,394,217
Theodore F. Craver, Jr.	278,676,073	7,657,393
Charles B. Curtis	280,066,414	6,267,052
Bradford M. Freeman	277,644,059	8,689,407
Luis G. Nogales	275,593,142	10,740,324
Ronald L. Olson	261,454,832	24,878,634
James M. Rosser	278,716,770	7,616,696
Richard T. Schlosberg, III	277,611,506	8,721,960
Thomas C. Sutton	276,016,111	10,317,355
Brett White	279,977,068	6,356,398

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


For	Against	Abstentions	Broker Non-Votes
275,328,516	7,167,412	3,837,538	0

The shareholder proposal on “Shareholder Say on Executive Pay,” which did not receive the affirmative vote of a majority of the votes cast, was not adopted. The proposal received the following numbers of votes:


For	Against	Abstentions	Broker Non-Votes
114,309,263	127,073,599	11,620,769	33,329,835

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Item 6. Exhibits

Edison International



10.1		Edison International Director Nonqualified Stock Options Terms and Conditions 2008

10.2		Edison International Director Compensation Schedule, as adopted June 27, 2008

31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

31.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

32		Statement Pursuant to 18 U.S.C. Section 1350

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SIGNATURE

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


EDISON INTERNATIONAL
(Registrant)

By:		/S/ LINDA G. SULLIVAN
		LINDA G. SULLIVAN Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

Dated: August 8, 2008

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