Edgar Filing: EDISON INTERNATIONAL

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, 2006

¨	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 ¨

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 July 31, 2006
Common Stock, no par value		325,811,206

EDISON INTERNATIONAL

INDEX


		Page No.
Part I. Financial Information:

Item 1.	Financial Statements:	1

	Consolidated Statements of Income – Three and Six Months Ended June 30, 2006 and 2005	1

	Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2006 and 2005	2

	Consolidated Balance Sheets – June 30, 2006 and December 31, 2005	3

	Consolidated Statements of Cash Flows – Six Months Ended June 30, 2006 and 2005	5

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	83

Item 4.	Controls and Procedures	83

Part II. Other Information:

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	84

Item 4.	Submission of Matters to a Vote of Security Holders	85

Item 6.	Exhibits	86

Signature		87

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	2006			2005			2006			2005
	(Unaudited)
Electric utility	$	2,521		$	2,203		$	4,739		$	4,109
Nonutility power generation		460			417			970			928
Financial services and other		20			29			44			56
Total operating revenue		3,001			2,649			5,753			5,093
Fuel		380			399			840			818
Purchased power		769			743			1,783			1,131
Provisions for regulatory adjustment clauses – net		(10	)		(41	)		(371	)		24
Other operation and maintenance		879			822			1,707			1,635
Depreciation, decommissioning and amortization		339			267			631			527
Property and other taxes		54			50			111			102
Net gain on sale of utility property and plant		(1	)		—			(1	)		—
Total operating expenses		2,410			2,240			4,700			4,237
Operating income		591			409			1,053			856
Interest and dividend income		43			25			80			47
Equity in income from partnerships and unconsolidated subsidiaries – net		10			24			14			108
Other nonoperating income		33			20			74			37
Interest expense – net of amounts capitalized		(209	)		(204	)		(409	)		(417	)
Loss on early extinguishment of debt		(143	)		—			(143	)		(24	)
Other nonoperating deductions		(10	)		(13	)		(22	)		(22	)
Income from continuing operations before tax and minority interest		315			261			647			585
Income tax		95			34			206			138
Dividends on utility preferred and preference stock not subject to mandatory redemption		13			5			25			7
Minority interest		34			42			59			65
Income from continuing operations		173			180			357			375
Income from discontinued operations – net of tax		4			21			77			28
Income before accounting change		177			201			434			403
Cumulative effect of accounting change – net of tax		—			—			1			—
Net income	$	177		$	201		$	435		$	403

Weighted-average shares of common stock outstanding		326			326			326			326
Basic earnings per common share:
Continuing operations	$	0.53		$	0.55		$	1.08		$	1.15
Discontinued operations		0.01			0.06			0.24			0.08
Total	$	0.54		$	0.61		$	1.32		$	1.23

Weighted-average shares, including effect of dilutive securities		331			331			331			331
Diluted earnings per common share:
Continuing operations	$	0.53		$	0.55		$	1.09		$	1.14
Discontinued operations		0.01			0.06			0.23			0.08
Total	$	0.54		$	0.61		$	1.32		$	1.22
Dividends declared per common share	$	0.27		$	0.25		$	0.54		$	0.50

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

EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2006			2005			2006			2005
	(Unaudited)
Net income	$	177		$	201		$	435		$	403
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments		2			(2	)		2			(2	)
Minimum pension liability adjustment		(2	)		—			(2	)		—
Unrealized gain (loss) on cash flow hedges:
Other unrealized gain (loss) on cash flow hedges – net		72			16			259			(54	)
Reclassification adjustment for gain (loss) included in net income		17			(3	)		(13	)		(8	)
Other comprehensive income (loss)		89			11			246			(64	)
Comprehensive income	$	266		$	212		$	681		$	339

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

EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS


In millions	June 30, 2006			December 31, 2005
	(Unaudited)
ASSETS
Cash and equivalents	$	1,858		$	1,893
Restricted cash		51			60
Margin and collateral deposits		366			739
Receivables, less allowances of $29 and $33 for uncollectible accounts at respective dates		1,104			1,220
Accrued unbilled revenue		490			291
Fuel inventory		152			80
Materials and supplies		274			261
Accumulated deferred income taxes – net		—			218
Trading and price risk management assets		193			316
Regulatory assets		740			536
Other current assets		397			345
Total current assets		5,625			5,959
Nonutility property – less accumulated provision for depreciation of $1,525 and $1,424 at respective dates		4,170			4,119
Nuclear decommissioning trusts		2,943			2,907
Investments in partnerships and unconsolidated subsidiaries		370			426
Investments in leveraged leases		2,472			2,447
Other investments		102			115
Total investments and other assets		10,057			10,014
Utility plant, at original cost:
Transmission and distribution		16,845			16,760
Generation		1,446			1,370
Accumulated provision for depreciation		(4,600	)		(4,763	)
Construction work in progress		1,256			956
Nuclear fuel, at amortized cost		175			146
Total utility plant		15,122			14,469
Regulatory assets		2,904			3,013
Restricted cash		121			105
Margin and collateral deposits		95			137
Trading and price risk management assets		118			132
Other long-term assets		1,109			951
Total long-term assets		4,347			4,338
Assets of discontinued operations		—			11

Total assets	$	35,151		$	34,791

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

EDISON INTERNATIONAL

CONSOLIDATED BALANCE SHEETS


In millions, except share amounts	June 30, 2006		December 31, 2005
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term debt	$	518	$	—
Long-term debt due within one year		368		745
Accounts payable		820		961
Accrued taxes		258		262
Accrued interest		210		212
Counterparty collateral		30		183
Customer deposits		188		183
Book overdrafts		194		257
Accumulated deferred income taxes – net		81		—
Trading and price risk management liabilities		290		418
Regulatory liabilities		710		681
Other current liabilities		698		1,057
Total current liabilities		4,365		4,959
Long-term debt		9,232		8,833
Accumulated deferred income taxes – net		5,338		5,256
Accumulated deferred investment tax credits		127		130
Customer advances and other deferred credits		1,072		1,179
Trading and price risk management liabilities		119		101
Power-purchase contracts		47		64
Accumulated provision for pensions and benefits		805		745
Asset retirement obligations		2,668		2,628
Regulatory liabilities		2,787		2,962
Other long-term liabilities		288		285
Total deferred credits and other liabilities		13,251		13,350
Liabilities of discontinued operations		—		14
Total liabilities		26,848		27,156
Commitments and contingencies (Notes 3 and 4)
Minority interest		304		301
Preferred and preference stock of utility not subject to mandatory redemption		915		719
Common stock, no par value (325,811,206 shares outstanding at each date)		2,042		2,043
Accumulated other comprehensive income (loss)		20		(226	)
Retained earnings		5,022		4,798
Total common shareholders’ equity		7,084		6,615

Total liabilities and shareholders’ equity	$	35,151	$	34,791

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

EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
In millions	2006			2005 Revised⁽¹⁾
	(Unaudited)
Cash flows from operating activities:
Net income	$	435		$	403
Less: income from discontinued operations		77			28
Income from continuing operations		358			375
Adjustments to reconcile to net cash provided by operating activities:
Cumulative effect of accounting change, net of tax		(1	)		—
Depreciation, decommissioning and amortization		631			527
Other amortization		43			47
Minority interest		59			65
Deferred income taxes and investment tax credits		160			(155	)
Equity in income from partnerships and unconsolidated subsidiaries		(14	)		(108	)
Income from leveraged leases		(36	)		(36	)
Regulatory assets – long-term		112			214
Regulatory liabilities – long-term		(174	)		(127	)
Loss on early extinguishment of debt		143			24
Levelized rent expense		(112	)		(67	)
Other assets		(82	)		19
Other liabilities		24			166
Margin and collateral deposits – net of collateral received		263			(114	)
Receivables and accrued unbilled revenue		(78	)		(268	)
Trading and price risk management assets – short-term		171			(50	)
Inventory and other current assets		(47	)		(1	)
Regulatory assets – short-term		(204	)		(199	)
Regulatory liabilities – short-term		29			276
Accrued interest and taxes		(4	)		282
Accounts payable and other current liabilities		(291	)		(97	)
Distributions and dividends from unconsolidated entities		26			39
Operating cash flows from discontinued operations		82			22
Net cash provided by operating activities		1,058			834
Cash flows from financing activities:
Long-term debt issued and issuance costs		2,120			980
Long-term debt repaid		(2,149	)		(1,848	)
Issuance of preference stock		196			395
Redemption of preferred stock		—			(148	)
Rate reduction notes repaid		(116	)		(116	)
Short-term debt financing – net		518			60
Change in book overdrafts		(64	)		30
Shares purchased for stock-based compensation		(101	)		(90	)
Proceeds from stock option exercises		33			51
Excess tax benefits related to stock option exercises		14			—
Dividends to minority shareholders		(63	)		(58	)
Dividends paid		(176	)		(163	)
Net cash provided (used) by financing activities	$	212		$	(907	)

(1)	See “Revisions” in Note 1 for further explanation.

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

EDISON INTERNATIONAL

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
In millions	2006			2005 Revised⁽¹⁾
	(Unaudited)
Cash flows from investing activities:
Capital expenditures	$	(1,207	)	$	(809	)
Purchase of interest of acquired companies		(18	)		—
Proceeds from sale of property and interests in projects		44			—
Proceeds from sale of discontinued operations		—			124
Proceeds from nuclear decommissioning trust sales		1,461			1,006
Purchases of nuclear decommissioning trust investments		(1,544	)		(1,057	)
Distributions from (investments in) partnerships and unconsolidated subsidiaries		13			68
Maturities and sales of short-term investments		97			140
Purchase of short-term investments		(173	)		—
Restricted cash		(15	)		21
Turbine deposits		(17	)		(9	)
Customer advances for construction and other investments		54			14
Investing cash flows from discontinued operations		—			5
Net cash used by investing activities		(1,305	)		(497	)
Effect of consolidation of variable interest entities on cash		—			3
Effect of exchange rate changes on cash		—			(1	)
Net decrease in cash and equivalents		(35	)		(568	)
Cash and equivalents, beginning of period		1,893			2,689
Cash and equivalents, end of period		1,858			2,121
Cash and equivalents, discontinued operations		—			(2	)
Cash and equivalents, continuing operations	$	1,858		$	2,119

(1)	See “Revisions” in Note 1 for further explanation.

The accompanying notes are an integral part of these 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 for a fair statement of the financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States for the periods covered by this quarterly report on Form 10-Q. The results of operations for the period ended June 30, 2006 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 on Form 10-K for the year ended December 31, 2005 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 2005 Annual Report. Edison International follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for stock-based compensation (discussed below in “New Accounting Pronouncements”).

On April 1, 2006, Mission Energy Holding Company (MEHC) received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. See Note 9, “Acquisitions and Disposition” for further information. These projects were previously owned by MEHC’s affiliate, Edison Capital. Edison Mission Group is a subsidiary of Edison International and is the holding company for its wholly owned subsidiaries, MEHC and Edison Capital. MEHC is the holding company of its wholly owned subsidiary Edison Mission Energy (EME). EME accounted for this acquisition at Edison Capital’s historical cost as a transaction between entities under common control. As a result of this capital contribution, Edison International’s nonutility power generation segment will now include the wind assets and biomass power project previously owned by Edison Capital.

Certain prior-period amounts were reclassified to conform to the June 30, 2006 financial statement presentation. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.

Earnings Per Common Share (EPS)

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 vested stock options that earn dividend equivalents on an equal basis with common shares. Basic EPS is computed by dividing net income available for common stock by the weighted-average number of common shares outstanding. Net income available for common stock was $175 million and $200 million for the three months ended June 30, 2006, and 2005, respectively, and was $431 million and $400 million for the six months ended June 30, 2006, and 2005, respectively. In arriving at net income, dividends on preferred and preference stock have been deducted.

For the diluted EPS calculation, dilutive securities (stock-based compensation awards exercisable) are added to the weighted-average shares. Dilutive securities are excluded from the diluted EPS calculation for items with a net loss due to their antidilutive effect.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes

Edison International’s effective tax rate from continuing operations was 35% and 37% for the three- and six-month periods ended June 30, 2006, respectively, as compared to 16% and 27% for the same periods in 2005. The increased effective tax rate resulted from reductions made to income tax reserves at Southern California Edison Company (SCE) and EME in 2005 which have not recurred in 2006. The 2005 reserve reductions were made to reflect progress in settlement negotiations relating to income tax audits.

Mohave Generating Station Shutdown

Mohave obtained all of its coal supply from the Black Mesa Mine in northeast Arizona, located on lands of the Navajo Nation and Hopi Tribe (the Tribes). This coal was delivered from the mine to Mohave by means of a coal slurry pipeline, which requires water from wells located on lands belonging to the Tribes in the mine vicinity. Uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave co-owners from making approximately $1.1 billion in Mohave-related investments (SCE’s share is $605 million), including the installation of enhanced pollution-control equipment required by a 1999 air-quality consent decree in order for Mohave to operate beyond 2005. Accordingly, the plant ceased operations, as scheduled, on December 31, 2005, consistent with the provisions of the consent decree.

On June 19, 2006, SCE announced that it had decided not to move forward with its efforts to return Mohave to service. SCE’s decision was not based on any one factor, but resulted from the conclusion that in light of all the significant unresolved challenges related to returning the plant to service, the plant could not be returned to service in sufficient time to render the necessary investments cost-effective for SCE’s customers. Two of the Mohave co-owners, Nevada Power Company and the Los Angeles Department of Water & Power (DWP), announced that they had reached this same conclusion, while the fourth co-owner, Salt River Project Agricultural Improvement and Power District, has advised SCE that it is still assessing its interest in putting together a successor owner group to allow continued coal operations. All of the co-owners have agreed to work together to evaluate options for disposition of the plant, which conceivably could include, among other potential options, sale of the plant “as is” to a power plant operator, decommissioning and sale to a developer, and decommissioning and apportionment of the land among the owners. At this time, SCE continues to work with the water and coal suppliers to the plant to determine if more clarity around the provision of such services can be provided to any potential acquirer.

Following the suspension of Mohave operations at the end of 2005, the plant’s workforce was reduced from over 300 employees to approximately 224 employees. The impacted employees were notified in April 2006 and the workforce reduction was completed by June 30, 2006. In July 2006, the co-owners decided to further reduce the workforce to 65 employees before the end of 2006. Termination costs for the June terminations of approximately $7 million (SCE’s share) were recorded in the second quarter and deferred in a balancing account authorized in the 2006 General Rate Case (GRC) decision. SCE indicated in July 2006 that it will ensure that remaining Mohave employees are considered for job placement opportunities elsewhere within the company. The amount of termination costs for the second workforce reduction will depend on the success of this effort. Due to this uncertainty, SCE management is unable to predict the amount of termination costs, if any, of the second workforce reduction at this time. However, SCE management believes these costs and other costs associated with the cessation of operations (excluding decommissioning) will range from zero to $14 million (SCE’s share). These additional costs will be recorded and deferred in the Mohave balancing account in late 2006. SCE expects to recover amounts in this balancing account in future rate-making proceedings.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$21 million. Based on the 2006 GRC decision, SCE is allowed to continue to earn its authorized rate of return on the Mohave investment and receive rate recovery for amortization, costs of removal, and operating and maintenance expenses, subject to balancing account treatment, during the three-year 2006 rate case cycle. SCE expects to file a notification with the California Public Utilities Commission (CPUC) regarding the status of Mohave by the end of 2006, and the CPUC may institute an investigation to determine whether to reduce SCE’s rates. At this time, SCE does not anticipate that the CPUC will order a rate reduction. In the past, the CPUC has allowed full recovery of investment for similarly situated plants. However, in a December 2004 decision, the CPUC noted that SCE would not be allowed to recover any unamortized plant balances if SCE could not demonstrate that it took all steps to preserve the “Mohave-open” alternative. SCE believes that it will be able to demonstrate that SCE did everything reasonably possible to return Mohave to service and that its unamortized costs are probable of future rate recovery. However, SCE cannot predict the outcome of any future CPUC action.

New Accounting Pronouncements

A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. Edison International implemented the new standard in the first quarter of 2006 and applied the modified prospective transition method. Under the modified prospective method, the new accounting standard was applied effective January 1, 2006 to the unvested portion of awards previously granted and will be applied to all prospective awards. Prior financial statements were not restated under this method. The new accounting standard resulted in the recognition of expense for all stock-based compensation awards. Prior to January 1, 2006, Edison International used the intrinsic value method of accounting, which resulted in no recognition of expense for its stock options.

Prior to adoption of the new accounting standard, Edison International presented all tax benefits of deductions resulting from the exercise of stock options as a component of operating cash flows under the caption “Other liabilities” in the consolidated statements of cash flows. The new accounting standard requires the cash flows resulting from the tax benefits that occur from estimated tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. The $14 million excess tax benefit is classified as a financing cash inflow in 2006.

Due to the adoption of this new accounting standard, Edison International recorded a cumulative effect adjustment that increased net income by approximately $1 million, net of tax, in the first quarter of 2006, mainly to reflect the change in the valuation method for performance shares classified as liability awards and the use of forfeiture estimates.

In April 2006, the Financial Accounting Standards Board (FASB) issued a Staff Position (FSP) that specifies how a company should determine the variability to be considered in applying the accounting standard for consolidation of variable interest entities. The pronouncement states that such variability shall be determined based on an analysis of the design of the entity, including the nature of the risks in the entity, the purpose for which the entity was created, and the variability the entity is designed to create and pass along to its interest holders. This new accounting guidance is effective prospectively beginning July 1, 2006, although companies have until December 31, 2006, to elect retrospective application. Edison International has not yet selected a transition method.

In July 2006, the FASB issued an interpretation relating to accounting for uncertainty in income taxes. This interpretation clarifies the accounting for uncertain tax positions. An enterprise would be required 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. The effective date is January 1, 2007. Edison International is currently assessing the potential impact of the interpretation on its financial condition.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In July 2006, the FASB issued an FSP on accounting for a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction. The effective date is January 1, 2007. As discussed under “Federal and State Income Taxes” in Note 3, the deferral of income taxes associated with Edison Capital’s cross-border, leveraged leases has been challenged by the Internal Revenue Service (IRS). If it becomes probable that Edison International would accelerate the payment of deferred taxes for these leases, the new FSP requires the change in the timing of cash flows to trigger a recalculation of the income allocated over the life of the lease, with the cumulative effect of the change recognized immediately. This could result in a material charge against earnings, although future income would be expected to increase over the remaining terms of the affected leases.

Regulatory Assets and Liabilities

Regulatory assets included in the consolidated balance sheets are:


In millions	June 30, 2006		December 31, 2005
	(Unaudited)
Current:
Regulatory balancing accounts	$	382	$	355
Direct access procurement charges		104		113
Energy derivatives		164		—
Purchased-power settlements		40		53
Other		50		15
		740		536
Long-term:
Flow-through taxes – net		1,118		1,066
Rate reduction notes – transition cost deferral		355		465
Unamortized nuclear investment – net		451		487
Nuclear-related asset retirement obligation investment – net		284		292
Unamortized coal plant investment – net		96		97
Unamortized loss on reacquired debt		320		323
Direct access procurement charges		5		40
Energy derivatives		81		58
Environmental remediation		83		56
Purchased-power settlements		22		39
Other		89		90
		2,904		3,013
Total regulatory assets	$	3,644	$	3,549

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory liabilities included in the consolidated balance sheets are:


In millions	June 30, 2006		December 31, 2005
	(Unaudited)
Current:
Regulatory balancing accounts	$	519	$	370
Direct access procurement charges		104		113
Energy derivatives		—		136
Other		87		62
		710		681
Long-term:
Asset retirement obligation		561		584
Costs of removal		2,134		2,110
Direct access procurement charges		4		39
Employee benefit plans		88		229
		2,787		2,962
Total regulatory liabilities	$	3,497	$	3,643

Revisions

Edison International revised its consolidated statements of cash flows for the six months ended June 30, 2005 to separately disclose the operating, financing and investing portions of the cash flows attributable to discontinued operations consistent with its consolidated statements of cash flow for the year ended December 31, 2005 included in Edison International’s Annual report on Form 10-K for the year ended December 31, 2005. Edison International had previously reported these amounts on a combined basis in its quarterly report on Form 10-Q for the quarter ended June 30, 2005.

Stock-Based Compensation

Edison International’s stock-based compensation plans primarily include the issuance of stock options and performance shares. Edison International usually does not issue new common stock for equity awards earned. Rather, a third party is used to facilitate the exercise of stock options and the purchase and delivery of outstanding common stock for settlement of performance shares earned. The amount of cash used to settle stock options exercised was $24 million and $59 million for the quarters ended June 30, 2006 and 2005, respectively, and $68 million and $90 million for the six months ended June 30, 2006, and 2005, respectively. The amount of cash used to settle performance shares classified as equity awards was less than $1 million and zero for the quarters ended June 30, 2006 and 2005, respectively, and $37 million and $20 million for the six months ended June 30, 2006 and 2005, respectively. Edison International has approximately 13.7 million shares remaining for future issuance under its stock-based compensation plans, which are described more fully in Note 2.

Prior to January 1, 2006, Edison International accounted for these plans using the intrinsic value method. Upon grant, no stock-based compensation cost for stock options was reflected in net income, as the grant date was the measurement date, and all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Previously, stock-based compensation cost for performance shares was remeasured at each reporting period and related compensation expense was adjusted. Previously, Edison International did not capitalize stock-based compensation cost related to both unvested awards and new awards. As discussed in “New Accounting Pronouncements” above, effective January 1, 2006, Edison International implemented a new accounting standard that requires companies to use the fair value accounting

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

method for stock-based compensation resulting in the recognition of expense for all stock-based compensation awards. Edison International recognizes stock-based compensation expense on a straight-line basis over the vesting period. Edison International is capitalizing a portion of its stock-based compensation cost related to both unvested awards and new awards. Edison International recognizes stock-based compensation expense for awards granted to retirement-eligible participants as follows: for stock-based awards granted prior to January 1, 2006, Edison International recognized stock-based compensation expense over the explicit vesting period and accelerated any remaining unrecognized compensation expense when a participant actually retired; for awards granted or modified after January 1, 2006 to participants who are retirement-eligible or will become retirement-eligible prior to the end of the normal vesting period for the award, stock-based compensation will be recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement. If Edison International recognized stock-based compensation expense for awards granted prior to January 1, 2006, over a period to the date the participant first became eligible for retirement, stock-based compensation expense would have decreased by less than $1 million for the quarter ended June 30, 2006, would have increased $3 million for the quarter ended June 30, 2005, would have decreased $2 million for the six months ended June 30, 2006 and would have increased $4 million for the six months ended June 30, 2005.

Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $13 million and $25 million for the three months ended June 30, 2006 and 2005, respectively, and was $23 million and $43 million for the six months ended June 30, 2006 and 2005, respectively. The income tax benefit recognized in the income statement was $5 million and $10 million for the three months ended June 30, 2006 and 2005, respectively, and was $9 million and $17 million for the six months ended June 30, 2006 and 2005, respectively. Total stock-based compensation cost capitalized for the three and six months ended June 30, 2006, was $1 million and $2 million, respectively.

The following table illustrates the effect on net income and EPS if Edison International had used the fair-value accounting method for the quarter and six months ended June 30, 2005.


	Three Months Ended June 30,		Six Months Ended June 30,
In millions, except per-share amounts	2005		2005
	(Unaudited)
Net income, as reported	$	201	$	403
Add: stock-based compensation expense using the intrinsic value accounting method – net of tax		15		25
Less: stock-based compensation expense using the fair-value accounting method – net of tax		13		25
Pro forma net income	$	203	$	403
Basic EPS:
As reported	$	0.61	$	1.23
Pro forma	$	0.62	$	1.23

Diluted EPS:
As reported	$	0.61	$	1.22
Pro forma	$	0.61	$	1.22

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Supplemental Accumulated Other Comprehensive Loss Information

Supplemental information regarding Edison International’s accumulated other comprehensive loss is:


In millions	June 30, 2006			December 31, 2005
	(Unaudited)
Foreign currency translation adjustments – net of tax	$	4		$	2
Minimum pension liability – net of tax		(15	)		(12	)
Unrealized gain (loss) on cash flow hedges – net of tax		31			(216	)
Accumulated other comprehensive income (loss)	$	20		$	(226	)

The minimum pension liability is discussed in Note 6, Compensation and Benefit Plans of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report.

Included in Edison International’s accumulated other comprehensive income at June 30, 2006, was a $31 million gain related to EME’s net unrealized gains on cash flow hedges.

Unrealized gains on cash flow hedges at June 30, 2006, include unrealized gains on commodity hedges primarily related to EME’s Homer City and Midwest Generation futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in the relevant markets are lower than contract prices. The decrease in the unrealized losses during the six months ended June 30, 2006 resulted from a decrease in market prices for power.

As EME’s hedged positions for continuing operations are realized, approximately $26 million (after tax) of the net unrealized gains on cash flow hedges at June 30, 2006 is expected to be reclassified into earnings during the next 12 months. EME expects that reclassification of the net unrealized gains will offset 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 an EME cash flow hedge is designated is through December 31, 2008.

Supplemental Cash Flows Information


	Six Months Ended June 30,
In millions	2006		2005
	(Unaudited)
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	361	$	377
Tax payments (receipts)		81		(47	)

Non-cash investing and financing activities:

Details of debt exchange:
Pollution-control bonds redeemed		—	$	(204	)
Pollution-control bonds issued		—		204
Funds held in trust		—		—

Dividends declared but not paid	$	88	$	81

Details of assets acquired:
Fair value of assets acquired	$	29		—
Liabilities assumed		—		—

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the first six months of 2006, EME accrued $11 million in connection with the purchase price of the Wildorado wind project due upon completion of construction. In addition, MEHC received a capital contribution of $76 million in the form of ownership interests in a portfolio of wind projects and a small biomass project.

Note 2. Compensation and Benefits Plans

Pension Plans

Edison International previously disclosed in Note 6 of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report that it expects to contribute approximately $66 million to its pension plans in 2006. As of June 30, 2006, $36 million in contributions have been made. Edison International anticipates that its original expectations will be met by year-end 2006.

Expense components are:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2006			2005			2006			2005
	(Unaudited)
Service cost	$	30		$	29		$	60		$	58
Interest cost		45			43			91			86
Expected return on plan assets		(59	)		(56	)		(117	)		(112	)
Special termination benefits		4			—			4			—
Net amortization and deferral		6			7			11			14
Expense under accounting standards		26			23			49			46
Regulatory adjustment – deferred		(1	)		(2	)		(3	)		(4	)
Total expense recognized	$	25		$	21		$	46		$	42

Due to the Mohave shutdown, SCE has incurred costs for special termination benefits. See “Mohave Generating Station Shutdown” in Note 1 for further information.

Postretirement Benefits Other Than Pensions

Edison International previously disclosed in Note 6 of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report that it expects to contribute approximately $79 million to its postretirement benefits other than pension plans in 2006. As of June 30, 2006, $13 million in contributions have been made. Edison International anticipates that its original expectation will be met by year-end 2006.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Expense components are:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2006			2005			2006			2005
	(Unaudited)
Service cost	$	13		$	12		$	25		$	24
Interest cost		32			31			64			62
Expected return on plan assets		(27	)		(25	)		(54	)		(51	)
Special termination benefits		3			—			3			—
Amortization of unrecognized prior service costs		(8	)		(8	)		(16	)		(15	)
Amortization of unrecognized loss		12			12			24			24
Total expense	$	25		$	22		$	46		$	44

Due to the Mohave shutdown, SCE has incurred costs for special termination benefits. See “Mohave Generating Station Shutdown” in Note 1 for further information.

Stock-Based Compensation

Stock Options

Under various plans, Edison International may grant stock options at exercise prices equal to the average of the high and low price at the grant date and other awards related to or with a value derived from its common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly over the vesting period, except for awards granted to retirement-eligible participants, as discussed in “Stock-Based Compensation” in Note 1. Stock-based compensation expense associated with stock options (including amounts capitalized) was $12 million for the three months ended June 30, 2006 and $20 million for the six months ended June 30, 2006. Under prior accounting rules, there was no comparable expense recognized for the same periods in 2005. See “Stock-Based Compensation” in Note 1 for further discussion.

Beginning with awards made in 2003, stock options accrue dividend equivalents for the first five years of the option term. Unless transferred to non-qualified deferral plan accounts, dividend equivalents accumulate without interest. Dividend equivalents are paid only on options that vest, including options that are unexercised. Dividend equivalents are paid in cash after the vesting date. Edison International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table.


	Three Months Ended June 30,		Six Months Ended June 30,
	2006	2005	2006	2005
	(Unaudited)
Expected terms (in years)	9 to 10	9 to 10	9 to 10	9 to 10
Risk-free interest rate	4.3% – 4.5%	4.2% – 4.3%	4.3% – 4.5%	4.2% – 4.3%
Expected dividend yield	2.6% – 2.8%	2.5% – 2.8%	2.4% – 2.8%	2.5% – 3.1%
Weighted-average expected dividend yield	2.7%	2.7%	2.4%	3.1%
Expected volatility	16.8% – 17.5%	18.7% – 19.2%	16.2% – 17.5%	18.7% – 19.6%
Weighted-average volatility	17.2%	18.9%	16.3%	19.6%

The expected term of options granted is based on the actual remaining contractual term of the options. The risk-free interest rate for periods within the contractual life of the option is based on a 52-week historical average of the 10-year semi-annual coupon U.S. Treasury note. In 2006, expected volatility is based on the historical volatility of Edison International’s common stock for the recent 36 months. Prior to January 1, 2006, expected volatility was based on the median of the most recent 36 months historical volatility of peer companies because Edison International’s historical volatility was impacted by the California energy crisis.

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, 2005	15,331,659		$	22.99
Granted	1,974,897		$	44.16
Expired	—			—
Forfeited	(38,357	)	$	29.07
Exercised	(1,584,445	)	$	21.08
Outstanding at June 30, 2006	15,683,754		$	25.83
Vested and expected to vest at June 30, 2006	15,062,132		$	25.60	6.59	$	216,254,560
Exercisable at June 30, 2006	8,601,348		$	21.78	5.31	$	156,351,003

The weighted-average grant-date fair value of options granted during the quarters ended June 30, 2006 and 2005, was $13.48 and $13.29, respectively. The weighted-average grant-date fair value of options granted during the six months ended June 30, 2006 and 2005, was $14.44 and $11.72, respectively. The total intrinsic value of options exercised during the quarters ended June 30, 2006 and 2005, was $11 million and $28 million, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2006 and 2005, was $35 million and $39 million, respectively. At June 30, 2006, there was $53 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately two years. The fair value of options vested during the quarters and six-month periods ended June 30, 2006 and 2005, was $5 million and $7 million, respectively.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash received from options exercised for the quarters ended June 30, 2006 and 2005, was $13 million and $32 million, respectively, and for the six months ended June 30, 2006 and 2005, was $33 million and $51 million, respectively. The estimated tax benefit from options exercised for the six months ended June 30, 2006 and 2005, was $14 million and $15 million, respectively.

Performance Shares

A target number of contingent performance shares were awarded to executives in January 2004, January 2005 and March 2006, and vest at the end of December 2006, 2007 and 2008, respectively. Dividend equivalents associated with these performance shares accumulate without interest and will be payable in cash following the end of the performance period when the performance shares are paid, although Edison International has discretion to pay certain dividend equivalents in Edison International common stock. The vesting of Edison International’s performance shares is dependent upon a market condition and three years of continuous service subject to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be accelerated. The market condition is based on Edison International’s common stock performance relative to the performance of a specified group of companies at the end of a three-calendar-year period. The number of performance shares earned is determined based on Edison International’s ranking among these companies. Dividend equivalents will be adjusted to correlate to the actual number of performance shares paid. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Additionally, cash awards are substituted to the extent necessary to pay tax withholding or any government levies. The portion of performance shares settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized ratably over the vesting period based on the fair values determined, except for awards granted to retirement-eligible participants, as discussed in “Stock-Based Compensation” in Note 1. Stock-based compensation expense associated with performance shares (including amounts capitalized) was $1 million and $19 million for the three months ended June 30, 2006 and 2005, respectively, and $4 million and $32 million for the six months ended June 30, 2006 and 2005, respectively.

The performance shares’ fair value is determined using a Monte Carlo simulation valuation model. The Monte Carlo simulation valuation model requires a risk-free interest rate and an expected volatility rate assumption. The risk-free interest rate is based on a 52-week historical average of the three-year semi-annual coupon U.S. Treasury note and is used as proxy for the expected return for the specified group of companies. Volatility is based on the historical volatility of Edison International’s common stock for the recent 36 months. Historical volatility for each company in the specified group is obtained from a financial data services provider.

Edison International’s risk-free interest rate and expected volatility used to determine the grant date fair values for the 2006 and 2005 performance shares classified as share-based equity awards was 4.1% and 16.2%, respectively, and 2.7% and 27.7%, respectively. The portion of performance shares classified as share-based liability awards are revalued at each reporting period. The risk-free interest rate and expected volatility rate used to determine the fair value as of June 30, 2006 was 4.5% and 17.2%, respectively.

The total intrinsic value of performance shares settled during the quarters ended June 30, 2006 and 2005, was $1 million and zero, respectively, which included cash paid to settle the performance shares classified as liability awards for the three months ended June 30, 2006 and 2005 of less than $1 million and zero, respectively. The total intrinsic value of performance shares settled during the six months ended June 30, 2006 and 2005, was $73 million and $40 million, respectively, which included cash paid to settle the performance shares classified as liability awards for the six months ended June 30, 2006 and 2005 of $24 million and $13 million, respectively. At

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2006, there was $12 million (based on the June 30, 2006 fair value of performance shares classified as liability awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of less than two years. The fair values of performance shares vested during the quarters and six-month periods ended June 30, 2006 and 2005, were less than $1 million and zero, respectively.

A summary of the status of Edison International nonvested performance shares classified as equity awards is as follows:


			Weighted-Average
	Performance Shares		Grant-Date Fair Value
	(Unaudited)
Nonvested at December 31, 2005	280,289		$	39.19
Granted	82,581		$	53.04
Forfeited	(2,963	)	$	37.74
Paid out	(5,057	)	$	39.77
Nonvested at June 30, 2006	354,850		$	42.42

The weighted-average grant-date fair value of performance shares classified as equity awards granted during the six months ended June 30, 2005, was $46.09.

A summary of the status of Edison International nonvested performance shares classified as liability awards (the current portion is reflected in the caption “Other current liabilities” and the long-term portion is reflected in “Accumulated provision for pensions and benefits” on the consolidated balance sheets) is as follows:


	Performance Shares		Weighted-Average Fair Value
	(Unaudited)
Nonvested at December 31, 2005	280,434
Granted	82,668
Forfeited	(2,966	)
Paid out	(5,058	)
Nonvested at June 30, 2006	355,078		$	76.80

Note 3. Contingencies

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

2006 General Rate Case (GRC) Proceeding

In December 2004, SCE filed its application for a 2006 GRC and subsequently revised its requested 2006 base rate revenue requirement to $3.96 billion, an increase of $465 million over SCE’s 2005 base rate revenue. When a one-time credit of $140 million from an existing balancing account overcollection was applied, SCE’s requested increase was $325 million. SCE also proposed revised base rate revenue increases of $108 million for 2007 and $113 million for 2008.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On May 11, 2006, the CPUC issued its final decision authorizing an increase of $274 million over SCE’s 2005 base rate revenue, retroactive to January 12, 2006. When the one-time credit of $140 million from an existing balancing account overcollection was applied, SCE’s authorized increase was $134 million. The CPUC also authorized increases of $74 million in 2007 and $104 million in 2008. The decision substantially approved SCE’s request to continue its capital investment program for infrastructure replacement and expansion, with authorized revenue in excess of costs for this program subject to refund. In addition, the decision provided for balancing accounts for pensions, postretirement medical benefits and certain incentive compensation expenses.

During the second quarter of 2006, SCE implemented the 2006 GRC decision and resolved an outstanding regulatory issue which resulted in a pre-tax benefit of approximately $175 million. The implementation of the 2006 GRC decision retroactive to January 12, 2006 mainly resulted in revenue of $50 million related to the revenue requirement for the period January 12, 2006 through May 31, 2006, partially offset by the implementation of the new depreciation rates resulting in increased depreciation expense of approximately $25 million for the period January 12, 2006 through May 31, 2006. In addition, there was a favorable resolution of a one-time issue related to a portion of revenue collected during the 2001–2003 period for state income taxes. SCE was able to determine through the 2006 GRC decision and other regulatory proceedings that the level of revenue collected during the period was appropriate, and as a result recorded a pre-tax gain of $135 million.

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 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.

Edison International’s recorded estimated minimum liability to remediate its 35 identified sites at SCE (24 sites) and EME (11 sites related to Midwest Generation) is $86 million, $82 million of which is related to SCE. 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 $117 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

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 31 immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $10 million.

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $32 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 $83 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 $25 million. Recorded costs for the twelve months ended June 30, 2006 were $14 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 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

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994–1996 and 1997–1999 tax years, respectively. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would be deductible on future tax returns of Edison International.

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 Edison Capital’s cross-border, leveraged leases.

The IRS is challenging Edison Capital’s foreign power plant and electric locomotive sale/leaseback transactions entered into in 1993 and 1994 (Replacement Leases, which the IRS refers to as a sale-in/lease-out or SILO). The IRS is also challenging Edison Capital’s foreign power plant and electric transmission system lease/leaseback transactions entered into in 1997 and 1998 (Lease/Leaseback, which the IRS refers to as a lease-in/lease-out or LILO).

Edison Capital also entered into a lease/service contract transaction in 1999 involving a foreign telecommunication system (Service Contract, which the IRS also refers to as a SILO). The IRS did not yet assert an adjustment for the Service Contract but is expected to challenge the Service Contract in subsequent audit cycles.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes estimated federal and state income taxes deferred from these leases. Repayment of these deferred taxes would be accelerated if the IRS prevails:


In millions	Tax Years Under Appeal 1994 – 1999		Unaudited Tax Years 2000 – 2005		Total
Replacement Leases (SILO)	$	44	$	36	$	80
Lease/Leaseback (LILO)		547		570		1,117
Service Contract (SILO)		—		272		272
	$	591	$	878	$	1,469

As of June 30, 2006, the interest on the proposed tax adjustments is estimated to be approximately $356 million. The IRS also seeks a 20% penalty on any sustained tax adjustment.

Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law in effect at the time the transactions were entered into, and it is vigorously defending its tax treatment of these leases. Written protests were filed to appeal the audit adjustments for the tax years under appeal asserting that the IRS’s position misstates material facts, misapplies the law and is incorrect. This matter is now being considered by the Administrative Appeals branch of the IRS.

In addition, the payment of taxes, interest and penalties could have a significant impact on earnings and cash flow. In order to commence litigation in certain forums, Edison International must make payments of disputed taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. On May 26, 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 cash payment was funded by Edison Capital and accounted for as a deposit which will be refunded with interest to the extent Edison International prevails. If the IRS either denies this refund claim or fails to act on the claim within six months, Edison International expects to take legal action to assert its refund claim. Depending on the status of the claim for tax year 1999, Edison International may make additional payments related to other tax years to preserve its litigation rights, although, at this time, the amount and timing of these additional payments is uncertain. At this time, Edison International is unable to predict the impact of the ultimate resolution of these matters.

Under an FSP on accounting for a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction and a FASB interpretation relating to accounting for uncertainty in income taxes, both issued in July 2006 and effective January 1, 2007, the payments made by Edison International will continue to be treated as a deposit unless it becomes more likely than not that a tax payment related to the resolution of the dispute will be made. If it becomes probable that such a tax payment will be made, the new FSP requires the change in the timing of cash flows to trigger a recalculation of the income allocated over the life of the lease, with the cumulative effect of the change recognized immediately. This could result in a material charge against earnings, although future income would be expected to increase over the remaining terms of the affected leases.

The IRS Revenue Agent Report for the 1997–1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company. While Edison International intends to defend its tax return position with respect to this transaction, the tax benefits relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these tax losses are sustained.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2001. These transactions include certain Edison Capital leveraged lease transactions and the SCE subsidiary contingent liability company transaction described above. Edison International filed these amended returns under protest retaining its appeal rights.

Federal Energy Regulatory Commission (FERC) Refund Proceedings

In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of electricity in the California Power Exchange (PX) and California Independent System Operator (ISO) markets. On March 26, 2003, the FERC staff issued a report concluding that there had been pervasive gaming and market manipulation of both the electric and natural gas markets in California and on the West Coast during 2000–2001 and describing many of the techniques and effects of that market manipulation. 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. SCE is required to refund to customers 90% of any refunds actually realized by SCE net of litigation costs, except for the El Paso Natural Gas Company settlement agreement (see discussion in Note 9 of “Notes to Consolidated Financial Statements” in Edison International’s 2005 Annual Report), and 10% will be retained by SCE as a shareholder incentive. A brief summary of the various settlements is below:

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In November 2005, the FERC approved a settlement agreement among SCE, Pacific Gas and Electric (PG&E) and San Diego Gas & Electric (SDG&E) and several governmental entities, and Enron Corporation and a number of its affiliates (collectively Enron), most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In January 2006, SCE received cash settlement proceeds of $4 million and anticipates receiving approximately $5 million in additional cash proceeds assuming certain contingencies are satisfied. SCE also received an allowed, unsecured claim against one of the Enron debtors in the amount of $241 million. In February 2006, SCE received a partial distribution of $10 million of its allowed claim. In April 2006, SCE received a distribution on its allowed bankruptcy claim against one of the Enron debtors of approximately $29 million, and 196,245 shares of common stock of Portland General Electric Company with an aggregate value of approximately $5 million. The remaining amount of the allowed claim that will actually be realized will depend on events in Enron’s bankruptcy that impact the value of the relevant debtor estate.

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In December 2005, the FERC approved a settlement agreement among SCE, PG&E, SDG&E, several governmental entities and certain other parties, and Reliant Energy, Inc. and a number of its affiliates. In January 2006, SCE received its $65 million share of the settlement proceeds. In March 2006, SCE received an additional $61 million.

On November 19, 2004, the CPUC issued a resolution authorizing SCE to establish an energy settlement memorandum account (ESMA) for the purpose of recording the foregoing settlement proceeds from energy providers and allocating them in accordance with a settlement agreement. The resolution provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA are allocated to recovery of SCE’s litigation costs and expenses in the FERC refund proceedings described above and the 10% shareholder incentive. Remaining amounts for each settlement are to be refunded to ratepayers through the energy resource recovery account mechanism. During 2005, SCE recognized $23 million in shareholder incentives related to the FERC refunds described above.

On August 2, 2006, the United States Court of Appeals for the Ninth Circuit issued an opinion regarding the scope of refunds issued by the FERC. The Ninth Circuit widened the time period during which refunds could be issued to include the summer of 2000 for tariff violations and broadened the categories of transactions that could be subject to refund. The Ninth Circuit also held that the FERC’s company-specific, nonpublic investigations could not prevent parties from seeking relief through litigation. As a result of this decision, SCE may be able to recover additional refunds from sellers of electricity who manipulated the electric markets.

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Investigations Regarding Performance Incentives Rewards

SCE is eligible under its CPUC-approved performance-based ratemaking (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 has been conducting 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 for the years 1998, 1999 and 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. As a result of these findings, SCE accrued a $9 million charge in 2004 for the potential refunds of rewards that have been received.

SCE has taken remedial action as to the customer satisfaction survey misconduct by disciplining employees and terminating the employment of 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 received $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. Therefore, SCE accrued a $20 million charge in 2004 for the potential refund of these rewards. SCE has also proposed to withdraw the pending rewards for the 2001–2003 time frames.

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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 an employee. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004.

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, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE.

Also on June 15, 2006, the Consumer Protection and Safety Division (CPSD) of the CPUC also issued its report regarding SCE’s PBR program. In that report, the CPSD recommended that the CPUC order SCE to (1) implement the commitments SCE made in its internal investigations to refund and forgo earned and pending rewards totaling $14 million for the service planning and meter reading customer satisfaction components of PBR and totaling $35 million for the safety component of PBR; (2) pay an additional $56 million, based on the assumption that, absent the data falsification and inadequate recordkeeping, SCE’s planning and meter reading customer satisfaction performance would have incurred the maximum PBR penalty ($21 million), and its safety performance would have incurred the maximum PBR penalty ($35 million); (3) investigate the other customer satisfaction components of SCE’s PBR program, including phone center, in-person services, and field delivery services, and order SCE to refund an as yet unquantified amount; (4) refund other, as yet unquantified, ratepayer costs; and (5) pay as yet unquantified statutory fines for alleged improper administration of the PBR program and alleged filing of misleading information. If imposed, such fines could range from $500 to $20,000 per day for each action determined to be a violation, over the seven years during which the PBR program was in effect.

Evidentiary hearings which will address the planning and meter reading components of customer satisfaction, safety, issues related to SCE’s administration of the survey, and statutory fines associated with those matters are scheduled to take place in the fourth quarter of 2006. A schedule has not been set to address the other components of customer satisfaction, system reliability, and other issues. SCE cannot predict the outcome of these matters or estimate the potential amount of any additional refunds, disallowances, or penalties that may be required.

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 schedule coordinators in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from schedule 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 schedule 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. A decision is expected in late 2006. The FERC may require SCE to pay these costs, but SCE does not believe this outcome is probable. If SCE is required to pay these costs, SCE may seek recovery in its reliability service rates.

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Leveraged Lease Investments

Edison Capital has a net leveraged lease investment of $59 million, before deferred taxes, in three aircraft leased to American Airlines. American Airlines has reported net losses since 2000. 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, 2006, American Airlines was current in its lease payments to Edison Capital.

Edison Capital also has a net leveraged lease investment of $46 million, before deferred taxes, in a large natural gas-fired cogeneration plant leased to Midland Cogeneration Venture. During 2005, Midland Cogeneration Venture wrote down the book value of the power plant as a result of a substantial increase in long-term natural gas prices. A default of the lease could result in a loss of some or all of Edison Capital’s lease investment. At June 30, 2006, Midland Cogeneration Venture was current in its payments under the lease.

Midwest Independent Transmission System Operator (MISO) Revenue Sufficiency Guarantee Charges

On April 25, 2006, the FERC issued an order regarding the MISO’s “Revenue Sufficiency Guarantee” charges (RSG charges). The MISO’s business practice manuals and other instructions to market participants have stated, since the implementation of market operations on April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO’s tariff concerning that issue and, in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges, and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO’s tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that, to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. Edison Mission Marketing & Trading (EMMT) made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot reasonably estimate a range of loss related to this matter. In addition, the FERC’s April 25 order has been challenged by the MISO and other parties, including EMMT, and as the FERC has issued an extension of time to comply with the requirements of the order until after the date of issuance of an order on rehearing, the eventual outcome of these proceedings is unclear.

Navajo Nation Litigation

In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement for the Mohave Generating Station (Mohave). The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and Corrupt Organizations statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentation 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, as well as a declaration that Peabody’s lease and contract rights to mine coal on Navajo Nation lands should be terminated. SCE joined Peabody’s motion to strike the Navajo Nation’s complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C. District Court

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denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District’s motion for its separate dismissal from the lawsuit.

Certain issues related to this case were addressed by the United States Supreme Court in a separate legal proceeding filed by the Navajo Nation in the United States Court of Federal Claims against the United States Department of Interior. In that action, the Navajo Nation claimed that the Government breached its fiduciary duty concerning negotiations relating to the coal lease involved in the Navajo Nation’s lawsuit against SCE and Peabody. On March 4, 2003, the Supreme Court concluded, by majority decision, that there was no breach of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the Supreme Court’s conclusion, SCE and Peabody brought motions to dismiss or for summary judgment in the D.C. District Court action but the D.C. District Court denied the motions on April 13, 2004.

The Court of Appeals for the Federal Circuit, acting on a suggestion filed by the Navajo Nation on remand from the Supreme Court’s March 4, 2003 decision held, in an October 24, 2003 decision, that the Supreme Court’s decision was focused on three specific statutes or regulations and therefore did not address the question of whether a network of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the United States during the time period in question. On March 16, 2004, the Federal Circuit issued an order remanding the case against the Government to the Court of Federal Claims, which considered (1) whether the Navajo Nation previously waived its “network of other laws” argument and, (2) if not, whether the Navajo Nation can establish that the Government breached any fiduciary duties pursuant to such “network.” On December 20, 2005, the Court of Federal Claims issued its ruling and found that although there was no waiver, the Navajo Nation did not establish that a “network of other laws” created a judicially enforceable trust obligation. The Navajo Nation filed a notice of appeal from this ruling on February 14, 2006. The Navajo Nation’s opening brief was filed on June 7, 2006 and the Government filed its brief on July 20, 2006. No date for oral argument has been set.

Pursuant to a joint request of the parties, the D.C. District Court granted a stay of the action in that court to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with Mohave. Negotiations are ongoing and the stay has been continued until further order of the court.

SCE cannot predict the outcome of the 1999 Navajo Nation’s complaint against SCE, the impact on the complaint of the Supreme Court’s decision and the December 2005 Court of Federal Claims ruling in the Navajo Nation’s suit against the Government, or the impact on the facilitated negotiations of SCE’s recently announced decision to discontinue efforts to return Mohave to service.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre Nuclear Generating Station (San Onofre) and Palo Verde Nuclear Generating Station (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 Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994. The current maximum deferred premium for each nuclear incident is $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 on a 5-year schedule. The next inflation adjustment will occur on August 31, 2008. Based on its ownership interests, SCE could be required to pay a maximum of $199 million per nuclear incident. However, it would have to pay no more than

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$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 regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

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 $42 million per year. Insurance premiums are charged to operating expense.

Procurement of Renewable Resources

California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2017. The Joint Energy Action Plan adopted in 2003 by the CPUC and the California Energy Commission (CEC) accelerated the deadline to 2010.

SCE entered into a contract with Calpine Energy Services, L.P. (Calpine) to purchase the output of certain existing geothermal facilities in northern California. On January 30, 2003, the CPUC issued a resolution approving the contract. SCE interpreted the resolution as authorizing SCE to count all of the output of the geothermal facilities towards the obligation to increase SCE’s procurement from renewable resources and counted the entire output of the facilities toward its 1% obligation in 2003, 2004 and 2005. On July 21, 2005, the CPUC issued a decision stating that SCE can only count procurement pursuant to the Calpine contract towards its 1% annual renewable procurement requirement if it is certified as “incremental” by the CEC. On February 1, 2006, the CEC certified approximately 25% and 17% of SCE’s 2003 and 2004 procurement, respectively, from the Calpine geothermal facilities as “incremental.” A similar outcome is anticipated with respect to the CEC’s certification review for 2005.

On August 26, 2005, SCE filed an application for rehearing and a petition for modification of the CPUC’s July 21, 2005 decision. On January 26, 2006, the CPUC denied SCE’s application for rehearing of the decision. On May 25, 2006, the CPUC issued a decision denying SCE’s petition for modification.

SCE could have deficits in meeting its renewable procurement obligations for 2003 and 2004. However, based on the CPUC’s rules for compliance with renewable procurement targets, SCE may have until 2007 to make up these deficits before becoming subject to penalties for those years or may not have deficits at all. The CEC’s and the CPUC’s treatment of the output from the geothermal facilities could also result in SCE being deemed to be out of compliance in 2005 and 2006.

Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement obligations 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.

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Scheduling Coordinator Tariff Dispute

SCE serves as a scheduling coordinator for the Los Angeles DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges are billed to the DWP under a FERC tariff that remains subject to dispute. The DWP has paid the amounts billed under protest but requested that 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. As a result, SCE could be required to refund all or part of the amounts collected from the DWP under the tariff. As of June 30, 2006, SCE has accrued a $31 million charge to earnings for the potential refunds. If the FERC ultimately rules that SCE may not collect the scheduling coordinator charges from the DWP and requires the amounts collected to be refunded to the DWP, SCE would attempt to recover the scheduling coordinator charges from all transmission grid customers through another regulatory mechanism. However, the availability of other recovery mechanisms is uncertain, and ultimate recovery of the scheduling coordinator charges cannot be assured.

Settlement Agreement with Duke Energy Trading and Marketing, LLC

On May 10, 2006, SCE filed an application with the CPUC for approval of a settlement agreement between SCE and Duke Energy Trading and Marketing, LLC (DETM) that resolves disputes arising from DETM’s termination of certain bilateral power supply contracts in early 2001. Under the settlement, DETM will make principal and interest payments to SCE of approximately $75 million, which SCE proposes will be refunded to ratepayers through the energy resource recovery account mechanism. The settlement, once approved, will also permit $58 million in liabilities that SCE had previously recorded with respect to the DETM terminated contracts to be reversed, which will result in an equivalent gain being recorded by SCE. SCE’s application to the CPUC requests that this gain not be refunded to ratepayers since these liabilities were not funded by ratepayers. The recorded liabilities consist of $40 million in cash collateral received from DETM in 2000 and $18 million in power purchase payments that SCE, in light of DETM’s termination of the bilateral contracts, withheld for energy delivered by DETM in January 2001. A decision on SCE’s application for approval of the settlement is not expected until the end of 2006 or early 2007. SCE cannot predict the outcome of this matter.

Spent Nuclear Fuel

Under federal law, the United States Department of Energy (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 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. Pursuant to this schedule, SCE’s damages schedule must be produced by August 31, 2006. The discovery schedule provides for the government to produce its response on May 31, 2007 and for discovery to end on August 31, 2007. A Joint Status Report is due on September 7, 2007, regarding further proceedings in this case presumably including establishing a trial date.

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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 is stored. There is now sufficient space in the Unit 2 and 3 spent fuel pools to meet plant requirements through mid-2007 and mid-2008, respectively. In order to maintain a full core off-load capability, SCE is planning to begin moving Unit 2 and 3 spent fuel into the independent spent fuel storage installation by early 2007.

In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a dry cask storage facility. Arizona Public Service, as operating agent, plans to continually load casks on a schedule to maintain full core off-load capability for all three units.

Note 4. Commitments

The following is an update to Edison International’s commitments. See Note 8 of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report for a detailed discussion.

Other Commitments

At June 30, 2006, EME’s subsidiaries had firm commitments to spend approximately $157 million during the remainder of 2006 and $33 million in 2007 on capital and construction expenditures. The majority of these expenditures relate to the construction of the Wildorado wind project (see further discussion related to the Wildorado project in Note 9, Acquisitions and Disposition). Also included are expenditures for boiler head replacement, dust collection and mitigation system and various other projects. These expenditures are planned to be financed by existing subsidiary credit agreements, cash on hand or cash generated from operations.

At June 30, 2006, in connection with wind projects in development, EME had entered into agreements with turbine vendors securing 235 turbines with remaining commitments of $110 million in 2006 and $244 million in 2007. In addition, EME had options to acquire an additional 50 turbines for delivery in 2007 that were exercised on July 31, 2006. In July 2006, EME entered into an agreement to purchase 20 turbines from another supplier with options to purchase another 32 turbines for delivery in 2007 subject to certain conditions.

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

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Indemnities Provided as Part of EME’s 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. 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 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 existing asbestos claims and 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 has a five-year term with an automatic renewal provision (subject to the right of either party to terminate). 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 175 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2006. Midwest Generation had recorded a $66 million liability at June 30, 2006 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 EME’s Acquisition of the Homer City Facilities

In connection with the acquisition of the Homer City facilities, EME Homer City Generation L.P. (EME Homer City) agreed to indemnify the sellers with respect to specific environmental liabilities before and after the date of sale. 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. Payments would be triggered under this indemnity by a claim from the sellers. 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. During the second quarter of 2006, EME paid $34 million related to an indemnity to IPM for matters arising out of the exercise by one of its project partners of a purported right of first refusal. 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, 2006, EME had recorded a liability of $94 million related to these matters.

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

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. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore Cogeneration Company under its project power sales agreement to repay capacity payments to the project’s power purchaser in the event that the project unilaterally terminates its performance or reduces its electric power producing capability during the term of the power sales agreements. The obligations under the indemnification agreements as of June 30, 2006, if payment were required, would be $114 million. EME has not recorded a liability related to these indemnities.

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. The generating station has not operated since early 2001. 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.

Other SCE Indemnities

SCE 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. SCE’s obligations under these agreements may be limited in terms of time and/or amount, and in some instances SCE 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. SCE has not recorded a liability related to these indemnities.

Note 5. Business Segments

Edison International’s reportable business segments include its electric utility operation segment (SCE), a nonutility power generation segment (MEHC – parent only and EME), and a financial services provider segment (Edison Capital). As a result of Edison International’s change in the structure of its internal organization and in accordance with an accounting standard related to operating segments, prior periods have been restated to conform to Edison International’s new business segment definition. See further discussion in “Basis of Presentation” in Note 1.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Segment information for the three and six months ended June 30, 2006 and 2005 was:


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2006			2005			2006			2005
	(Unaudited)
Operating Revenue:
Electric utility	$	2,521		$	2,203		$	4,739		$	4,109
Nonutility power generation		460			422			975			939
Financial services		19			19			38			40
Corporate and other		1			5			1			5
Consolidated Edison International	$	3,001		$	2,649		$	5,753		$	5,093
Net Income (Loss):
Electric utility⁽¹⁾	$	234		$	161		$	355		$	292
Nonutility power generation⁽²⁾		(56	)		23			75			57
Financial services		5			22			20			73
Corporate and other		(6	)		(5	)		(15	)		(19	)
Consolidated Edison International	$	177		$	201		$	435		$	403

(1)	Net income available for common stock.

(2)	Includes earnings from discontinued operations of $4 million and $21 million, respectively, for the three months ended June 30, 2006 and 2005, and $77 million and $28 million, respectively, for the six months ended June 30, 2006 and 2005.

Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment.

Total segment assets as of June 30, 2006, were: electric utility, $25 billion; nonutility power generation, $7 billion; and, financial services, $3 billion.

Note 6. Liabilities and Lines of Credit

Long-Term Debt

On June 6, 2006, EME completed a private offering of $500 million aggregate principal amount of its 7.50% senior notes due June 15, 2013 and $500 million aggregate principal amount of its 7.75% senior notes due June 15, 2016. EME will pay interest on the senior notes on June 15 and December 15 of each year, beginning on December 15, 2006. The senior notes are redeemable by EME at any time at a price equal to 100% of the principal amount of, plus accrued and unpaid interest and liquidated damages, if any, on, the senior notes plus a “make-whole” premium.

The senior notes are EME’s senior unsecured obligations, ranking equal in right of payment to all of EME’s existing and future senior unsecured indebtedness, and will be senior to all of EME’s future subordinated indebtedness. EME’s secured debt and its other secured obligations are effectively senior to the senior notes to the extent of the value of the assets securing such debt or other obligations. None of EME’s subsidiaries have guaranteed the senior notes and, as a result, all the existing and future liabilities of EME’s subsidiaries are effectively senior to the senior notes.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

aggregate principal amount of its 9.875% senior notes due April 15, 2011. The net proceeds of the offering of the senior notes, together with cash on hand, were also used to pay related tender premiums, consent fees and accrued interest. EME recorded a $143 million loss on early extinguishment of debt during the second quarter of 2006.

Reflecting the above refinancing transactions, long-term debt maturities and sinking fund requirements as of June 30, 2006 are:


In millions
	(Unaudited)
July through December 2006	$	190
2007		486
2008		879
2009		763
2010		312

Short-Term Debt

Short-term debt is used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements. At June 30, 2006, Edison International’s outstanding short-term debt and weighted-average interest rate was $518 million and 5.35%, respectively.

Lines of Credit

At June 30, 2006, Edison International and its subsidiaries had $2.4 billion of borrowing capacity available under lines of credit totaling $3.2 billion. SCE had a $1.7 billion line of credit with $946 million available. EME had a line of credit of $500 million available. Edison International (parent) has a $1.0 billion line of credit available. These credit lines have various expiration dates, and when available, can be drawn down at negotiated or bank index rates.

These amounts have been updated primarily to reflect EME’s financing activities completed during the second quarter of 2006. EME’s new credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate debt to corporate capital ratio. A failure to meet a ratio threshold could trigger other provisions, such as mandatory prepayment provisions or restrictions on dividends.

Note 7. Preferred and Preference Stock of Utility Not Subject to Mandatory Redemption

In January 2006, SCE issued two million shares of 6.0% Series C preference stock (noncumulative, $100 liquidation value) and received net proceeds of $197 million. The Series C preference stock may not be redeemed prior to January 31, 2011. After January 31, 2011, SCE may, at its option, redeem the shares in whole or in part. The Series C preference stock has the same general characteristics as the Series A and B preference stock. See Note 4 of “Notes to Consolidated Financial Statements” included in Edison International’s 2005 Annual Report for additional information on SCE’s preference stock.

At June 30, 2006, accrued dividends related to SCE’s preferred and preference stock not subject to mandatory redemption were $13 million.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 8. Discontinued Operations

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project, pursuant to a purchase agreement dated December 15, 2004, to a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately $20 million. The sale of this investment had no significant effect on net income in the first quarter of 2005.

On January 10, 2005, EME sold its 50% equity interest in the Caliraya-Botocan-Kalayaan (CBK) project to Corporacion IMPSA S.A., pursuant to a purchase agreement dated November 5, 2004. Proceeds from the sale were approximately $104 million. EME recorded a pre-tax gain on the sale of approximately $9 million during the first quarter of 2005.

EME previously owned a 220-MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of a default by its counterparty, a subsidiary of TXU Europe Group plc and the project company was subsequently placed in liquidation. In response to its claim against the TXU subsidiary for damages from the termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the amount of the settlement remaining after payment of creditor claims. As creditor claims have been settled, EME has received to date payments of £13 million (approximately $24 million) in April 2005, £61 million (approximately $106 million) in the first quarter of 2006, and £9 million (approximately $16 million) in April 2006. The after-tax income attributable to the Lakeland project was $10 million and $24 million for the second quarters of 2006 and 2005, respectively, and $83 million and $24 million for the six months ended June 30, 2006 and 2005, respectively. Beginning in 2002, EME reported the Lakeland project among discontinued operations and accounts for its ownership of Lakeland Power on the cost method with earnings being recognized as cash is distributed from the project.

For all periods presented, the results of EME’s projects discussed above have been accounted for as discontinued operations in the consolidated financial statements in accordance with an accounting standard related to the impairment and disposal of long-lived assets.

For the three months ended June 30, 2006, and 2005, there was no revenue from discontinued operations and pre-tax income was $7 million and $22 million, respectively. For the six months ended June 30, 2006, and 2005, there was no revenue from discontinued operations and pre-tax income was $119 million and $22 million, respectively. For the six months ended June 30, 2005, there was a $9 million gain on sale before taxes.

There were no assets or liabilities of discontinued operations at June 30, 2006. At December 31, 2005, the assets and liabilities of discontinued operations were segregated on the consolidated balance sheet and were comprised of current assets of $2 million, other long-term assets of $9 million and long-term liabilities of $14 million.

Note 9. Acquisitions and Disposition

Acquisitions

On April 1, 2006, MEHC received, as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. The acquisition was accounted for as a transaction between entities under common control. As such, the assets and liabilities of the projects acquired were recorded at historical cost on the acquisition date for a net book value of approximately $76 million. MEHC subsequently contributed these ownership interests to EME.

EDISON INTERNATIONAL

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On January 5, 2006, EME completed a transaction with Cielo Wildorado, G.P., LLC and Cielo Capital, L.P. to acquire a 99.9% interest in the Wildorado Wind Project, which owns a 161-MW wind farm located in the panhandle of northern Texas, referred to as the Wildorado wind project. The acquisition included all development rights, title and interest held by Cielo in the Wildorado wind project, except for a small minority stake in the project retained by Cielo. The total purchase price was $29 million. As of June 30, 2006, a cash payment of $18 million had been made towards the purchase price. Total project costs of the Wildorado wind project, excluding capitalized interest, are estimated to be approximately $270 million with commercial operations expected to begin in April 2007. The acquisition was accounted for utilizing the purchase method. The fair value of the Wildorado wind project was equal to the purchase price and as a result, the total purchase price was allocated to nonutility property in Edison International’s consolidated balance sheet.

Disposition

On March 7, 2006, EME completed the sale of a 25% ownership interest in the San Juan Mesa wind project to Citi Renewable Investments I LLC, a wholly owned subsidiary of Citicorp North America, Inc. Proceeds from the sale were $43 million. EME recorded a pre-tax gain on the sale of approximately $4 million during the first quarter of 2006.

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

INTRODUCTION

This Management’s Discussion and Analysis of Financial Condition and Results of Operation (MD&A) for the three- and six-month periods ended June 30, 2006 discusses material changes in the financial condition, results of operations and other developments of Edison International since December 31, 2005, and as compared to the three- and six-month periods ended June 30, 2005. This discussion presumes that the reader has read or has access to Edison International’s MD&A for the calendar year 2005 (the year-ended 2005 MD&A), which was included in Edison International’s 2005 annual report to shareholders and incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2005, 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 Southern California Edison Company (SCE) to recover its costs in a timely manner from its customers through regulated rates;

•

decisions and other actions by the California Public Utilities Commission (CPUC) 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 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 and environmental regulations 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 and output;

•

the 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;

•

supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which Mission Energy Holding Company’s (MEHC) generating units have access;

•

the cost and availability of coal, natural gas, fuel oil, nuclear fuel, and associated transportation;

•

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 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 activities in the complex and volatile markets in which MEHC and its subsidiaries participate;

•

general political, economic and business conditions;

•

weather conditions, natural disasters and other unforeseen events; and

•

changes in the fair value of investments and other assets.

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 for the year ended December 31, 2005. 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 and 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, Edison Mission Energy (EME) and Edison Capital. Edison Mission Group Inc. (EMG), a subsidiary of Edison International is the holding company for its principal wholly owned subsidiaries, MEHC and Edison Capital. MEHC is the holding company for its wholly owned subsidiary EME. Beginning in 2006, MEHC and Edison Capital are presented on a consolidated basis as EMG. This change has been made to reflect the integration of management and personnel at MEHC and Edison Capital. In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG, MEHC, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison International (parent) or parent company and MEHC (parent) mean Edison International or MEHC on a stand-alone basis, not consolidated with its subsidiaries.

This MD&A is presented in nine major sections. The MD&A begins with a discussion of current developments. Following is a company-by-company discussion of SCE, EMG, and Edison International (parent) which 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		38
Southern California Edison Company		40
Edison Mission Group Inc.		51
Edison International (Parent)		67
Results of Operations and Historical Cash Flow Analysis		69
Acquisitions and Dispositions		78
New Accounting Pronouncements		78
Commitments, Guarantees and Indemnities		79
Other Developments		80

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 since year-end December 31, 2005. This section is not intended to be an all-inclusive list of all current developments related to each principal business segment. Further details of each current development discussed below can be found in the specific principal business segment’s section of this MD&A, along with discussions of liquidity, market risk exposures, and other matters as relevant to each principal business segment.

SCE: CURRENT DEVELOPMENTS

2006 General Rate Case Proceeding

On May 11, 2006, the CPUC issued its final decision authorizing an increase of $274 million over SCE’s 2005 base rate revenue, retroactive to January 12, 2006. The CPUC also authorized increases of $74 million in 2007 and $104 million in 2008. See “SCE: Regulatory Matters—Current Regulatory Developments—2006 General Rate Case Proceeding” for further discussion.

2006 FERC Rate Case

On July 6, 2006, the Federal Energy Regulatory Commission (FERC) approved a settlement that set a revenue requirement of $312 million, which increases SCE’s revenue requirement by $26 million over current base transmission rates. See “SCE: Regulatory Matters—Current Regulatory Developments—2006 FERC Rate Case” for further discussion.

Mohave Generating Station and Related Proceedings

EMG: CURRENT DEVELOPMENTS

MEHC: Business Development

Wind Projects

EME has undertaken a number of activities with respect to new wind projects, including:

•

Completion of the purchase of development rights for the Wildorado wind project for $29 million. This project started construction on April 24, 2006. Project completion is scheduled for April 2007, with total construction costs estimated to be $270 million. Upon completion, power from the project will be sold under a twenty-year power purchase agreement to Southwestern Public Service.

•

Securing a supply of 285 turbines for 538 megawatts (MW) of new wind projects which are expected to be developed and constructed by the end of 2007.

•

Advancing development of a number of wind projects, including four projects totaling 181 MW that have been approved for investment, subject to completion of specific contractual or permitting arrangements.

In addition, Edison Capital transferred its ownership interests in a 192-MW portfolio of wind projects located in Iowa and Minnesota to EME (EME’s share is 176 MW). Edison Capital declared a dividend of the common stock of the companies owning the portfolio and project to EMG, which contributed the shares to MEHC. MEHC in turn contributed the shares to EME.

Thermal Projects

EME has continued to develop two 500 MW natural gas-fired peaker projects in Southern California. SCE has announced a request for offers from new generation resources. EME intends to respond to the request for offers.

In June 2006, subsidiaries of EME and BP America Inc. formed Carson Hydrogen Power LLC for the development of a power project to be located in Carson, California. Carson Hydrogen is conducting engineering studies for this industrial gasification project that will integrate proven gasification, power generation and enhanced oil recovery technologies. In June 2006, the project submitted an application to the United States Department of Energy (DOE) to qualify for gasification tax credits under the Energy Policy Act of 2005. Funding of tax credits is limited and, accordingly, there is no assurance that the project will be allocated tax credits. A decision is not expected until the end of 2006.

MEHC: Financing Activities

On June 6, 2006, EME completed a private offering of $500 million of its 7.50% senior notes due 2013 and $500 million of its 7.75% senior notes due 2016. The proceeds of the offering were used, together with cash on hand, to purchase substantially all of EME’s outstanding 10% senior notes due 2008 and 9.875% senior notes due 2011. In connection with the repayment, EME recorded a $143 million loss on early extinguishment of debt in the second quarter of 2006.

On June 15, 2006, EME entered into a new credit agreement providing for $500 million in revolving loan and letter of credit capacity to be used to repay existing debt and/or to provide liquidity and credit support for the hedging and trading activities of EME and its subsidiaries. The new credit agreement replaces EME’s $98 million credit agreement.

MEHC: Lakeland Project

EME previously owned a 220-MW power plant located in the United Kingdom, referred to as the Lakeland project. An administrative receiver was appointed in 2002 as a result of default by its counterparty, a subsidiary of TXU Europe Group plc and the project company was subsequently placed in liquidation. In response to its claim against the TXU subsidiary for damages resulting from the termination of the power sales agreement, the Lakeland project received a settlement of £116 million (approximately $217 million). EME is entitled to receive the amount of the settlement remaining after payment of creditor claims. As creditor claims have been settled, EME has received to date payments of £13 million (approximately $24 million) in April 2005, £61 million (approximately $106 million) in the first quarter of 2006, and £9 million (approximately $16 million) in April 2006. The after-tax income attributable to the Lakeland project was $10 million and $24 million for the second quarters of 2006 and 2005, respectively, and $83 million and $24 million for the six months ended June 30, 2006 and 2005, respectively. Beginning in 2002, EME reported the Lakeland project among discontinued operations and accounts for its ownership of Lakeland Power on the cost method, with earnings being recognized as cash is distributed from the project.

MEHC: Homer City Transformer Failure

On January 29, 2006, the main power transformer on Unit 3 of the Homer City facilities failed resulting in a suspension of operations at this unit. Homer City secured a replacement transformer and Unit 3 returned to service on May 5, 2006. Homer City has adjusted its previously planned outage schedules for Unit 3 and the other Homer City units in order to minimize to the extent practicable overall outage activities for all units through the first half of 2007. Taking into consideration the impact of the outage, generation for the year is currently expected to be approximately 13 terawatt hours (TWh). The actual financial impact and generation levels in 2006 will depend on the effect of market conditions upon the dispatch of the plant and on prevailing power prices during the balance of the year.

The main transformer failure will result in claims under Homer City’s property and business interruption insurance policies. At June 30, 2006, Homer City recorded a $17 million receivable related to these claims. Resolution of the claims is subject to a number of uncertainties, including computations of the lost profit during the outage period.

SOUTHERN CALIFORNIA EDISON COMPANY

SCE: LIQUIDITY

Overview

As of June 30, 2006, SCE had cash and equivalents of $90 million ($78 million of which was held by SCE’s consolidated Variable Interest Entities). As of June 30, 2006, long-term debt, including current maturities of long-term debt, was $5.3 billion. In December 2005, SCE replaced its $1.25 billion credit facility with a $1.7 billion five-year senior secured credit facility. The security pledged (first and refunding mortgage bonds) for the new facility can be removed at SCE’s discretion. If SCE chooses to remove the security, the credit facility’s pricing will change to an unsecured basis per the terms of the credit facility agreement. As of June 30, 2006, SCE’s credit facility supported $236 million in letters of credit and $518 million of commercial paper outstanding, leaving $946 million available under the credit facility.

SCE’s estimated cash outflows during the twelve-month period following June 30, 2006 consist of:

•

Debt maturities of approximately $247 million of rate reduction notes that have a separate nonbypassable recovery mechanism approved by state legislation and CPUC decisions;

•

Projected capital expenditures primarily to replace and expand distribution and transmission infrastructure and construct generation assets;

•

Dividend payments to SCE’s parent company. SCE made dividend payments to Edison International of $71 million on January 16, 2006, and $60 million on both April 28, 2006 and July 24, 2006;

•

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, including power-procurement, through cash and equivalents on hand, operating cash flows and short-term borrowings, when necessary. Projected capital expenditures are expected to be financed through operating cash flows and the issuance of short-term and long-term debt and preferred equity.

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

Credit Ratings

At June 30, 2006, SCE’s credit rating on long-term senior secured debt from Standard & Poor’s Rating Services and Moody’s Investors Service were BBB+ and A3, respectively. At June 30, 2006, SCE’s short-term (commercial paper) credit ratings from Standard & Poor’s and Moody’s were A-2 and P-2, respectively.

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, 2006, SCE’s 13-month weighted-average common equity component of total capitalization was 49%. At June 30, 2006, SCE had the capacity to pay $152 million in additional dividends based on the 13-month weighted-average method. Based on recorded June 30, 2006 balances, SCE’s common equity to total capitalization ratio, for rate-making purposes, was 49%. SCE had the capacity to pay $156 million of additional dividends to Edison International based on June 30, 2006 recorded balances.

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, 2006, SCE’s debt to total capitalization ratio was 0.47 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 and changes in market prices relative to contractual commitments, and other factors. At June 30, 2006, SCE had a net deposit of $183 million (consisting of $106 million in cash and reflected in “Margin and collateral deposits” on the balance sheet and $77 million in letters of credit) with a broker. In addition, SCE has deposited $179 million (consisting of $20 million in cash and reflected in “Margin and collateral deposits” on the balance sheet and $159 million in letters of credit) with other brokers and counterparties. Cash deposits with brokers and counterparties earn interest at various rates.

Margin and collateral deposits in support of power contracts and trading activities fluctuate with changes in market prices. Future margin and collateral requirements may be higher or lower than the margin collateral requirements as of June 30, 2006, based on future market prices and volumes of contractual and trading activity.

SCE: REGULATORY MATTERS

Current Regulatory Developments

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

Impact of Regulatory Matters on Customer Rates

SCE is concerned about high customer rates, which were a contributing factor that led to the deregulation of the electric services industry during the mid-1990s. At January 1, 2005, SCE’s system average rate for bundled customers was 12.2¢-per-kilowatt-hour. As of December 31, 2005, the system average rate was 12.6¢-per-kilowatt-hour. On January 1, 2006, SCE implemented a rate change that resulted in a system average rate of 13.7¢-per-kilowatt-hour. Of the 1.1¢ rate increase, 1¢ was due to the implementation of the California Department of Water Resources’ (CDWR) 2006 revenue requirement approved by the CPUC on December 1, 2005.

SCE implemented another rate change on February 4, 2006. As a result, SCE’s system average rate increased to 14.3¢-per-kilowatt-hour. The rate increase was due to a 1.2¢ increase resulting from the implementation of SCE’s 2006 Energy Resource Recovery Account (ERRA) forecast discussed below, partially offset by a decrease of 0.7¢ due to spreading of the revenue requirement over a larger customer base resulting from forecast sales growth. In addition, the rate change includes authorized increases in funding for energy efficiency programs.

As of June 4, 2006, SCE’s system average rate was 14.5¢-per-kilowatt-hour after increases associated with demand response program funding and FERC transmission-related rates. Except for residential rates, on August 1, 2006, SCE implemented in rates the 2006 General Rate Case (GRC) decision and modified the FERC-jurisdictional base transmission-related rates for the revised revenue requirement approved in the settlement discussed below. To mitigate the impact of further rate increases on residential customers during a period of record heat conditions in Southern California, on July 26, 2006, the CPUC granted SCE’s request to defer the residential rate increase to November 1, 2006. On July 27, 2006, SCE filed an advice letter with the CPUC seeking approval of the mechanism in which SCE will collect the authorized revenue earned during this three-month deferral period. SCE’s current system average rate, as of August 1, 2006, is approximately 14.7¢-per-kWh.

2006 General Rate Case Proceeding

On December 21, 2004, SCE filed its application for a 2006 GRC and subsequently revised its requested 2006 base rate revenue requirement to $3.96 billion, an increase of $465 million over SCE’s 2005 base rate revenue.

When a one-time credit of $140 million from an existing balancing account overcollection was applied, SCE’s requested increase was $325 million. SCE also proposed revised base rate revenue increases of $108 million for 2007 and $113 million for 2008.

During the second quarter of 2006, SCE implemented the 2006 GRC decision and resolved an outstanding regulatory issue which resulted in a pre-tax benefit of approximately $175 million. The implementation of the 2006 GRC decision retroactive to January 12, 2006 mainly resulted in revenue of $50 million related to the revenue requirement for the period January 12, 2006 through May 31, 2006, partially offset by the implementation of the new depreciation rates resulting in increased depreciation expense of approximately $25 million for the period January 12, 2006 through May 31, 2006. In addition, there was a favorable resolution of a one-time issue related to a portion of revenue collected during the 2001–2003 period for state income taxes. SCE was able to determine through the 2006 GRC decision and other regulatory proceedings that the level of revenue collected during that period was appropriate, and as a result recorded a pre-tax gain of $135 million (reflected in the caption “provisions for regulatory adjustments clauses—net” on the income statement). See “SCE: Regulatory Matters—Impact of Regulatory Matters on Customer Rates” for further discussion.

2007 Cost of Capital Proceeding

On March 27, 2006, SCE initiated proceedings requesting the CPUC to waive the requirement that SCE file a 2007 cost of capital application and instead file its next such application in 2007 for year 2008. If SCE’s waiver application is granted, SCE’s authorized capital structure, return on common equity of 11.6% and overall rate of return on capital of 8.77% will not change for 2007. On July 14, 2006, the CPUC issued a proposed decision granting SCE’s waiver application. SCE anticipates a final CPUC decision on its waiver application by the third quarter of 2006.

2006 FERC Rate Case

SCE’s electric transmission revenue and wholesale and retail transmission rates are subject to authorization by the FERC. On November 10, 2005, SCE filed proposed revisions to the 2006 base transmission rates, which would increase SCE’s revenue requirement by $65 million, or 23%, over current base transmission rates and requested an effective date of January 10, 2006. On May 30, 2006, the FERC authorized an effective date for the new rates of June 4, 2006. On July 6, 2006, the FERC approved a settlement that set a revenue requirement of $312 million, which increases SCE’s revenue requirement by $26 million over current base transmission rates. SCE’s original effective date request was not resolved by the settlement. On July 31, 2006, the FERC denied SCE’s request for rehearing on the effective date issue. SCE is currently considering its options to appeal. See “SCE: Regulatory Matters—Impact of Regulatory Matters on Customer Rates.”

Energy Resource Recovery Account Proceedings

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2005 MD&A, the Energy Resource Recovery Account (ERRA) is the balancing account mechanism to track and recover SCE’s fuel and procurement-related costs. If the ERRA balancing account incurs an overcollection or undercollection in excess of 4% of SCE’s prior year’s generation revenue, the CPUC has established a “trigger” mechanism, whereby SCE must file an application in which it can request an emergency rate adjustment if the ERRA overcollection or undercollection exceeds 5% of SCE’s prior year’s generation revenue. In February 2006, the ERRA was undercollected by $206 million, which

was 5.16% of SCE’s prior year’s generation revenue. On April 14, 2006, SCE filed an ERRA trigger application. In its application, SCE forecast that the ERRA undercollection would be eliminated by the end of June 2006 as a result of the implementation of the CPUC’s January 2005 ERRA decision (see “Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings—ERRA Forecast” in the year-ended 2005 MD&A for further discussion) and no further rate action by the CPUC will be necessary. On June 29, 2006, the CPUC issued a decision authorizing SCE to maintain its currently authorized ERRA rates to reduce its undercollected balance. As of June 30, 2006, the ERRA was undercollected by $27 million, which was 0.68% of SCE’s prior year’s generation revenue.

Resource Adequacy Requirements

Under the CPUC’s resource adequacy framework, all load-serving entities in California have an obligation to procure sufficient resources to meet their expected customers’ needs on a system-wide basis with a 15–17% reserve level. In addition, on June 6, 2006, the CPUC adopted local resource adequacy requirements.

Effective February 16, 2006, SCE was required to demonstrate that it had procured sufficient resources to meet 90% of its June–September 2006 system resource adequacy requirement. SCE believes that it has met this requirement. Effective in May 2006, SCE was required to demonstrate that it has met 100% of its system resource adequacy requirement one month in advance of expected need. A month-ahead showing demonstrating that SCE has procured 100% of its system resource adequacy requirement will be required every month thereafter. The system resource adequacy requirements provide for penalties of 150% of the cost of new monthly capacity for failing to meet the system resource adequacy requirements in 2006, and a 300% penalty in 2007 and beyond. SCE believes it has procured sufficient resources to meet its expected system resource adequacy requirements for 2006.

Under the local resource adequacy requirements, SCE must demonstrate that it has procured 100% of its requirement within defined local areas. The CPUC is currently in the process of determining the amount of local capacity SCE will need to meet the requirement. SCE must make a preliminary showing regarding its local resource adequacy in September 2006, and a final compliance showing for 2007, by October 31, 2006. The local resource adequacy requirements provide for penalties of 100% of the cost of new monthly capacity for failing to meet the local resource adequacy requirements. SCE believes it has procured sufficient resources to meet its expected local resource adequacy requirements for 2006 and 2007.

Procurement of Renewable Resources

Request for Offers from Renewable and New Generation Resources

SCE periodically conducts competitive solicitations for natural gas and wholesale electric energy supplies. On July 14, 2006, SCE requested proposals for power purchase contracts from renewable energy resources, with bids due in September 2006. The contract lengths will be 10, 15 or 20 years. On July 21, 2006, SCE announced that it will request proposals for long-term power purchase contracts with terms of up to 10 years from new generating facilities that could come online within the next several years. SCE anticipates issuing the request for proposals in September 2006 and soliciting up to 1,500 MW of new generation. In the 3rd quarter of 2006, SCE expects to solicit proposals for five-year contracts from all sources.

Mohave Generating Station and Related Proceedings

On June 19, 2006, SCE announced that it had decided not to move forward with its efforts to return Mohave to service. SCE’s decision was not based on any one factor, but resulted from the conclusion that in light of all the significant unresolved challenges related to returning the plant to service, the plant could not be returned to service in sufficient time to render the necessary investments cost-effective for SCE’s customers. Two of the Mohave co-owners, Nevada Power Company and the Los Angeles Department of Water & Power, announced that they had reached this same conclusion, while the fourth co-owner, Salt River Project Agricultural Improvement and Power District, has advised SCE that it is still assessing its interest in putting together a successor owner group to allow continued coal operations. All of the co-owners have agreed to work together to evaluate options for disposition of the plant, which conceivably could include, among other potential options, sale of the plant “as is” to a power plant operator, decommissioning and sale to a developer, and decommissioning and apportionment of the land among the owners. At this time, SCE continues to work with the water and coal suppliers to the plant to determine if more clarity around the provision of such services can be provided to any potential acquirer.

the second workforce reduction will depend on the success of this effort. Due to this uncertainty, SCE management is unable to predict the amount of termination costs, if any, of the second workforce reduction at this time. However, SCE management believes these costs and other costs associated with the cessation of operations (excluding decommissioning) will range from zero to $14 million (SCE’s share). These additional costs will be recorded and deferred in the Mohave balancing account in late 2006. SCE expects to recover amounts in this balancing account in future rate-making proceedings.

As of June 30, 2006, SCE had a Mohave regulatory asset of approximately $77 million representing unamortized capital costs, and a Mohave regulatory liability for revenue collected for future removal costs of approximately $21 million. Based on the 2006 GRC decision, SCE is allowed to continue to earn its authorized rate of return on the Mohave investment and receive rate recovery for amortization, costs of removal, and operating and maintenance expenses, subject to balancing account treatment, during the three-year 2006 rate case cycle. SCE expects to file a notification with the CPUC regarding the status of Mohave by the end of third quarter 2006, and the CPUC may institute an investigation to determine whether to reduce SCE’s rates. At this time, SCE does not anticipate that the CPUC will order a rate reduction. In the past, the CPUC has allowed full recovery of investment for similarly situated plants. However, in a December 2004 decision, the CPUC noted that SCE would not be allowed to recover any unamortized plant balances if SCE could not demonstrate that it took all steps to preserve the “Mohave-open” alternative. SCE believes that it will be able to demonstrate that SCE did everything reasonably possible to return Mohave to service and that its unamortized costs are probable of future rate recovery. However, SCE cannot predict the outcome of any future CPUC action.

San Onofre Nuclear Generating Station Steam Generators

As discussed under the heading “Regulatory Matters—Current Regulatory Developments—San Onofre Nuclear Generating Station Steam Generators” in the year-ended 2005 MD&A, on December 15, 2005, the CPUC issued a final decision on SCE’s application for replacement of SCE’s San Onofre Nuclear Generating Station (San Onofre) Units 2 and 3 steam generators. SCE provided its acceptance of the decision to the CPUC on March 6, 2006. On June 15, 2006, the CPUC granted a limited rehearing of the decision in response to an Application for Rehearing filed by The Utility Reform Network and California Earth Corps challenging the cost effectiveness of the steam generator replacement project. The limited rehearing is to focus on the appropriate calculation of the net present benefits of the steam generator replacement project.

The city of Anaheim opted out of the project and agreed to transfer its 3.16% share of San Onofre to SCE. In March 2006, SCE filed applications to the Nuclear Regulatory Commission (NRC) and the FERC requesting authority to transfer Anaheim’s share to SCE. Also, in March 2006, SCE filed an application with the CPUC requesting rate recovery for Anaheim’s share of San Onofre operating and decommissioning costs. In April 2006, the FERC granted SCE authority to transfer Anaheim’s share to SCE. The transfer of Anaheim’s share is contingent upon receipt of regulatory approvals.

On April 13, 2006, SCE and San Diego Gas & Electric Company (SDG&E) settled a dispute regarding SDG&E’s decision to opt out of steam generator replacement. As a result, on April 14, 2006, SDG&E applied to the CPUC to participate in the steam generator replacement and retain its 20% share of San Onofre contingent upon CPUC adoption of its application subject to certain conditions including, operating and maintenance expense balancing account and an 11.6% return on equity for SDG&E’s San Onofre capital investment. If the CPUC’s decision is not acceptable to SDG&E, it may file an application with the CPUC to opt out of steam generator replacement and have its ownership share of San Onofre reduced.

Palo Verde Nuclear Generating Station Steam Generators

SCE owns a 15.8% interest in the Palo Verde Nuclear Generating Station (Palo Verde). During 2003, the Palo Verde Unit 2 steam generators were replaced. During 2005, the Palo Verde Unit 1 steam generators were replaced. In addition, the Palo Verde owners have approved the manufacture and installation of steam generators in Unit 3. SCE expects that replacement steam generators will be installed in Unit 3 in 2008. SCE’s share of the

costs of manufacturing and installing all of the replacement steam generators at Palo Verde is estimated to be approximately $115 million. The CPUC approved the replacement costs for Unit 2 in the 2003 GRC. The final decision in the 2006 GRC proceeding authorized SCE to recover the replacement costs for Units 1 and 3.

FERC Refund Proceedings

As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—FERC Refund Proceedings” in the year-ended 2005 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. SCE is required to refund to customers 90% of any refunds actually 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 April 2006, SCE received a distribution on its allowed bankruptcy claim against one of the Enron debtors of approximately $29 million, and 196,245 shares of common stock of Portland General Electric Company with an aggregate value of approximately $5 million. In December 2005, the FERC approved a settlement agreement among SCE, Pacific Gas and Electric Company, SDG&E, several governmental entities and certain other parties, and Reliant Energy, Inc. and a number of its affiliates. In March 2006, SCE received an additional $61 million.

Holding Company Order Instituting Rulemaking

On October 27, 2005, the CPUC issued an order instituting rulemaking to allow the CPUC to re-examine the relationships of the major California energy utilities with their parent holding companies and nonregulated affiliates. On June 29, 2006, the CPUC issued an opinion amending the October 2005 order. The opinion elaborates the CPUC’s reasons for opening the order instituting rulemaking and invites comment on a number of perceived problems and potential solutions relating to the relationships between utilities, holding companies and nonregulated energy affiliates. The opinion also includes the CPUC staff proposals for revisions to the affiliate transaction rules and the utility executive salary reporting rules. The CPUC stated that it expects to issue draft rules for comment in the third quarter 2006. Edison International has filed a response, along with the other California utilities and their holding company parents, on August 7, 2006. The CPUC has stated that it intends to conclude this rulemaking in November 2006. Edison International cannot predict the outcome of this proceeding.

Investigations Regarding Performance Incentives Rewards

SCE has been conducting 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

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 for the years 1998, 1999 and 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. As a result of these findings, SCE accrued a $9 million charge in the caption “Other nonoperating deductions” on the income statement in 2004 for the potential refunds of rewards that have been received.

Employee Injury and Illness Reporting

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. Therefore, SCE accrued a $20 million charge in the caption “Other nonoperating deductions” on the income statement in 2004 for the potential refund of these rewards. SCE has also proposed to withdraw the pending rewards for the 2001–2003 time frames.

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. On February 28, 2005, SCE provided its final investigatory report to the CPUC concluding that the reliability reporting system is working as intended.

CPUC Investigation

reporting, and system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE.

Settlement Agreement with Duke Energy Trading and Marketing, L.L.C.

On May 10, 2006, SCE filed an application with the CPUC for approval of a settlement agreement between SCE and Duke Energy Trading and Marketing, L.L.C. (DETM) that resolves disputes arising from DETM’s termination of certain bilateral power supply contracts in early 2001. Under the settlement, DETM will make principal and interest payments to SCE of approximately $75 million, which SCE proposes will be refunded to ratepayers through the ERRA mechanism. The settlement, once approved, will also permit $58 million in liabilities that SCE had previously recorded with respect to the DETM terminated contracts to be reversed, which will result in an equivalent gain being recorded by SCE. SCE’s application to the CPUC requests that this gain not be refunded to ratepayers since these liabilities were not funded by ratepayers. The recorded liabilities consist of $40 million in cash collateral received from DETM in 2000 and $18 million in power purchase payments that SCE, in light of DETM’s termination of the bilateral contracts, withheld for energy delivered by DETM in January 2001. A decision on SCE’s application for approval of the settlement is not expected until the end of 2006 or early 2007. SCE cannot predict the outcome of this matter.

SCE: OTHER DEVELOPMENTS

Navajo Nation Litigation

In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and Corrupt Organizations statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentation 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, as well as a declaration that Peabody’s lease and contract rights to mine coal on Navajo Nation lands should be terminated. SCE joined Peabody’s motion to strike the Navajo Nation’s complaint. In addition,

SCE and other defendants filed motions to dismiss. The D.C. District Court denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District’s motion for its separate dismissal from the lawsuit.

The Court of Appeals for the Federal Circuit, acting on a suggestion filed by the Navajo Nation on remand from the Supreme Court’s March 4, 2003 decision held, in an October 24, 2003 decision that the Supreme Court’s decision was focused on three specific statutes or regulations and therefore did not address the question of whether a network of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the United States during the time period in question. On March 16, 2004, the Federal Circuit issued an order remanding the case against the Government to the Court of Federal Claims, which considered (1) whether the Navajo Nation previously waived its “network of other laws” argument and, (2) if not, whether the Navajo Nation can establish that the Government breached any fiduciary duties pursuant to such “network.” On December 20, 2005, the Court of Federal Claims issued its ruling and found that although there was no waiver, the Navajo Nation did not establish that a “network of other laws” created a judicially enforceable trust obligation. The Navajo Nation filed a notice of appeal from this ruling on February 14, 2006. The Navajo Nation’s opening brief was filed on June 7, 2006 and the Government filed its reply brief on July 20, 2006. No date for oral argument has been set.

Palo Verde Nuclear Generating Station Outage

Between December 2005 when Palo Verde Unit 1 returned to service from its refueling and steam generator replacement outage and March 21, 2006, Palo Verde Unit 1 operated at between 25% and 32% power level. The need to operate at a reduced power level was due to the vibration level in one of the unit’s shutdown cooling lines. On March 21, 2006, Arizona Public Service, the operating agent for Palo Verde Unit 1, decided to remove the unit from service completely. The vibration problem was resolved and Palo Verde Unit 1 was returned to service on July 7, 2006. Incremental replacement power costs are expected to be recovered through the ERRA rate-making mechanism.

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. See “SCE: Market Risk Exposures” in the year-ended 2005 MD&A for a complete discussion of SCE’s market risk exposures.

Commodity Price Risk

The following table summarizes the net fair values for outstanding physical and financial derivative investments used at SCE to mitigate its exposures to commodity price risk:


	June 30, 2006				December 31, 2005
In millions	Assets		Liabilities		Assets		Liabilities
Energy options and tolling arrangements	$	—	$	20	$	25	$	—
Forward physicals (power)		—		92		—		49
Gas options, swaps, and forward arrangements		—		132		105		—
Total	$	—	$	244	$	130	$	49

EDISON MISSION GROUP INC.

EMG has no business activities other than through its ownership interests in its subsidiaries, including MEHC (parent), EME, and Edison Capital. The following section includes discussion of liquidity, market risk exposures and other matters related to EMG’s principal subsidiaries.

EMG: LIQUIDITY

MEHC (parent)’s Liquidity

At June 30, 2006, MEHC had cash and cash equivalents of $16 million (excluding amounts held by EME and its subsidiaries). MEHC’s ability to honor its obligations under the senior secured notes is substantially dependent upon the receipt of dividends from EME and the receipt of tax-allocation payments from MEHC’s parent, Edison Mission Group, and ultimately Edison International. See “—EME’s Liquidity as a Holding Company— Intercompany Tax-Allocation Agreement.” Dividends to MEHC from EME are limited based on EME’s earnings and cash flow, terms of restrictions contained in EME’s corporate credit facility, business and tax considerations and restrictions imposed by applicable law.

Dividends to MEHC

In January 2006, EME made total dividend payments of $11.5 million to MEHC. In July 2006, EME made a dividend payment of $39 million to MEHC.

EME’s Liquidity

At June 30, 2006, EME and its subsidiaries had cash and cash equivalents and short-term investments of $1.6 billion and EME had available the full amount of borrowing capacity under its new $500 million corporate credit facility. EME’s consolidated debt at June 30, 2006 was $3.4 billion. In addition, EME’s subsidiaries had $4.4 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 29 years.

MEHC’s Financing Developments

During June 2006, EME replaced its $98 million credit agreement with a new credit agreement that provides for a $500 million senior secured revolving loan and letter of credit facility and matures on June 15, 2012 and completed a private offering of $500 million aggregate principal amount of its 7.50% senior notes due June 15, 2013 and $500 million aggregate principal amount of its 7.75% senior notes due June 15, 2016. EME will pay interest on the senior notes on June 15 and December 15 of each year, beginning on December 15, 2006. The senior notes are redeemable by EME at any time at a price equal to 100% of the principal amount of, plus accrued and unpaid interest and liquidated damages, if any, on, the senior notes plus a “make-whole” premium.

As security for its obligations under this credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects will be deposited. EME will be free to use these proceeds unless an event of default occurs under the credit facility.

EME used the net proceeds of the offering of the senior notes, together with cash on hand, to purchase $369 million in aggregate principal amount of its 10% senior notes due August 15, 2008 and $596 million in aggregate principal amount of its 9.875% senior notes due April 15, 2011, that were validly tendered pursuant to EME’s previously announced cash tender offer and consent solicitation. The net proceeds of the offering of the senior notes, together with cash on hand, were also used to pay related tender premiums, consent fees and accrued interest. EME recorded a $143 million loss on early extinguishment of debt during the second quarter of 2006.

MEHC’s Capital Expenditures

The estimated capital and construction expenditures of EME’s subsidiaries are $280 million in the remaining two quarters of 2006 and $493 million, $28 million and $25 million for 2007, 2008 and 2009, respectively. The nonenvironmental portion of these expenditures relates to the construction of the Wildorado wind project, purchases of turbines, upgrades to dust collection/mitigation systems and the coal handling system, ash removal improvements and various other projects. EME plans to finance these expenditures with existing subsidiary credit agreements, cash on hand or cash generated from operations. Included in the estimated expenditures are environmental expenditures of $4 million for the remaining two quarters of 2006, $12 million for 2007, $6 million for 2008, and $25 million for 2009. The environmental expenditures relate to environmental projects such as selective catalytic reduction system improvements at the Homer City facilities and projects at the Illinois plants.

MEHC’s Credit Ratings

Overview

Credit ratings for MEHC and its subsidiaries, EME, Midwest Generation and Edison Mission Marketing & Trading (EMMT), are as follows:


	Moody’s Rating	S&P Rating
MEHC	B2	B-
EME	B1	B+
Midwest Generation:
First priority senior secured rating	Ba2	BB-
Second priority senior secured rating	Ba3	B
EMMT	Not Rated	B+

MEHC 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. MEHC 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.

MEHC does not have any “rating triggers” contained in subsidiary financings that would result in it or EME 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 Standard & Poor’s 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, 2006. EME Homer City continues to be in compliance with the terms of the consent; however, the consent is revocable by the sale-leaseback owner participant at any time. The sale-leaseback owner participant has not indicated that it intends to

revoke the consent; however, there can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between EMMT and EME Homer City that had been entered into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See “EMG: Market Risk Exposures—MEHC’s Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities.”

MEHC’s Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into contracts in support of EME’s price risk management 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. Because the credit ratings of EMMT and EME are below investment grade, EME has historically provided collateral in the form of cash and letters of credit for the benefit of counterparties related to accounts payable and unrealized losses in connection with these price risk management and trading activities. At June 30, 2006, EMMT had deposited $289 million in cash with brokers in margin accounts in support of futures contracts and had deposited $46 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $7 million in support of commodity contracts at June 30, 2006.

Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2006, if wholesale energy prices increase further or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2006 could increase by no more than approximately $310 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, 2006, Midwest Generation had borrowed $200 million under its credit facility which was partially used to finance margin advances to EMMT of $142 million. In addition, EME has cash on hand and a $500 million working capital facility to provide credit support to subsidiaries. See “—MEHC’s Financing Developments” and “—EME’s Liquidity as a Holding Company” for further discussion.

EME’s Liquidity as a Holding Company

Overview

At June 30, 2006, EME had corporate cash and cash equivalents and short-term investments of $1.3 billion to meet liquidity needs. See “—EME’s Liquidity.” Cash distributions from EME’s subsidiaries and partnership investments and unused capacity under its corporate credit facility represent EME’s major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME’s subsidiaries may be affected by many factors beyond its control. See “—MEHC’s Dividend Restrictions in Major Financings.”

EME Homer City Interim Funding Arrangements

During March 2006, EME, through its subsidiary, Edison Mission Finance, advanced funds in the amount of $9 million to EME Homer City under the subordinated revolving loan agreement in place between Edison Mission Finance and EME Homer City. The funds were used to assist EME Homer City with a cash shortfall resulting from reduced revenue and higher maintenance expenses caused by the Unit 3 outage. For similar reasons, at the end of March 2006 and April 2006, EMMT made advance payments to EME Homer City in the amounts of $43.5 million and $20 million, respectively, against future deliveries of power to it under its trading arrangements with EME Homer City. The proceeds of the subordinated loans were deposited in EME Homer City’s operating account and the prepayment by EMMT was deposited in EME Homer City’s revenue account. It is currently anticipated that a substantial portion of the advance payments will be applied against amounts invoiced to EMMT within the next 12 months.

Historical Distributions Received By EME

The following table is presented as an aid in understanding the cash flow of EME’s continuing operations and its various subsidiary holding companies which depend on distributions from subsidiaries and affiliates to fund general and administrative costs and debt service costs of recourse debt.


In millions	Six Months Ended June 30,	2006		2005
Distributions from Consolidated Operating Projects:
Edison Mission Midwest Holdings (Illinois plants)		$	380	$	171
EME Homer City Generation L.P. (Homer City facilities)			—		41
Holding companies of other consolidated operating projects			3		—

Distributions from Unconsolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 Projects)⁽¹⁾			41		29
Sunrise Power Company			7		5
Holding company for Doga project			—		17
Holding companies for Westside projects			6		6
Holding companies of other unconsolidated operating projects			1		4
Total Distributions		$	438	$	273

(1)

The Big 4 projects consist of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project. Distributions reflect the amount received by EME after debt service payments by Edison Mission Energy Funding Corp.

Intercompany Tax-Allocation Agreement

MEHC (parent) and EME are included in the consolidated federal and combined state income tax returns of Edison International and are eligible to participate in tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of MEHC (parent) and EME to receive and the amount of and timing of tax-allocation payments are dependent on the inclusion of MEHC (parent) and EME, respectively, in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of MEHC (parent), EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. MEHC (parent) and EME receive tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize MEHC (parent)’s or EME’s consolidated tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on the application of the factors cited above, MEHC (parent) and EME are obligated during periods they generate taxable income to make payments under the tax-allocation agreements. EME made tax-allocation payments to Edison International of $162 million during the first six months of 2006. MEHC (parent) received tax-allocation payments from Edison International of $16 million during the first six months of 2006. MEHC (parent) and EME received tax-allocation payments from Edison International of $59 million and $3 million, respectively, during the first six months of 2005.

MEHC’s 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 MEHC and EME’s Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of MEHC and EME’s principal subsidiaries required by financing arrangements for the twelve months ended June 30, 2006:


Subsidiary	Financial Ratio	Covenant	Actual
MEHC	Interest Coverage Ratio	Greater than 2.0 to 1	2.97 to 1
Midwest Generation, LLC (Illinois plants)	Interest Coverage Ratio	Greater than or equal to 1.40 to 1	6.45 to 1
Midwest Generation, LLC (Illinois plants)	Secured Leverage Ratio	Less than or equal to 7.25 to 1	2.00 to 1
EME Homer City Generation L.P. (Homer City facilities)	Senior Rent Service Coverage Ratio	Greater than 1.7 to 1	2.26 to 1⁽¹⁾

(1)

The senior rent service coverage ratio is determined by dividing net operating cash flow by senior rent. Net operating cash flow represents revenue less operating expenses as defined in the sale-leaseback documents. Revenue during the twelve months ended June 30, 2006 includes $43.5 million and $20 million from an advance payment from EMMT on March 31, 2006 and April 30, 2006, respectively, against future deliveries of power to it under its trading arrangements with EME Homer City.

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 “MEHC: Liquidity—Dividend Restrictions in Major Financings” in the year-ended 2005 MD&A.

Edison Capital’s Liquidity

Edison Capital’s main sources of liquidity are tax-allocation payments from Edison International, distributions from its global infrastructure fund investments and lease rents. During the first half of 2006, Edison Capital received $64 million in tax-allocation payments and $15 million in global infrastructure fund distributions. As of June 30, 2006, Edison Capital had unrestricted cash and cash equivalents of $341 million and long-term debt, including current maturities, of $189 million.

Credit Ratings

At June 30, 2006, Edison Capital’s long-term debt had credit ratings of Ba1 and BB+ from Moody’s Investors Service and Standard & Poor’s, respectively.

Dividend Restrictions and Debt Covenants

Edison Capital’s ability to make dividend payments to Edison International (parent) is restricted by debt covenants (see “Edison International (Parent): Liquidity” for further discussion). During the first half of 2006, Edison Capital complied with its debt covenants.

Intercompany Tax-Allocation Payments

Edison Capital is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in tax-allocation payments with Edison International and other subsidiaries of Edison International. See “EMG: Liquidity—EME’s Liquidity as a Holding Company—Intercompany Tax-Allocation Agreement” for additional information regarding these arrangements. The amount received is net of payments made to Edison International.

Edison Capital’s Federal Income Taxes

Edison International received Revenue Agent Reports from the Internal Revenue Service (IRS) in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 to 1996 and 1997 to 1999 tax years, respectively. Among the issues raised were items related to Edison Capital. See “Other Developments—Federal and State Income Taxes” for further discussion of these matters.

EMG: MARKET RISK EXPOSURES

Introduction

EME’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.

MEHC’s Commodity Price Risk

General Overview

EME’s revenue and results of operations of its merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary services, emission allowances or credits, coal, natural gas and fuel oil, and associated transportation costs in the market areas where EME’s merchant plants are located. Among the factors that influence the price of energy, capacity and ancillary services in these markets are:

•

prevailing market prices for coal, natural gas and fuel oil, and associated transportation;

•

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/or technologies that may be able to produce electricity at a lower cost than EME’s generating facilities and/or increased access by competitors to EME’s markets as a result of transmission upgrades;

•

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

•

the market structure rules established for each market area and regulatory developments affecting the market areas, including any price limitations and other mechanisms adopted to address volatility or illiquidity in these markets or the physical stability of the system;

•

the cost and availability of emission credits or allowances;

•

the availability, reliability and operation of competing power generation facilities, including nuclear generating plants, where applicable, and the extended operation of such facilities beyond their presently expected dates of decommissioning;

•

weather conditions prevailing in surrounding areas from time to time; and

•

changes in the demand for electricity or in patterns of electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.

A discussion of commodity price risk for the Illinois plants and the Homer City facilities is set forth below.

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 from unit to unit.

EME uses “value at risk” to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois plants, its Homer City facilities, and its trading positions. The use of value at risk 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 over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, EME supplements this approach 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 merchant portfolio risk through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its merchant portfolio, 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. Hedge transactions are also entered into as forward sales to utilities and power marketing companies.

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 sales 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 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 “—MEHC’s 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, negotiated by EMMT with customers through a combination of bilateral agreements, forward energy sales and spot market sales. As discussed further below, power generated at the Illinois plants is generally sold into the PJM Interconnection, LLC (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 in PJM, and may also be entered into at other trading hubs, including the AEP/Dayton Hub in PJM and the Cinergy Hub in the Midwest Independent Transmission System Operator (MISO). These trading hubs have been the most liquid locations for hedging purposes. However, hedging transactions which settle at points other than the Northern Illinois Hub are subject to the possibility of basis risk. 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 2006 and 2005.


	24-Hour Northern Illinois Hub Historical Energy Prices⁽¹⁾
	2006		2005
January	$	42.27	$	38.36
February		42.66		34.92
March		42.50		45.75
April		43.16		38.98
May		39.96		33.60
June		34.80		42.45
Six-Month Average	$	40.89	$	39.01

(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, 2006:


	24-Hour Northern Illinois Hub Forward Energy Prices⁽¹⁾
2006
July	$	43.77
August		47.64
September		36.86
October		33.17
November		38.21
December		50.37

2007 Calendar “strip”⁽²⁾	$	45.49
2008 Calendar “strip”⁽²⁾	$	45.10

(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 (primarily based on prices at the Northern Illinois Hub) at June 30, 2006:


	2006	2007	2008
Megawatt hours	10,039,760	16,237,200	3,072,000
Average price/MWh⁽¹⁾	$ 47.61	$ 48.25	$ 66.13

(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, 2006 is not directly comparable to the 24-hour Northern Illinois Hub prices set forth above.

Subsequent to June 30, 2006, EMMT entered into an agreement with a third party to hedge the price risk for 500 MW of on-peak power from the Illinois plants for 2007, 2008 and 2009 (using the Northern Illinois Hub as a reference point). Under the terms of the agreement, EME has guaranteed the obligation of EMMT, but neither EME nor EMMT is required to post margin, provide liens on property or provide other collateral to support the obligations under the agreement.

Energy Price Risk Affecting Sales from the Homer City Facilities

Electric power generated at the Homer City facilities is generally sold into the PJM market. PJM has a short-term market, which establishes an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and New York Independent System Operator 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 during the first six months of 2006 and 2005:


	Historical Energy Prices⁽¹⁾ 24-Hour PJM
	Homer City				West Hub
	2006		2005		2006		2005
January	$	48.67	$	45.82	$	54.57	$	49.53
February		49.54		39.40		56.39		42.05
March		53.26		47.42		58.30		49.97
April		48.50		44.27		49.92		44.55
May		44.71		43.67		48.55		43.64
June		38.78		46.63		45.78		53.72
Six-Month Average	$	47.24	$	44.54	$	52.25	$	47.24

(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, 2006:


	24-Hour PJM West Hub Forward Energy Prices⁽¹⁾
2006
July	$	59.69
August		63.18
September		49.56
October		48.23
November		53.15
December		65.25

2007 Calendar “strip”⁽²⁾	$	63.80
2008 Calendar “strip”⁽²⁾	$	62.58

(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 Homer City’s hedge position at June 30, 2006:


	2006	2007	2008
Megawatt hours	4,415,900	7,590,000	2,371,200
Average price/MWh⁽¹⁾	$ 54.07	$ 64.35	$ 66.01

(1)

The average price/MWh for 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.

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 at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case of the Homer City facilities and for a settlement point at the Northern Illinois Hub in the case of the Illinois plants. EME’s price risk management 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 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. 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, 2006, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub (EME Homer City’s primary trading hub) by an average of 10%, compared to 6% during the six months ended June 30, 2005. The monthly average difference during the twelve months ended June 30, 2006 ranged from 3% to 20%, which occurred in August 2005. 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.

By entering into cash settled futures contracts and forward contracts using the PJM West Hub and the Northern Illinois 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 has purchased 7.8 TWh of financial transmission rights and basis swaps in PJM for Homer City during the period July 1, 2006 through May 31, 2007, and may continue to purchase financial transmission rights and basis swaps in the future. 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 price risk management activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk.

Coal Price and Transportation Risk

The Illinois plants use approximately 18 million to 20 million tons of coal annually, primarily obtained from the Southern Powder River Basin of Wyoming. In addition, the Homer City facilities use approximately 5 million to 6 million tons of coal annually, obtained primarily from mines located near the facilities in Pennsylvania. Coal purchases are made under a variety of supply agreements with terms ranging from one year to eight years. The following table summarizes the percent of expected coal requirements for the next five years that were under contract at June 30, 2006.


	Percent of Coal Requirements Under Contract
	2006⁽¹⁾		2007		2008		2009		2010
Illinois plants	108	%	95	%	33	%	33	%	33	%
Homer City facilities	99	%	97	%	39	%	15	%	0	%

(1)

The percentage in 2006 is calculated based on coal supply and expected generation requirements for a full year.

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which is related to the price of coal purchased for the Homer City facilities, increased considerably during 2005. The price of NAPP coal (with 13,000 British Thermal units (Btu) per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) fluctuated between $44 per ton and $57 per ton during 2005, with a price of $45 per ton at December 30, 2005, as reported by the Energy Information Administration. The 2005 overall increase in the NAPP coal price was largely attributed to greater demand from domestic power producers and increased international shipments of coal to Asia. During the first six months of 2006, the price of NAPP coal decreased to $37.50 per ton at June 23, 2006, as reported by the Energy Information Administration, due to

the combined effects of a mild winter, easing natural gas prices and improving eastern stockpiles. Prices of Powder River Basin (PRB) coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content), which is purchased for the Illinois plants, significantly increased in 2005 due to the curtailment of coal shipments during 2005 due to increased PRB coal demand from other regions (east), rail constraints (discussed below), higher oil and natural gas prices and higher prices for SO2 allowances. On June 23, 2006, the Energy Information Administration reported the price of PRB coal to be $12.25 per ton, which compares to 2005 prices that ranged from $6.20 per ton to $18.48 per ton. The price of PRB coal decreased during the first six months of 2006 from 2005 year-end prices due to easing natural gas prices, lower prices for SO2 allowances and mild weather during the first six months of 2006.

After two derailments in May 2005, the railroads that bring coal from the PRB mines to the Illinois plants discovered significant problems with the joint-rail line that serves the PRB mines. Repairs to the joint-rail line are expected to continue through most of 2006. Even though some restrictions in coal shipments have occurred while repairs are being completed, EME expects to continue receiving a sufficient amount of coal to generate power based on communications with the railroad companies.

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 NOx SIP Call requirement. Under these programs, 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. 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.

The price of emission allowances, particularly SO2 allowances issued through the federal Acid Rain Program, decreased during the first half of 2006 from 2005 year-end prices. The average price of purchased SO2 allowances decreased to $899 per ton during the six months ended June 30, 2006 from $1,219 per ton during 2005. The decrease in the price of SO2 allowances during the six months ended June 30, 2006 from 2005 year-end prices has been attributed to lower loads in January 2006 and a decline in natural gas prices. The price of SO2 allowances, determined by obtaining broker quotes and information from other public sources, was $750 per ton as of July 31, 2006.

For a discussion of environmental regulations related to emissions, refer to “Other Developments—Environmental Matters” of the year-ended 2005 MD&A.

MEHC’s Credit Risk

In conducting EME’s price risk management and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted price if the nonperforming counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of nonpayment 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.

EME measures credit risk exposure from counterparties of its merchant energy activities 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 price risk management 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, 2006, the amount of exposure, broken down by the credit ratings of EME’s counterparties, was as follows:


In millions	June 30, 2006
S&P Credit Rating
A or higher	$	88
A-		18
BBB+		52
BBB		65
BBB-		—
Below investment grade		2
Total	$	225

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 69% of EME’s consolidated operating revenue for the six months ended June 30, 2006. Moody’s Investors Service rates PJM’s senior unsecured 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 noninvestment grade companies. Any losses due to a PJM member default are shared by all other members based upon a predetermined formula. At June 30, 2006, EME’s account receivable due from PJM was $70 million.

MEHC’s Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. The fair market values of long-term fixed interest rate obligations are subject to interest

rate risk. The fair market value of MEHC’s consolidated long-term obligations (including current portion) was $4.4 billion at June 30, 2006, compared to the carrying value of $4.2 billion. The fair market value of MEHC’s parent only long-term obligations was $941 million at June 30, 2006, compared to the carrying value of $793 million.

MEHC’s 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, 2006	December 31, 2005
Commodity price:
Electricity	$ (3)	$ (434)

In assessing the fair value of EME’s nontrading derivative financial instruments, EME uses a variety of methods and assumptions based on the market conditions and associated risks existing at each balance sheet date. 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 following table summarizes the maturities and the related fair value, based on actively traded prices, of EME’s commodity price risk management assets and liabilities as of June 30, 2006:


In millions	Total Fair Value	Maturity Less than 1 year	Maturity 1 to 3 years	Maturity 4 to 5 years	Maturity Greater than 5 years
Prices actively quoted	$ (3)	$ 5	$ (8)	$ —	$ —

Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities as of June 30, 2006 and December 31, 2005, are set forth below:


	June 30, 2006				December 31, 2005
In millions	Assets		Liabilities		Assets		Liabilities
Electricity	$	120	$	4	$	127	$	27
Other		1		2		1		—
Total	$	121	$	6	$	128	$	27

The change in the fair value of trading contracts for the six months ended June 30, 2006, was as follows:


In millions
Fair value of trading contracts at January 1, 2006	$	101
Net gains from energy trading activities		59
Amount realized from energy trading activities		(52	)
Other changes in fair value		7
Fair value of trading contracts at June 30, 2006	$	115

Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated electric utility that EME’s subsidiary purchased and restructured and a long-term power supply agreement with another unaffiliated party. EME’s subsidiary recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the nonrecourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of June 30, 2006):


In millions	Total Fair Value		Maturity Less than 1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity Greater than 5 years
Prices actively quoted	$	29	$	26	$	3	$	—	$	—
Prices based on models and other valuation methods		86		1		11		17		57
Total	$	115	$	27	$	14	$	17	$	57

MEHC’s Regulatory Matters

PJM Reliability Pricing Model

On August 31, 2005, PJM filed under sections 205 and 206 of the Federal Power Act a proposal for a reliability pricing model (RPM) to replace its existing capacity construct. The proposal offers RPM as a new capacity construct to address the deficiencies in PJM’s current structure in a comprehensive and integrated manner. On April 20, 2006, the FERC issued an Initial Order on RPM, finding that as a result of a combination of factors, PJM’s existing capacity construct is unjust and unreasonable as a long-term capacity solution, because it fails to set prices adequate to ensure energy resources to meet its reliability responsibilities. Although the FERC did not find that the RPM proposal, as filed by PJM, is the just and reasonable replacement for the current capacity construct because some elements of the proposal need further development and elaboration, it did find that certain elements of the RPM proposal, with some adjustment and clarification, may form the basis for a just and reasonable capacity market. Accordingly, in the order the FERC provided guidance on PJM’s RPM proposal, as well as other features that need to be included in a just and reasonable capacity market, and established further proceedings to resolve these issues.

MISO Revenue Sufficiency Guarantee Charges

On April 25, 2006, the FERC issued an order regarding the MISO’s “Revenue Sufficiency Guarantee” charges (RSG charges). The MISO’s business practice manuals and other instructions to market participants have stated, since the implementation of market operations on April 1, 2005, that RSG charges will not be imposed on offers to supply power not supported by actual generation (also known as virtual supply offers). However, some market participants raised questions about the language of the MISO’s tariff concerning that issue and, in October 2005, the MISO submitted to the FERC proposed tariff revisions clarifying its tariff to reflect its business practices with respect to RSG charges and filed corrected tariff sheets exempting virtual supply from RSG charges. In its April 25 decision, the FERC interpreted the MISO’s tariff to require that virtual supply offers must be included in the calculation of the RSG charges and that, to the extent that the MISO did not charge virtual supply offers for RSG charges, it violated the terms of its tariff. The FERC order then proceeded to require the MISO to recalculate the RSG charges back to April 1, 2005, and to make refunds to customers, with interest, reflecting the recalculated charges. In order to make such refunds, it is likely that the MISO will attempt to impose retroactively RSG charges on those who submitted virtual supply offers during the recalculation period. EMMT made virtual supply offers in the MISO during this period on which no RSG charges were imposed, and thus may be subject to a claim for refunds from the MISO (which claim will be contested by EMMT). Because calculation of any claimed liability for refunds depends on information not currently available to it, EMMT cannot

reasonably estimate a range of loss related to this matter. In addition, the FERC’s April 25 order has been challenged by the MISO and other parties, including EMMT, and as the FERC has issued an extension of time to comply with the requirements of the order until after the date of issuance of an order on rehearing, the eventual outcome of these proceedings is unclear. The FERC order also requires the MISO to modify its tariff on a prospective basis to impose RSG charges on virtual supply offers. At this time, it is not possible to predict how the prospective effect of the order will affect the nature and operation of the MISO markets.

FERC Order Regarding PJM Marginal Losses

On May 1, 2006, the FERC issued an order in response to a complaint filed by Pepco Holdings, Inc. against PJM regarding marginal losses for transmission. The FERC concluded that PJM had violated its tariff by not implementing marginal losses and further directed PJM to implement marginal losses by October 2, 2006. Implementation of marginal losses will adjust the algorithm that calculates locational marginal prices to include a marginal loss component in addition to the already included congestion component. This may have an adverse impact on sellers in the Western PJM and Northern Illinois regions. On June 19, 2006, the FERC issued an order delaying implementation of marginal losses in PJM until June 1, 2007, and at this time it is not possible to predict how the prospective effect of the order will affect the prices at which EME Homer City and Midwest Generation will be able to sell their power.

Edison Capital’s Market Risk Exposures

Edison Capital is exposed to interest rate risk, foreign currency exchange rate risk and credit and performance risk that could adversely affect its results of operations or financial position. See “Edison Capital: Market Risk Exposures” in the year-ended 2005 MD&A for a complete discussion of Edison Capital’s market risk exposures.

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, 2006, Edison International had no debt outstanding (excluding intercompany related debt).

Edison International (parent)’s cash requirements for the twelve-month period following June 30, 2006 primarily consist of:

•

Dividends to common shareholders. Edison International paid quarterly common stock dividends of $88 million on January 31, 2006, April 30, 2006 and July 31, 2006;

•

Intercompany related debt; and

•

General and administrative expenses.

Edison International (parent) expects to meet its continuing obligations through cash and cash equivalents on hand, short-term borrowings, when necessary, and dividends from its subsidiaries. At June 30, 2006, Edison International (parent) had approximately $74 million of cash and cash equivalents on hand. In December 2005, Edison International (parent) replaced its $750 million credit facility with a $1 billion five-year senior unsecured credit facility. As of June 30, 2006, the entire $1 billion 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.

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. The CPUC also requires that SCE establish its dividend policy as though it were a comparable stand-alone utility company and give first priority to the capital requirements of the utility 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. During 2006, SCE made dividend payments to Edison International of $71 million on January 16, 2006, and $60 million on both April 28, 2006 and July 24, 2006.

MEHC may not pay dividends unless it has an interest coverage ratio of at least 2.0 to 1. At June 30, 2006, its interest coverage ratio was 2.97 to 1. See “EMG: Liquidity—MEHC’s Dividend Restrictions in Major Financings—Key Ratios of MEHC and EME’s Principal Subsidiaries Affecting Dividends.” In addition, MEHC’s certificate of incorporation and senior secured note indenture contain restrictions on MEHC’s ability to declare or pay dividends or distributions (other than dividends payable solely in MEHC’s common stock). These restrictions require the unanimous approval of MEHC’s Board of Directors, including its independent director, before it can declare or pay dividends or distributions, as long as any indebtedness is outstanding under the indenture. MEHC’s ability to pay dividends is dependent on EME’s ability to pay dividends to MEHC (parent). MEHC has not declared or made dividend payments to Edison International during the first quarter of 2006. EME and its subsidiaries have certain dividend restrictions as discussed in the “EMG: Liquidity—MEHC’s Dividend Restrictions in Major Financings” section.

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, 2006. Edison Capital made a $50 million dividend payment to Edison International in 2006.

EDISON INTERNATIONAL (PARENT): OTHER DEVELOPMENTS

Federal and State Income Taxes

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994 to 1996 and 1997 to 1999 tax years, respectively. 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 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

Edison International recorded consolidated earnings of $177 million, or 54¢ per common share, for the three-month period ended June 30, 2006, compared to $201 million, or 61¢ per common share, for the comparable period in 2005.

Edison International recorded consolidated earnings of $435 million, or $1.32 per common share, for the six-month period ended June 30, 2006, compared to $403 million, or $1.23 per common share, for the comparable period in 2005.

The table below presents Edison International’s earnings and earnings per common share for the three- and six-month periods ended June 30, 2006 and 2005, and the relative contributions by its subsidiaries.


In millions, except per common share amounts	Earnings (Loss)						Earnings (Loss) per Common Share
Three-Month Period Ended June 30,	2006			2005			2006			2005
Earnings (Loss) from Continuing Operations:
SCE	$	234		$	161		$	0.72		$	0.49
EMG:
MEHC		(60	)		2			(0.18	)		0.01
Edison Capital and other		4			23			0.01			0.07
EMG Total		(56	)		25			(0.17	)		0.08
Edison International (parent) and other		(5	)		(6	)		(0.02	)		(0.02	)
Edison International Consolidated Earnings from Continuing Operations		173			180			0.53			0.55
Earnings from Discontinued Operations		4			21			0.01			0.06
Edison International Consolidated	$	177		$	201		$	0.54		$	0.61


In millions, except per common share amounts	Earnings (Loss)						Earnings (Loss) per Common Share
Six-Month Period Ended June 30,	2006			2005			2006			2005
Earnings (Loss) from Continuing Operations:
SCE	$	355		$	292		$	1.09		$	0.89
EMG:
MEHC		(2	)		29			(0.01	)		0.10
Edison Capital and other		19			73			0.06			0.22
EMG Total		17			102			0.05			0.32
Edison International (parent) and other		(15	)		(19	)		(0.06	)		(0.06	)
Edison International Consolidated Earnings from Continuing Operations		357			375			1.08			1.15
Earnings from Discontinued Operations		77			28			0.24			0.08
Cumulative Effect of Change in Accounting Principle		1			—			—			—
Edison International Consolidated	$	435		$	403		$	1.32		$	1.23

Earnings (Loss) from Continuing Operations

Edison International’s earnings from continuing operations were $173 million and $357 million for the three- and six-month periods ended June 30, 2006, respectively, compared with earnings of $180 million and $375 million for the comparable periods in 2005.

SCE’s earnings from continuing operations were $234 million and $355 million for the three- and six-month periods ended June 30, 2006, respectively, compared with earnings of $161 million and $292 million for the comparable periods in 2005. The increase for both periods is primarily due to the resolution of an outstanding state income tax issue, higher revenue associated with the implementation of the 2006 GRC decision and the return on investment earned by SCE’s Mountainview plant, partially offset by higher operating and income tax expenses.

EMG had a loss from continuing operations of $56 million for the three-month period and earnings of $17 million for the six-month period ended June 30, 2006, respectively, compared with earnings of $25 million and $102 million for the comparable periods in 2005. MEHC’s second quarter 2006 loss includes an after-tax charge of $88 million reflecting the early extinguishment of debt related to EME’s bond refinancing and higher taxes, partially offset by higher wholesale energy margins mainly driven by higher prices at MEHC’s Illinois plants and Homer City facilities, an estimated insurance recovery at MEHC’s Homer City facilities related to the Unit 3 outage and higher net interest income. MEHC’s year-to-date earnings also reflect higher energy trading income. Edison Capital’s earnings for both the quarter and year-to-date decreased primarily due to Edison Capital’s share of income from its investment in the Emerging Europe Infrastructure Fund which recorded a gain in the second quarter of 2005.

Operating Revenue

Electric Utility Revenue

SCE’s retail sales represented approximately 89% of electric utility revenue for both the three- and six-month periods ended June 30, 2006, respectively, compared to approximately 83% for both comparable periods in 2005. Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is generally significantly higher than other quarters.

The following table sets forth the major changes in electric utility revenue:


In millions	Three Months Ended June 30, 2006 vs. 2005			Six Months Ended June 30, 2006 vs. 2005
Electric utility revenue
Rate changes (including unbilled)	$	356		$	457
Sales volume changes (including unbilled)		15			91
Deferred revenue		49			234
Sales for resale		(109	)		(198	)
SCE’s variable interest entities		(16	)		—
Other (including intercompany transactions)		23			46
Total	$	318		$	630

Total electric utility revenue increased by $318 million and $630 million for the three and six months ended June 30, 2006, respectively (as shown in the table above). The increases resulting from rate changes for both periods was mainly due to the rate change implemented on February 4, 2006 arising from SCE’s 2006 ERRA decision (see “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings—ERRA Forecast” in the year-ended 2005 MD&A for further discussion). The increases in electric utility revenue resulting from sales volume changes was mainly due to an increase in kilowatt-hours (kWh) sold, including SCE providing a greater amount of energy to its customers from its own sources in 2006, compared to 2005. The change in deferred revenue for the three-month period reflects deferral of approximately $73 million of revenue in 2006, compared to deferral of approximately $122 million in 2005 due to lower overcollections in 2006. The change in deferred revenue for the six-month period ended June 30, 2006 reflects the recognition of approximately $34 million of revenue in 2006 due to balancing account undercollections, compared to the deferral of approximately $200 million of revenue in 2005 due to balancing account overcollections. Electric utility revenue from 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 decreased due to a lesser amount of excess energy in 2006, as compared to 2005. Revenue from sales for resale is refunded to customers through the ERRA rate-making mechanism and does not impact earnings. SCE’s variable interest entities revenue represents the recognition of revenue resulting from the consolidation of SCE’s variable interest entities.

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 $553 million and $1.1 billion for the three- and six-month periods ended June 30, 2006, respectively, compared to $409 million and $919 million for the same respective periods in 2005.

Nonutility Power Generation Revenue

Nonutility power generation revenue increased $43 million and $42 million in the three- and six-month periods ended June 30, 2006, respectively, as compared to the same periods in 2005.

Energy revenue at MEHC’s Homer City facilities increased $10 million for the three-month period ended June 30, 2006 and decreased $11 million for the six-month period ended June 30, 2006. Although generation in the second quarter of 2006 was lower than second quarter of 2005, due to an unplanned outage, there was a 17% increase in average energy prices. The year-to-date decrease was mainly due to an unplanned outage. MEHC’s Homer City facilities are generally classified as a baseload plant, which means the amount of generation is largely based on the availability of the plant. Accordingly, the unplanned outage reduced the amount of generation during the first six months of 2006.

Energy revenue at MEHC’s Illinois plants increased $17 million and $28 million for the three- and six-month periods ended June 30, 2006, respectively, as compared to the same periods in 2005, mainly due to higher average energy prices. Although generation in the second quarter of 2006 was lower than the second quarter of 2005, there was a 14% increase in average energy prices.

Revenue from energy trading activities at EMMT increased $7 million and $12 million for the three- and six-month periods ended June 30, 2006, respectively, as compared to the same periods in 2005. The increase was primarily due to increased congestion at specific delivery points in the eastern power grid in which EMMT purchased financial transmission rights. See “EMG: Market Risk Exposures—Regulatory Matters—MISO Revenue Sufficiency Guarantee Charge” for information regarding potential refund exposure related to virtual supply offers made by EMMT in MISO after April 1, 2005.

Due to higher electric demand resulting from warmer weather during the summer months, nonutility power generation revenue generated from MEHC’s Illinois plants and Homer City facilities are generally higher during the third quarter of each year. However, as a result of recent increases in market prices for power, driven in part by higher natural gas and oil prices, this historical trend may not be applicable to quarterly revenue in the future.

Operating Expenses

Fuel Expense


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2006		2005		2006		2005
SCE	$	237	$	265	$	548	$	520
EMG – MEHC		143		134		292		298
Edison International Consolidated	$	380	$	399	$	840	$	818

SCE’s fuel expense decreased $28 million for the three months ended June 30, 2006 and increased $28 million for the six months ended June 30, 2006, as compared to the same periods in 2005. The quarter and year-to-date variances were due to lower fuel expense of approximately $15 million and $35 million for the three- and six-month periods ended June 30, 2006 at SCE’s Mohave Generating Station resulting from the plant shutdown on December 31, 2005 (see “SCE: Regulatory Matters—Mohave Generating Station and Related Proceedings” for further discussion); lower nuclear fuel expense of $10 million and $15 million for the three- and six-month periods ended June 30, 2006 resulting from a planned refueling and maintenance outage at SCE’s San Onofre Unit 2; lower fuel expense of $45 million and $15 million for the three- and six-month periods ended June 30, 2006 related to SCE’s consolidated variable interest entities; and higher fuel expense of $40 million and $95 million for the three- and six-month periods ended June 30, 2006 resulting from SCE’s newly constructed Mountainview project which became operational in December 2005. The year-to-date variance also reflects a Department of Energy settlement refund of approximately $10 million related to crude oil overcharges. The settlement refund was returned to ratepayers through the ERRA mechanism.

Purchased-Power Expense

Purchased-power expense increased $26 million and $652 million for the three- and six-month period ended June 30, 2006, respectively, as compared to the same periods in 2005. The quarterly increase was mainly due to increased firm energy purchases of approximately $80 million, lower energy settlement refunds of approximately $95 million in 2006, compared to 2005 and increased purchase power expense of $45 million related to SCE’s variable interest entities. These increases were partially offset by lower net realized and unrealized losses on economic hedging transactions of approximately $105 million and lower expenses of approximately $30 million related to power purchased from qualifying facilities (QF) as discussed further below. The year-to-date increase

was mainly due higher net realized and unrealized losses related to economic hedging transactions of approximately $450 million in 2006, as compared to 2005, higher firm energy purchases of approximately $115 million and lower energy settlement refunds of approximately $85 million.

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. Effective May 2002, energy payments for most renewable QFs were converted to a fixed price of 5.37¢-per-kWh until April 2007. Average spot natural gas prices were higher during 2006 as compared to 2005. The higher expenses related to power purchased from QFs were mainly due to higher average spot natural gas prices, partially offset by lower kWh purchases.

Provisions for Regulatory Adjustment Clauses—Net

Provisions for regulatory adjustment clauses—net increased $31 million for the three-month period ended June 30, 2006 and decreased $395 million for the six-month period ended June 30, 2006, as compared to the same periods in 2005. The increase for the three-month period was mainly due to lower net unrealized losses of approximately $190 million related to economic hedging transactions (mentioned above in purchased-power expense) that, if realized, would be recovered from ratepayers, and higher net overcollections of purchase-power, fuel, and operation and maintenance expenses of approximately $60 million. These increases were partially offset by the resolution of the one-time issue related to a portion of revenue collected during the 2001–2003 period related to state income taxes. SCE was able to determine through the 2006 GRC decision and other regulatory proceedings that the level of revenue collected during that period was appropriate, and as a result recorded a pre-tax gain of $135 million. The decrease for the six-month period ended June 30, 2006 was mainly due to the implementation of the 2006 GRC decision and higher net unrealized losses of approximately $295 million related to economic hedging transactions, partially offset by net overcollections of purchased-power, fuel, and operation and maintenance expenses of approximately $80 million in 2006, compared to net undercollections of approximately $30 million in 2005.

Other Operation and Maintenance Expense


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2006		2005		2006		2005
SCE	$	639	$	569	$	1,254	$	1,167
EMG – MEHC		230		232		424		422
EMG – Edison Capital and Other		6		14		13		32
Edison International (parent) and Other		4		7		16		14
Edison International Consolidated	$	879	$	822	$	1,707	$	1,635

SCE’s other operation and maintenance expense increased $70 million and $87 million for the three- and six-month periods ended June 30, 2006, respectively, as compared to the same periods in 2005. The quarter and year-to-date increases were mainly due to higher generation-related costs of approximately $10 million for the quarter ended June 30, 2006 and $40 million for the year-to-date ended June 30, 2006 primarily resulting from the planned refueling and maintenance outage at SCE’s San Onofre Unit 2, an increase in reliability costs of $45 million and $20 million for the three- and six-month periods ended June 30, 2006 related to must-run offer units (reliability costs are being recovered through regulatory mechanisms approved by the FERC). As a result of implementation of the 2006 GRC, beginning in May 2006, costs related to Mohave shutdown, postretirement benefits other than pensions, pensions and results sharing are being recovered through a balancing account mechanism.

Depreciation, Decommissioning and Amortization Expense


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2006		2005		2006		2005
SCE	$	300	$	231	$	552	$	454
EMG – MEHC		35		31		68		61
EMG – Edison Capital and Other		4		5		11		12
Edison International Consolidated	$	339	$	267	$	631	$	527

SCE’s depreciation, decommissioning and amortization expense increased $69 million and $98 million for the three- and six-month periods ended June 30, 2006, respectively, as compared to the same periods in 2005. The increases in 2006 are mainly due to an increase in depreciation expense resulting from additions to transmission and distribution assets, as well as an increase of approximately $25 million resulting from the implementation of the new depreciation rates approved in the 2006 GRC decision for the period January 12, 2006 through May 31, 2006, and higher investment earnings from SCE’s nuclear decommissioning trusts. The nuclear decommissioning trust investment earnings are also recorded in electric utility revenue and as a result, have no impact on net income.

Other Income and Deductions

Interest and Dividend Income


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2006		2005		2006		2005
SCE	$	13	$	9	$	26	$	17
EMG – MEHC		23		14		43		26
EMG – Edison Capital and Other		5		2		9		4
Edison International (parent) and Other		2		—		2		—
Edison International Consolidated	$	43	$	25	$	80	$	47

SCE’s interest and dividend income increased for the three- and six-month periods ended June 30, 2006, as compared to the same periods in 2005. The 2006 increases were mainly due to higher interest income resulting from higher balancing account undercollections and higher short-term interest rates in 2006 as compared to 2005.

MEHC’s interest and dividend income increased for the three- and six-month periods ended June 30, 2006, as compared to the same periods in 2005, primarily due to higher interest rates in 2006, compared to 2005.

Equity in Income from Partnerships and Unconsolidated Subsidiaries – Net

Equity in income from partnerships and unconsolidated subsidiaries – net decreased $94 million for the six-month period ended June 30, 2006. The 2006 decrease is mainly due to lower earnings of approximately $90 million from Edison Capital’s global infrastructure funds.

Other Nonoperating Income


	Three Months Ended June 30,				Six Months Ended June 30,
In millions	2006		2005		2006		2005
SCE	$	19	$	18	$	46	$	35
EMG – MEHC		12		1		25		1
EMG – Edison Capital and Other		2		1		3		1
Edison International Consolidated	$	33	$	20	$	74	$	37

SCE’s other nonoperating income increased for the six-months ended June 30, 2006, as compared to the same period in 2005, mainly due to an increase in incentive rewards related to the efficient operation of Palo Verde and corporate-owned life insurance proceeds. The incentive rewards approved by the CPUC for the efficient operation of Palo Verde were $13 million in the first quarter of 2006 and $10 million in the first quarter of 2005.

MEHC’s other nonoperating income increased for the three- and six-months ended June 30, 2006, as compared to the same periods in 2005. The quarter increase reflects the recognition of an estimated business interruption insurance claim in the amount of $10 million. The year-to-date increase also reflects an $8 million gain related to the receipt of shares from Mirant Corporation from settlement of a claim recorded during the first quarter of 2006.

Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt for the three- and six-month periods ended June 30, 2006 of $143 million relates to the early repayment of MEHC’s 10% senior notes due August 15, 2008 and 9.875% senior notes due April 15, 2011. The loss on early extinguishment for the six-month period ended June 30, 2005 of $24 million primarily relates to the early repayment of MEHC’s $385 million term loan.

Income Tax (Benefit) – Continuing Operation


	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2006			2005			2006			2005
SCE	$	145		$	59		$	228		$	124
EMG – MEHC		(51	)		(22	)		(18	)		(6	)
EMG – Edison Capital and Other		2			—			(1	)		18
Edison International (parent) and other		(1	)		(3	)		(3	)		2
Edison International Consolidated	$	95		$	34		$	206		$	138

Edison International’s effective tax rate from continuing operations was 35% and 37% for the three- and six-month periods ended June 30, 2006, respectively, as compared to 16% and 27% for the same periods in 2005. The increased effective tax rate resulted from reductions made to income tax reserves at SCE and EME in 2005 which have not recurred in 2006. The 2005 reserve reductions were made to reflect progress in settlement negotiations relating to income tax audits.

Income from Discontinued Operations

Edison International’s earnings from discontinued operations were $4 million and $77 million for the three- and six-month periods ended June 30, 2006, respectively, compared to $21 million and $28 million for the same periods in 2005. The 2006 and 2005 earnings primarily resulted from distributions received related to MEHC’s Lakeland project (see “EMG: Current Developments—MEHC: Lakeland Project” for further discussion).

Cumulative Effect of Accounting Change – Net of Tax

Effective January 1, 2006, Edison International adopted a new accounting standard that requires the fair value accounting method for stock-based compensation. Implementation of this new accounting standard resulted in a $1 million, after-tax, cumulative-effect adjustment in the first quarter of 2006 (see “New Accounting Pronouncements” for further discussion).

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 by operating activities:


In millions	Six-Month Period Ended June 30,	2006		2005
Continuing operations		$	976	$	812
Discontinued operations			82		22
		$	1,058	$	834

The 2006 change in cash provided by operating activities from continuing operations was mainly due to a change in working capital items resulting from the timing of cash receipts and disbursements.

Cash provided by operating activities from discontinued operations increased $60 million in the first six months of 2006, compared to the first six months of 2005. The 2006 increase reflects higher distributions received in 2006, compared to 2005, from MEHC’s Lakeland power project. See “Current Developments—EMG: Current Developments—MEHC: Lakeland Project” for more information regarding these distributions.

Cash Flows from Financing Activities

Net cash used by financing activities:


In millions	Six-Month Period Ended June 30,	2006		2005
Continuing operations		$	212	$	(907	)

Cash used by financing activities from continuing operations mainly consisted of long-term and short-term debt payments at SCE and EME.

Financing activities in 2006 included activities related to the rebalancing of SCE’s capital structure and rate base growth and the reduction of debt at MEHC.

•

In January 2006, SCE issued $500 million of first and refunding mortgage bonds which consisted of $350 million of 5.625% bonds due in 2036 and $150 million of floating rate bonds due in 2009. The proceeds from this issuance were used to redeem $150 million of variable rate first and refunding mortgage bonds due in January 2006 and $200 million of its 6.375% first and refunding mortgage bonds due in January 2006.

•

In January 2006, SCE issued two million shares of 6% Series C preference stock (noncumulative, $100 liquidation value) and received net proceeds of $197 million.

•

In April 2006, SCE issued $331 million of tax-exempt bonds which consisted of $196 million of 4.10% bonds which are subject to remarketing in April 2013 and $135 million of 4.25% bonds which are subject to remarketing in November 2016. The proceeds from this issuance were used to call and redeem $196 million of tax-exempt bonds due February 2008 and $135 million of tax-exempt bonds due March 2008.

•

In June 2006, EME issued $1 billion of senior notes. The proceeds from this issuance were mostly used to repay $965 million of EME’s outstanding senior notes and $136 million paid for tender premiums and related fees.

•

During the six months ended June 30, 2006, Midwest Generation had borrowings of $315 million under its credit facility, mostly offset by repayments of $285 million.

•

Financing activities in 2006 also included dividend payments of $176 million paid by Edison International to its shareholders.

Financing activities in 2005 also included activities related to the rebalancing of SCE’s capital structure and the reduction of debt at MEHC.

•

In January 2005, SCE issued $650 million of first and refunding mortgage bonds which consisted of $400 million of 5% bonds due in 2016 and $250 million of 5.55% bonds due in 2036. The proceeds from this issuance were used to redeem the remaining $50,000 of its 8% first and refunding mortgage bonds due February 2007 (Series 2003A) and $650 million of the $966 million 8% first and refunding mortgage bonds due February 2007 (Series 2003B).

•

In January 2005, MEHC repaid the remaining $285 million of its term loan.

•

In January 2005, MEHC repaid $150 million of its junior subordinated debentures.

•

In April 2005, SCE issued 4,000,000 shares of Series A preference stock (noncumulative, 100% liquidation value) and received net proceeds of approximately $394 million. Approximately $81 million of the proceeds was used to redeem all the outstanding shares of its $100 cumulative preferred stock, 7.23% Series, and approximately $64 million of the proceeds was used to redeem all the outstanding shares of its $100 cumulative preferred stock, 6.05% Series.

•

In April 2005, MEHC repaid $302 million related to Midwest Generation’s existing term loan.

•

In June 2005, SCE issued $350 million of 5.35% first and refunding mortgage bonds due in 2035 (Series 2005E). A portion of the proceeds from this issuance were used to redeem $316 million of its 8% first and refunding mortgage bonds due in 2007 (Series 2003B).

•

Financing activities in 2005 also include dividend payments of $163 million paid by Edison International to its shareholders.

Cash Flows from Investing Activities

Net cash provided (used) by investing activities:


In millions	Six-Month Period Ended June 30,	2006			2005
Continuing operations		$	(1,305	)	$	(502	)
Discontinued operations			—			5
		$	(1,305	)	$	(497	)

Cash flows from investing activities are affected by capital expenditures, EME’s sales of assets and SCE’s funding of nuclear decommissioning trusts.

Investing activities in 2006 reflect $1.1 billion in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $50 million for nuclear fuel acquisitions and $8 million related to the Mountainview project, and $120 million in capital expenditures at MEHC. In addition, investing activities include net purchases of marketable securities of $76 million at MEHC and received proceeds of $43 million from the sale of 25% of EME’s ownership interest in the San Juan Mesa wind project.

Investing activities in 2005 reflect $774 million in capital expenditures at SCE, primarily for transmission and distribution assets, including approximately $21 million for nuclear fuel acquisitions and $87 million related to the Mountainview project, and $35 million in capital expenditures at MEHC. In addition, investing activities include net purchases of marketable securities of $140 million at MEHC and $124 million in proceeds received in 2005 from the sale of EME’s 25% investment in the TriEnergy project and EME’s 50% investment in the CBK project.

ACQUISITIONS AND DISPOSITIONS

Acquisitions

On April 1, 2006, MEHC received as a capital contribution, ownership interests in a portfolio of wind projects located in Iowa and Minnesota and a small biomass project. The acquisition was accounted for as a transaction between entities under common control. As such, the assets and liabilities of the projects acquired were recorded at historical cost on the acquisition date for a net book value of approximately $76 million. MEHC subsequently contributed these ownership interests to EME.

Disposition

NEW ACCOUNTING PRONOUNCEMENTS

In July 2006, the FASB issued an FSP on accounting for a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction. The effective date is January 1, 2007. As discussed under “Other Developments—Federal and State Income Taxes” the deferral of income taxes associated with Edison Capital’s cross-border, leveraged leases has been challenged by the IRS. If it becomes probable that Edison International would accelerate the payment of deferred taxes for these leases, the new FSP requires the change in the timing of cash flows to trigger a recalculation of the income allocated over the life of the lease, with the cumulative effect of the change recognized immediately. This could result in a material charge against earnings, although future income would be expected to increase over the remaining terms of the affected leases.

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 2005 MD&A for a detailed discussion.

Other Commitments

Edison International’s long-term principal debt maturities and sinking-fund requirements as of June 30, 2006 are: remaining 2006—$190 million; 2007—$486 million; 2008—$879 million; 2009—$763 million; 2010—$312 million; and thereafter—$7.0 billion.

At June 30, 2006, EME’s subsidiaries had firm commitments to spend approximately $157 million during the remainder of 2006 and $33 million in 2007 on capital and construction expenditures. The majority of these expenditures relate to the construction of the Wildorado wind project (see “Acquisitions and Dispositions” for further discussion related to the Wildorado project). Also included are expenditures for boiler head replacement, dust collection and mitigation system and various other projects. These expenditures are planned to be financed by existing subsidiary credit agreements, cash on hand or cash generated from operations.

OTHER DEVELOPMENTS

Environmental Matters

The operating affiliates 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 affiliates are in substantial compliance with existing environmental regulatory requirements.

The domestic power plants owned or operated by Edison International’s operating affiliates, 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 sulfur dioxide (SO2) and nitrogen oxide (NOx) 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 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 2005 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:

Federal Air Quality Standards

Clean Air Mercury Rule

As part of its evaluation of environmental control technologies for the Homer City facilities, EME has obtained cost estimates from an engineering and construction company that are substantially higher than the approximately $350 million to $400 million previously estimated for the 2006-2010 timeframe. The estimated costs have increased for a number of reasons, including increased material costs and greater demand for environmental control equipment scheduled for installation during the same period. In light of higher estimated capital costs, the impact of the recent decline in emissions costs and the continued uncertainty over the final provisions of relevant environmental regulations, EME has deferred making commitments for the installation of further environmental controls at the Homer City facilities at this time. EME plans to study alternative environmental technologies while continuing to review and refine the scope of the project, estimated costs for control equipment and to monitor developments related to mercury and other environmental regulations.

State Air Quality Standards

On March 14, 2006, the Illinois Environmental Protection Agency submitted a proposed rule to the Illinois Pollution Control Board (PCB) for adoption. The proposed rule requires a 90% reduction of mercury emissions from coal-fired power plants averaged across company-owned Illinois stations and a minimum reduction of 75% for individual generating units by July 1, 2009. A 90% reduction at each station would be required by 2013. The first hearing on the rule was held in June 2006 and a second hearing is set for August 2006.

Environmental Remediation

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.

Federal and State Income Taxes

The following table summarizes estimated federal and state income taxes deferred from these leases. Repayment of these deferred taxes would be accelerated if the IRS prevails:


In millions	Tax Years Under Appeal 1994 – 1999		Unaudited Tax Years 2000 – 2005		Total
Replacement Leases (SILO)	$	44	$	36	$	80
Lease/Leaseback (LILO)		547		570		1,117
Service Contract (SILO)		—		272		272
	$	591	$	878	$	1,469

As of June 30, 2006, the interest on the proposed tax adjustments is estimated to be approximately $356 million. The IRS also seeks a 20% penalty on any sustained tax adjustment.

In addition, the payment of taxes, interest and penalties could have a significant impact on earnings and cash flow. In order to commence litigation in certain forums, Edison International must make payments of disputed taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. On May 26, 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 cash payment was funded by Edison Capital and accounted for as a deposit which will be refunded with interest to the extent Edison International prevails. If the IRS either denies this refund claim or fails to act on the claim within six months, Edison International expects to take legal action to assert its refund claim. Depending on the status of the claim for tax year 1999, Edison International may make additional payments related to other tax years to preserve its litigation rights, although, at this time, the amount and timing of these additional payments is uncertain. At this time, Edison International is unable to predict the impact of the ultimate resolution of these matters. See “EMG: Liquidity—Edison Capital’s Liquidity.”

In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through 2002 to abate 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 above. Edison International filed these amended returns under protest, retaining its appeal rights.

Enterprise-Wide Software System Project

Edison International has commenced an enterprise-wide project to implement a comprehensive, integrated software system to support the majority of its critical business processes during the next few years. The objective of this initiative is to improve the efficiency and effectiveness of both SCE’s and EMG’s operations and enhance the transparency of information.

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,” “EMG: Market Risk Exposures,” and “Edison International (Parent): Market Risk Exposures.”

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

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 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, 2006 to April 30, 2006	395,495	$	40.05	—	—

May 1, 2006 to May 31, 2006	649,958	$	39.65	—	—

June 1, 2006 to June 30, 2006	822,029	$	39.36	—	—
Total	1,867,482	$	39.61	—	—

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 27, 2006, three matters were put to a vote of the shareholders: the election of eleven directors, a proposal to eliminate the “Fair Price” provision, and a shareholder proposal on “Simple Majority Vote.”

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


	Number of Votes
Name	For	Witheld
John E. Bryson	261,623,042	11,198,865
France A. Cordova	267,723,633	5,098,274
Charles B. Curtis	267,719,829	5,102,078
Bradford M. Freeman	261,605,972	11,215,935
Bruce Karatz	266,833,901	5,988,006
Luis G. Nogales	260,743,922	12,077,985
Ronald L. Olson	251,471,768	21,350,139
James M. Rosser	261,819,933	11,001,974
Richard T. Schlosberg, III	260,812,672	12,009,235
Robert H. Smith	260,663,864	12,158,043
Thomas C. Sutton	255,261,721	17,560,186

The management proposal to eliminate the “Fair Price” provision, which received the affirmative vote of a majority of the votes entitled to be cast, was adopted. The proposal received the following numbers of votes:


For	Against	Abstentions	Broker Non-Votes
265,506,979	4,063,257	3,251,671	0

The shareholder proposal on “Simple Majority Vote,” 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
53,430,353	174,646,383	3,705,188	41,039,983

Item 6. Exhibits


3.1		Restated Articles of Incorporation of Edison International, effective May 9, 1996 (File No. 1-9936, filed as Exhibit 3.1 to Edison International’s Form 10-K for the year ended December 31, 1998)*

3.2		Certificate of Determination of Series A Junior Participating Cumulative Preferred Stock of International’s Form 8-A dated November 21, 1996)*

3.3		Certificate of Amendment of Articles of Incorporation of Edison International, effective May 10, 2006

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

*	Incorporated herein by reference pursuant to Rule 12b-32.

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, 2006