10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________

FORM 10-Q

________________________

(Mark One)
R	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2012
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                        to

Commission File Number 1-2313

________________________

SOUTHERN CALIFORNIA EDISON COMPANY

(Exact name of registrant as specified in its charter)

________________________

California (State or other jurisdiction of incorporation or organization)	95-1240335 (I.R.S. Employer Identification No.)
2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California (Address of principal executive offices)	91770 (Zip Code)
(626) 302-1212 (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 S    No o

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

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

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

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

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 October 30, 2012
Common Stock, no par value	434,888,104

TABLE OF CONTENTS

GLOSSARY		iii
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS		1
	Consolidated Statements of Income	1
	Consolidated Statements of Comprehensive Income	1
	Consolidated Balance Sheets	2
	Consolidated Statements of Cash Flows	4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		5
	Note 1. Summary of Significant Accounting Policies	5
	Note 2. Consolidated Statements of Changes in Equity	6
	Note 3. Variable Interest Entities	7
	Note 4. Fair Value Measurements	8
	Note 5. Debt and Credit Agreements	12
	Note 6. Derivative Instruments and Hedging Activities	12
	Note 7. Income Taxes	15
	Note 8. Compensation and Benefit Plans	16
	Note 9. Commitments and Contingencies	17
	Note 10. Environmental Developments	22
	Note 11. Supplemental Cash Flows Information	22
	Note 12. Preferred and Preference Stock	22
	Note 13. Regulatory Assets and Liabilities	23
	Note 14. Other Investments	24
	Note 15. Other Income and Expenses	25
	Note 16. Planned Sale of Interest in Four Corners	25
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		26
FORWARD-LOOKING STATEMENTS		26
MANAGEMENT OVERVIEW		27
	Highlights of Operating Results	27
	2012 CPUC General Rate Case	27
	2013 Cost of Capital Application	28
	San Onofre	28
	Capital Program	32
RESULTS OF OPERATIONS		33
	Three Months Ended September 30, 2012 versus September 30, 2011	33
	Nine Months Ended September 30, 2012 versus September 30, 2011	34
	Supplemental Operating Revenue Information	35
	Income Taxes	36
LIQUIDITY AND CAPITAL RESOURCES		36
	Available Liquidity	36
	Capital Investment Plan	37
	Regulatory Proceedings	37
	Dividend Restrictions	37
	Margin and Collateral Deposits	37
	Workers Compensation Self-Insurance Fund	38

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	Historical Consolidated Cash Flows	38
	Contractual Obligations and Contingencies	39
MARKET RISK EXPOSURES		39
	Commodity Price Risk	40
	Credit Risk	40
CRITICAL ACCOUNTING ESTIMATES AND POLICIES		40
NEW ACCOUNTING GUIDANCE		40
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		40
ITEM 4. CONTROLS AND PROCEDURES		41
	Disclosure Controls and Procedures	41
	Changes in Internal Control Over Financial Reporting	41
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS		41
ITEM 6. EXHIBITS		41
SIGNATURE		42

ii

GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2011 Form 10-K	SCE's Annual Report on Form 10-K for the year-ended December 31, 2011
2010 Tax Relief Act	Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
AFUDC	allowance for funds used during construction
APS	Arizona Public Service Company
ARO(s)	asset retirement obligation(s)
Bcf	billion cubic feet
Big 4	Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAISO	California Independent System Operator
CAMR	Clean Air Mercury Rule
CARB	California Air Resources Board
CDWR	California Department of Water Resources
CEC	California Energy Commission
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DOE	U. S. Department of Energy
ERRA	energy resource recovery account
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FGIC	Financial Guarantee Insurance Company
FIP(s)	federal implementation plan(s)
Four Corners	coal fueled electric generating facility located in Farmington, New Mexico in which SCE holds a 48% ownership interest
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GRC	general rate case
IRS	Internal Revenue Service
ISO	Independent System Operator
kWh(s)	kilowatt-hour(s)
MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations in this report
Mohave	two coal fueled electric generating facilities that no longer operate located in Clark County, Nevada in which SCE holds a 56% ownership interest
Moody's	Moody's Investors Service
MRTU	Market Redesign Technology Upgrade
MW	megawatts
MWh	megawatt-hours
NAAQS	national ambient air quality standards
NERC	North American Electric Reliability Corporation
Ninth Circuit	U.S. Court of Appeals for the Ninth Circuit
NOx	nitrogen oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review

iii

Palo Verde	large pressurized water nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest
PBOP(s)	postretirement benefits other than pension(s)
PBR	performance-based ratemaking
PG&E	Pacific Gas & Electric Company
PSD	Prevention of Significant Deterioration
QF(s)	qualifying facility(ies)
ROE	return on equity
S&P	Standard & Poor's Ratings Services
San Onofre	large pressurized water nuclear electric generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest
SCAQMD	South Coast Air Quality Management District
SCE	Southern California Edison Company
SDG&E	San Diego Gas & Electric
SEC	U.S. Securities and Exchange Commission
SIP(s)	state implementation plan(s)
SO2	sulfur dioxide
SRP	Salt River Project Agricultural Improvement and Power District
US EPA	U.S. Environmental Protection Agency
VIE(s)	variable interest entity(ies)

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PART I.     FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

Consolidated Statements of Income Southern California Edison Company

	Three months ended September 30,						Nine months ended September 30,
(in millions, unaudited)	2012			2011			2012			2011
Operating revenue	$	3,731		$	3,386		$	8,794		$	8,063
Fuel	82			110			220			269
Purchased power	1,612			1,264			3,049			2,422
Operation and maintenance	906			819			2,622			2,450
Depreciation, decommissioning and amortization	399			358			1,187			1,058
Property and other taxes	73			71			229			217
Total operating expenses	3,072			2,622			7,307			6,416
Operating income	659			764			1,487			1,647
Interest income	2			2			5			7
Other income	36			26			103			103
Interest expense	(124		)	(116		)	(373		)	(344		)
Other expenses	(9		)	(10		)	(36		)	(35		)
Income before income taxes	564			666			1,186			1,378
Income tax expense	176			245			384			496
Net income	388			421			802			882
Less: Dividends on preferred and preference stock	25			15			66			44
Net income available for common stock	$	363		$	406		$	736		$	838

Consolidated Statements of Comprehensive Income
	Three months ended September 30,				Nine months ended September 30,
(in millions, unaudited)	2012		2011		2012			2011
Net income	$	388	$	421	$	802		$	882
Other comprehensive income, net of tax:
Pension and postretirement benefits other than pensions:
Net loss arising during the period, net of income tax benefit of $3 for the nine month period ended September 30, 2012	—		—		(4		)	—
Amortization of net loss included in net income, net of income tax expense of $1 for both three months ended September 30, 2012 and 2011 and $4 and $2 for the nine months ended September 30, 2012 and 2011, respectively	1		1		5			3
Comprehensive income	$	389	$	422	$	803		$	885

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

1

Consolidated Balance Sheets Southern California Edison Company

(in millions, unaudited)	September 30, 2012		December 31, 2011
ASSETS
Cash and cash equivalents	$	90	$	57
Receivables, less allowances of $75 for uncollectible accounts at both dates	1,067		760
Accrued unbilled revenue	787		519
Inventory	338		350
Prepaid taxes	48		278
Derivative assets	37		65
Regulatory assets	270		494
Deferred income taxes	170		—
Other current assets	110		89
Total current assets	2,917		2,612
Nuclear decommissioning trusts	3,997		3,592
Other investments	112		93
Total investments	4,109		3,685
Utility property, plant and equipment, less accumulated depreciation of $7,378 and $6,894 at respective dates	29,314		27,569
Nonutility property, plant and equipment, less accumulated depreciation of $115 and $107 at respective dates	71		73
Total property, plant and equipment	29,385		27,642
Derivative assets	74		70
Regulatory assets	6,068		5,815
Other long-term assets	506		491
Total long-term assets	6,648		6,376
Total assets	$	43,059	$	40,315

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

2

Consolidated Balance Sheets Southern California Edison Company

(in millions, except share amounts, unaudited)	September 30, 2012			December 31, 2011
LIABILITIES AND EQUITY
Short-term debt	$	380		$	419
Accounts payable	1,214			1,319
Accrued taxes	98			49
Accrued interest	104			167
Customer deposits	193			199
Derivative liabilities	128			266
Regulatory liabilities	493			670
Deferred income taxes	—			89
Other current liabilities	623			670
Total current liabilities	3,233			3,848
Long-term debt	8,828			8,431
Deferred income taxes	6,574			5,781
Deferred investment tax credits	103			84
Customer advances	149			138
Derivative liabilities	983			805
Pensions and benefits	2,359			2,461
Asset retirement obligations	2,731			2,610
Regulatory liabilities	5,249			4,670
Other deferred credits and other long-term liabilities	1,786			1,529
Total deferred credits and other liabilities	19,934			18,078
Total liabilities	31,995			30,357
Commitments and contingencies (Note 9)
Common stock, no par value (560,000,000 shares authorized; 434,888,104 shares issued and outstanding at each date)	2,168			2,168
Additional paid-in capital	600			596
Accumulated other comprehensive loss	(23		)	(24		)
Retained earnings	6,524			6,173
Total common shareholder's equity	9,269			8,913
Preferred and preference stock	1,795			1,045
Total equity	11,064			9,958
Total liabilities and equity	$	43,059		$	40,315

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

3

Consolidated Statements of Cash Flows Southern California Edison Company

	Nine months ended September 30,
(in millions, unaudited)	2012			2011
Cash flows from operating activities:
Net income	$	802		$	882
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,187			1,058
Regulatory impacts of net nuclear decommissioning trust earnings	147			131
Other amortization	55			97
Stock-based compensation	13			12
Deferred income taxes and investment tax credits	426			526
Proceeds from U.S. treasury grants	29			—
Changes in operating assets and liabilities:
Receivables	(336		)	(253		)
Inventory	13			(8		)
Margin and collateral deposits – net of collateral received	6			(9		)
Prepaid taxes	230			48
Other current assets	(295		)	(280		)
Accounts payable	165			142
Accrued taxes	49			77
Other current liabilities	(120		)	(230		)
Derivative assets and liabilities – net	63			433
Regulatory assets and liabilities – net	147			(363		)
Other assets	(26		)	(21		)
Other liabilities	101			30
Net cash provided by operating activities	2,656			2,272
Cash flows from financing activities:
Long-term debt issued	395			497
Long-term debt issuance costs	(4		)	(5		)
Long-term debt repaid	(4		)	(12		)
Bonds purchased	—			(86		)
Preference stock issued – net	804			123
Preference stock redeemed	(75		)	—
Short-term debt financing – net	(45		)	550
Settlements of stock-based compensation – net	(24		)	(7		)
Dividends paid	(411		)	(388		)
Net cash provided by financing activities	636			672
Cash flows from investing activities:
Capital expenditures	(3,105		)	(3,014		)
Proceeds from sale of nuclear decommissioning trust investments	1,525			2,108
Purchases of nuclear decommissioning trust investments and other	(1,689		)	(2,254		)
Customer advances for construction and other investments	10			24
Net cash used by investing activities	(3,259		)	(3,136		)
Net increase (decrease) in cash and cash equivalents	33			(192		)
Cash and cash equivalents, beginning of period	57			257
Cash and cash equivalents, end of period	$	90		$	65

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

4

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1.    Summary of Significant Accounting Policies

SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000 square-mile area of southern California. SCE is a wholly-owned subsidiary of Edison International.

Basis of Presentation

SCE's significant accounting policies were described in Note 1 of "SCE Notes to Consolidated Financial Statements" included in the 2011 Form 10-K. The same accounting policies are followed for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2012, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2011 Form 10-K.

In the opinion of management, all adjustments, consisting of recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and nine-month periods ended September 30, 2012 are not necessarily indicative of the operating results for the full year.

The December 31, 2011 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $28 million and $21 million at September 30, 2012 and December 31, 2011, respectively. Generally, the carrying value of cash equivalents equals the fair value, as these investments have original maturities of three months or less.

SCE temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. SCE reclassified $233 million and $220 million of checks issued, but not yet paid by the financial institution, from cash to accounts payable at September 30, 2012 and December 31, 2011, respectively.

Inventory

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

(in millions)	September 30, 2012		December 31, 2011
Fuel	$	19	$	24
Materials and supplies, spare parts	319		326
Total inventory	$	338	$	350

Revenue Recognition

Operating revenue is recognized when electricity is delivered and includes amounts for services rendered but unbilled at the end of each reporting period. During the first nine months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

New Accounting Guidance

Accounting Guidance Adopted in 2012

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board ("FASB") issued an accounting standards update modifying the fair value measurement and disclosure guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the value be based on the individual security. This amendment also results in new

5

disclosures primarily related to Level 3 measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. SCE adopted this guidance effective January 1, 2012. For further information, see Note 4.

Presentation of Comprehensive Income

In June 2011 and December 2011, the FASB issued accounting standards updates on the presentation of comprehensive income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate but consecutive statements. SCE adopted this guidance January 1, 2012 and elected to present two separate but consecutive statements. The adoption of these accounting standards updates did not change the items that constitute net income and other comprehensive income.

Accounting Guidance Not Yet Adopted

Offsetting Assets and Liabilities

In December 2011, the FASB issued an accounting standards update modifying the disclosure requirements about the nature of an entity's rights of offsetting assets and liabilities in the statement of financial position under master netting agreements and related arrangements associated with financial and derivative instruments. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and narrative descriptions of setoff rights. SCE will adopt this guidance effective January 1, 2013.

Note 2.    Consolidated Statements of Changes in Equity

The following table provides the changes in equity for the nine months ended September 30, 2012.

	Equity Attributable to SCE
(in millions)	Common Stock		Additional Paid-in Capital			Accumulated Other Comprehensive Loss			Retained Earnings			Preferred and Preference Stock			Total Equity
Balance at December 31, 2011	$	2,168	$	596		$	(24	)	$	6,173		$	1,045		$	9,958
Net income	—		—			—			802			—			802
Other comprehensive income	—		—			1			—			—			1
Dividends declared on common stock	—		—			—			(349		)	—			(349		)
Dividends declared on preferred and preference stock	—		—			—			(66		)	—			(66		)
Stock-based compensation and other	—		11			—			(35		)	—			(24		)
Noncash stock-based compensation and other	—		13			—			—			—			13
Issuance of preference stock	—		(21		)	—			—			825			804
Redemption of preference stock	—		1			—			(1		)	(75		)	(75		)
Balance at September 30, 2012	$	2,168	$	600		$	(23	)	$	6,524		$	1,795		$	11,064

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The following table provides the changes in equity for the nine months ended September 30, 2011.

	Equity Attributable to SCE
(in millions)	Common Stock		Additional Paid-in Capital			Accumulated Other Comprehensive Loss			Retained Earnings			Preferred and Preference Stock		Total Equity
Balance at December 31, 2010	$	2,168	$	572		$	(25	)	$	5,572		$	920	$	9,207
Net income	—		—			—			882			—		882
Other comprehensive income	—		—			3			—			—		3
Dividends declared on common stock	—		—			—			(345		)	—		(345		)
Dividends declared on preferred and preference stock	—		—			—			(44		)	—		(44		)
Stock-based compensation and other	—		5			—			(12		)	—		(7		)
Noncash stock-based compensation and other	—		12			—			1			—		13
Issuance of preference stock	—		(2		)	—			—			125		123
Balance at September 30, 2011	$	2,168	$	587		$	(22	)	$	6,054		$	1,045	$	9,832

Note 3.    Variable Interest Entities

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 17 power purchase agreements ("PPAs") that have variable interests in VIEs, including 7 tolling agreements through which SCE provides the natural gas to fuel the plants and 10 contracts with qualifying facilities ("QFs") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for these VIEs is the operation and maintenance of the power plants.

As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. Under these contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 9. As a result, there is no significant potential exposure to loss as a result of SCE's involvement with these VIEs. The aggregate capacity dedicated to SCE for these VIE projects was 3,900 MW at September 30, 2012 and the amounts that SCE paid to these projects were $158 million and $178 million for the three months ended September 30, 2012 and 2011, respectively, and $292 million and $347 million for the nine months ended September 30, 2012 and 2011, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.

Unconsolidated Trust

In May 2012, SCE Trust I issued $475 million (aggregate liquidation preference) of 5.625% trust securities (cumulative, liquidation amount of $25 per share) to the public and $10,000 of common stock (100%) to SCE. The trust invested the proceeds of these trust securities in Series F Preference Stock issued by SCE in the principal amount of $475 million (cumulative, $2,500 per share liquidation value) and which have substantially the same payment terms as the trust securities. The trust securities and the Series F Preference Stock do not have a maturity date. Upon any redemption of the Series F Preference Stock, a corresponding dollar amount of trust securities will be redeemed (for further information see Note 12). SCE Trust I will pay dividends at the same rate and on the same dates on the trust securities when, and if the SCE board of directors declare and make dividend payments on the Series F Preference Stock. The trust will use the dividends, if any, it receives on the Series F Preference Stock to make its corresponding dividend payments on the trust securities. If SCE does not make dividend payments to the trust, SCE would be prohibited from paying dividends on its common stock. SCE has fully and unconditionally guaranteed the payment of the trust securities and also its dividend payments, if and when, SCE pays dividends on the Series F Preference Stock.

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SCE Trust I was formed for the exclusive purpose of issuing trust preference securities (“trust securities”). The trust is a VIE. SCE has concluded that it is not the primary beneficiary of this VIE as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trust. The trust's balance sheet as of September 30, 2012, consisted of an investment of $475 million in the Series F Preference Stock, $475 million of trust securities and $10,000 of common stock. The trust's income statement consisted of dividend income and accrued dividend payments of $7 million and $10 million for the three- and nine-months ended September 30, 2012, respectively.

Note 4.    Fair Value Measurements

Recurring Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price”). Fair value of an asset or liability considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk which was not material as of September 30, 2012 and December 31, 2011.

Assets and liabilities are categorized into a three-level fair value hierarchy based on valuation inputs used to determine fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

The following table sets forth assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:

	September 30, 2012
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	28	$	—	$	—		$	—		$	28
Derivative contracts:
Electricity	—		1		9			(3		)	7
CRRs	—		—		100			—			100
Tolling	—		—		4			—			4
Subtotal of derivative contracts	—		1		113			(3		)	111
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks3	2,227		—		—			—			2,227
Municipal bonds	—		654		—			—			654
U.S. government and agency securities	467		122		—			—			589
Corporate bonds4	—		374		—			—			374
Short-term investments, primarily cash equivalents5	—		145		—			—			145
Subtotal of nuclear decommissioning trusts	2,694		1,295		—			—			3,989
Total assets6	2,730		1,296		113			(3		)	4,136
Liabilities at Fair Value
Derivative contracts:
Electricity	—		—		9			—			9
Natural gas	—		115		6			(47		)	74
Tolling	—		—		1,028			—			1,028
Subtotal of derivative contracts	—		115		1,043			(47		)	1,111
Total liabilities	—		115		1,043			(47		)	1,111
Net assets (liabilities)	$	2,730	$	1,181	$	(930	)	$	44		$	3,025

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	December 31, 2011
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at Fair Value
Money market funds2	$	21	$	—	$	—		$	—		$	21
Derivative contracts:
Electricity	—		—		1			—			1
Natural gas	—		5		—			(3		)	2
CRRs	—		—		122			—			122
Tolling	—		—		10			—			10
Subtotal of derivative contracts	—		5		133			(3		)	135
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks3	1,899		—		—			—			1,899
Municipal bonds	—		756		—			—			756
U.S. government and agency securities	433		147		—			—			580
Corporate bonds4	—		317		—			—			317
Short-term investments, primarily cash equivalents5	—		15		—			—			15
Subtotal of nuclear decommissioning trusts	2,332		1,235		—			—			3,567
Total assets6	2,361		1,240		133			(3		)	3,731
Liabilities at Fair Value
Derivative contracts:
Electricity	—		5		65			(2		)	68
Natural gas	—		234		23			(53		)	204
Tolling	—		—		799			—			799
Subtotal of derivative contracts	—		239		887			(55		)	1,071
Total liabilities	—		239		887			(55		)	1,071
Net assets (liabilities)	$	2,361	$	1,001	$	(754	)	$	52		$	2,660

¹  Represents the netting of assets and liabilities under master netting agreements and cash collateral across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.

²  Money market funds are included in cash and cash equivalents on SCE's consolidated balance sheets.

³  Approximately 67% and 70% of the equity investments were located in the United States at September 30, 2012 and December 31, 2011, respectively.

⁴  At September 30, 2012 and December 31, 2011, corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $42 million and $22 million, respectively.

⁵  Excludes net receivables of $8 million and $25 million at September 30, 2012 and December 31, 2011, respectively, of interest and dividend receivables as well as receivables and payables related to pending securities sales and purchases.

⁶  Excludes other investments of $70 million and $81 million at September 30, 2012 and December 31, 2011, respectively, primarily related to the cash surrender value of company owned life insurance investments which are used to fund certain executive benefits including deferred compensation.

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The following table sets forth a summary of changes in the fair value of Level 3 net derivative assets and liabilities:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Fair value of net assets (liabilities) at beginning of period	$	(739	)	$	(359	)	$	(754	)	$	6
Total realized/unrealized gains (losses), net:
Included in regulatory assets1	(180		)	(128		)	(203		)	(510		)
Purchases	33			19			84			35
Settlements	(44		)	(2		)	(57		)	(1		)
Transfers into Level 3	—			—			—			—
Transfers out of Level 3	—			—			—			—
Fair value of net liabilities at end of period	$	(930	)	$	(470	)	$	(930	)	$	(470	)
Change during the period in unrealized gains (losses) related to assets and liabilities held at the end of the period	$	(222	)	$	(135	)	$	(244	)	$	(502	)

¹  Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

The fair value for transfers in and transfers out of each level is determined at the end of each reporting period. There were no transfers between Levels 1 and 2 during the three- and nine-month periods ended September 30, 2012 and 2011.

Valuation Techniques Used to Determine Fair Value

Level 1

The fair value of Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded equity securities, U.S. treasury securities and money market funds.

Level 2

The fair value of Level 2 assets and liabilities is determined using the income approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument. This level includes fixed income securities and over-the-counter derivatives. For further discussion on fixed income securities, see "—Nuclear Decommissioning Trusts" below.

Over-the-counter derivative contracts are valued using standard pricing models to determine the net present value of estimated future cash flows. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. A primary price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity.

Level 3

The fair value of Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes over-the-counter options, tolling arrangements and derivative contracts that trade infrequently such as congestion revenue rights ("CRRs") and long-term power agreements.

Assumptions are made in order to value derivative contracts in which observable inputs are not available. Changes in fair value are based on changes to forward market prices, including extrapolation of short-term observable inputs into forecasted prices for illiquid forward periods. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts.

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Level 3 Valuation Process

The process of determining fair value is the responsibility of the risk management department which reports to the chief financial officer. This department obtains observable and unobservable inputs through broker quotes, exchanges and internal valuation techniques that use both standard and proprietary models to determine fair value. Each reporting period, the risk and finance departments collaborate to determine the appropriate fair value methodologies and classifications for each derivative. Inputs are validated for reasonableness by comparison against prior prices, other broker quotes and volatility fluctuation thresholds. Inputs used and valuations are reviewed period-over-period and compared with market conditions to determine reasonableness.

The following table sets forth the valuation techniques and significant unobservable inputs used to determine fair value for Level 3 assets and liabilities at September 30, 2012:

	Fair Value (in millions)							Significant	Range
	Assets			Liabilities			Valuation Technique(s)	Unobservable Input	(Weighted Average)
Electricity:
Options	$	23		$	26		Option model	Volatility of gas prices	23% - 41% (31%)
								Volatility of power prices	28% - 60% (39%)
								Power prices	$38.10 - $58.80 ($45.30)
Forwards	3			1			Discounted cash flow	Power prices	$22.10 - $64.50 ($32.50)
Gas Options	—			6			Option model	Volatility of gas prices	24% - 41% (35%)
CRRs	100			—			Market simulation model	Load forecast	7,597 MW - 26,612 MW
								Power prices	$(13.90) - $226.75
								Gas prices	$2.95 - $7.78
Tolling	5			1,028			Option model	Volatility of gas prices	17% - 41% (21%)
								Volatility of power prices	26% - 60% (28%)
								Power prices	$33.20 - $100.80 ($56.10)
Netting	(18		)	(18		)
Total derivative contracts	$	113		$	1,043

Level 3 Fair Value Sensitivity

Gas Options, Electricity Options, and Tolling Arrangements

The fair values of option contracts and tolling arrangements contain intrinsic value and time value. Intrinsic value is the difference between the market price and strike price of the underlying commodity. Time value is made up of several components, including volatility, time to expiration, and interest rates. The fair value of option contracts changes as the underlying commodity price moves away or towards the strike price. The option model for tolling arrangements reflects plant specific information such as operating and start-up costs.

For tolling arrangements and certain gas and power option contracts where SCE is the buyer, increases in volatility of the underlying commodity prices would result in increases to fair value as it represents greater price movement risk. As power and gas prices increase, the fair value of the option contracts and tolling arrangements tends to increase. The valuation of power option contracts and tolling arrangements is also impacted by the correlation between gas and power prices. As the correlation increases, the fair value of power option contracts and tolling arrangements tends to decline.

Forward Power Contracts

Generally, an increase (decrease) in long-term forward power prices at illiquid locations where SCE is the buyer relative to the contract price will increase (decrease) the fair value.

CRRs

Where SCE is the buyer, generally increases (decreases) in forecasted load in isolation would result in increases (decreases) to the fair value. In general, an increase (decrease) in electricity and gas prices at illiquid locations tends to result in increases (decreases) to fair value; however, changes in electricity and gas prices in opposite directions may have varying results on fair value.

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Nuclear Decommissioning Trusts

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

Fair Value of Long-Term Debt Recorded at Carrying Value

The carrying value and fair value of long-term debt are:

	September 30, 2012				December 31, 2011
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current portion	$	8,828	$	10,604	$	8,431	$	10,129

Fair value of short-term and long-term debt is classified as Level 2 and is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit information.

The carrying value of trade receivables and payables, other investments, and short-term debt approximates fair value.

Note 5.    Debt and Credit Agreements

Long-Term Debt

In March 2012, SCE issued $400 million of 4.05% first and refunding mortgage bonds due in 2042. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

Credit Agreements and Short-Term Debt

During the second quarter of 2012, SCE replaced its credit facilities with a $2.75 billion five-year revolving credit facility that matures in May 2017. The credit facility is generally used to support commercial paper and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working capital requirements to support operations and capital expenditures. At September 30, 2012, SCE's outstanding commercial paper supported by the credit facility was $380 million at a weighted-average interest rate of 0.43%. At September 30, 2012, letters of credit issued under SCE's credit facility aggregated $196 million and are scheduled to expire in twelve months or less.

At December 31, 2011, the outstanding commercial paper was $419 million at a weighted-average interest rate of 0.44%.

Note 6.    Derivative Instruments and Hedging Activities

Commodity Price Risk

SCE is exposed to commodity price risk which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces customer exposure to variability in market prices related to SCE's power and gas activities. As part of this program, SCE enters into options, swaps, forwards, tolling arrangements and CRRs. These transactions are approved by the CPUC or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the energy resource recovery account ("ERRA") balancing account, and as a result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.

SCE's electricity price exposure arises from energy purchased from and sold to wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities and power purchase agreements.

SCE's natural gas price exposure arises from natural gas purchased for the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and power purchase agreements in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.

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Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging activities:

		Economic Hedges
Commodity	Unit of Measure	September 30, 2012	December 31, 2011
Electricity options, swaps and forwards	GWh	18,304	30,881
Natural gas options, swaps and forwards	Bcf	142	300
Congestion revenue rights	GWh	140,263	166,163
Tolling arrangements	GWh	102,123	104,154

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at September 30, 2012:

	Derivative Assets									Derivative Liabilities
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	55		$	80		$	135		$	177		$	1,002		$	1,179		$	1,044
Netting and collateral	(18		)	(6		)	(24		)	(49		)	(19		)	(68		)	(44		)
Total	$	37		$	74		$	111		$	128		$	983		$	1,111		$	1,000

The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2011:

	Derivative Assets									Derivative Liabilities
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Non-trading activities
Economic hedges	$	86		$	85		$	171		$	303		$	856		$	1,159		$	988
Netting and collateral	(21		)	(15		)	(36		)	(37		)	(51		)	(88		)	(52		)
Total	$	65		$	70		$	135		$	266		$	805		$	1,071		$	936

Income Statement Impact of Derivative Instruments

SCE recognizes realized gains and losses on derivative instruments as purchased power expense and expects that such gains or losses will be part of the purchase power costs recovered from customers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from customers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.

The following table summarizes the components of economic hedging activity:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Realized gains (losses)	$	(77	)	$	(58	)	$	(199	)	$	(132	)
Unrealized gains (losses)	(91		)	(110		)	(29		)	(433		)

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Contingent Features/Credit Related Exposure

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

Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a credit-risk-related contingent feature. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features was $113 million and $216 million as of September 30, 2012 and December 31, 2011, respectively, for which SCE has posted no collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2012, SCE would be required to post $25 million of collateral.

Counterparty Default Risk Exposure

As part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments. Substantially all of the contracts that SCE has executed with counterparties are either entered into under SCE's procurement plan which has been pre-approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may temporarily affect cash flows.

To manage credit risk, SCE 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. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary.

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the related positions. SCE nets counterparty receivables and payables where balances exist under master netting agreements. SCE presents the portion of its margin and collateral deposits netted with its derivative positions on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to counterparties:

(in millions)	September 30, 2012		December 31, 2011
Collateral provided to counterparties:
Offset against derivative liabilities	$	44	$	51
Reflected in other current assets	9		17

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Note 7.    Income Taxes

Effective Tax Rate

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Income before income taxes	$	564		$	666		$	1,186		$	1,378
Provision for income tax at federal statutory rate of 35%	197			233			415			482
Increase (decrease) in income tax from:
State tax – net of federal benefit	10			31			30			61
Property-related	(19		)	(18		)	(39		)	(38		)
Other	(12		)	(1		)	(22		)	(9		)
Total income tax expense	$	176		$	245		$	384		$	496
Effective tax rate	31		%	37		%	32		%	36		%

The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.

Accounting for Uncertainty in Income Taxes

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)	2012			2011
Balance at January 1,	$	373		$	329
Tax positions taken during the current year:
Increases	23			58
Tax positions taken during a prior year:
Increases	154			44
Decreases	(33		)	(34		)
Decreases for settlements during the period	—			—
Balance at December 31,	$	517		$	397

Tax Dispute

Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 are currently under review by the Franchise Tax Board. The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010. This included a proposed adjustment to disallow a component of SCE's repair allowance deduction, which if sustained, would result in a federal tax payment of approximately $95 million, including interest through September 30, 2012. Edison International disagrees with the proposed adjustment and filed a protest with the IRS in the first quarter of 2011.

Repair Deductions

In 2009, Edison International made a voluntary election to change its tax accounting method for certain repair costs incurred on SCE's transmission, distribution and generation assets. In August 2011, the IRS issued guidance on repair deductions and changes in accounting method related to transmission and distribution assets. Based on this guidance, SCE included a second change in tax accounting method on repair costs in its 2011 tax return. Guidance for generation assets is pending. Regulatory treatment for the incremental deductions taken after the voluntary election to change SCE's tax accounting method for certain repair costs is part of SCE's 2012 GRC. Due to the pending regulatory decision, SCE has not recognized an earnings benefit

15

or regulatory asset related to this method change and incremental deductions taken in 2009, 2010 and 2011. In October 2012, the CPUC assigned administrative law judge issued a proposed GRC decision, which if adopted, would result in an earnings benefit of approximately $230 million attributable to flow through treatment of 2009 – 2011 vintage year activity. SCE would also record an earnings benefit related to 2012 vintage year activity consistent with the rate making treatment.

Note 8.    Compensation and Benefit Plans

Pension Plans

As part of the pension funding provisions contained in the Surface Transportation Extension Act of 2012 passed by Congress, SCE's projected 2012 plan contributions have been reduced to $154 million from $263 million, which resulted in a third quarter regulatory adjustment reflected in the table below. SCE made contributions of $136 million during the nine months ended September 30, 2012. The 2012 GRC proposed decision authorized contributions of $168 million with recovery of any undercollection through the continuation of the existing balancing account mechanism. A final GRC decision is expected by year-end. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Service cost	$	46		$	38		$	120		$	114
Interest cost	45			47			135			141
Expected return on plan assets	(52		)	(56		)	(162		)	(168		)
Amortization of prior service cost	1			2			3			6
Amortization of net loss	15			4			45			12
Expense under accounting standards	$	55		$	35		$	141		$	105
Regulatory adjustment (deferred)	(57		)	(6		)	(3		)	(18		)
Total expense recognized	$	(2	)	$	29		$	138		$	87

Postretirement Benefits Other Than Pensions

SCE made contributions of $15 million during the nine months ended September 30, 2012 and expects to make $47 million of additional contributions during the remainder of 2012. SCE's 2012 annual contributions are expected to be recovered through CPUC-approved regulatory mechanisms. Annual contributions are expected to be, at a minimum, equal to the total annual expense for these plans. Benefits under these plans, with some exceptions, are generally unvested and subject to change.

Expense components are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Service cost	$	12		$	10		$	36		$	30
Interest cost	28			31			84			93
Expected return on plan assets	(27		)	(27		)	(81		)	(81		)
Special termination benefits1	3			—			3			—
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	11			9			33			27
Total expense	$	18		$	14		$	48		$	42

¹  Due to the reduction in the workforce at San Onofre, SCE has incurred costs for enhanced retiree health care coverage. See below for further information.

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Transfer of Certain Postretirement Benefits to Edison International

In March 2012, Edison International agreed to assume the liabilities for active employees of SCE and its subsidiaries under the specified plans related to deferred compensation and executive postretirement benefits. SCE is obligated to reimburse Edison International upon settlement of liabilities on an after tax basis. Included in the consolidated balance sheet at September 30, 2012 was $116 million related to this obligation.

San Onofre Workforce Reduction

In August 2012, SCE announced plans for downsizing to bring the San Onofre organization and cost structure in line with industry peers. SCE plans to reduce the San Onofre workforce by 730 employees to 1,500 employees beginning in the fourth quarter of 2012 and continuing in 2013. At September 30, 2012, SCE had recorded $30 million in estimated cash severance costs (SCE's share) related to the non-represented employee workforce reduction.

Note 9.    Commitments and Contingencies

Third-Party Power Purchase Agreements

During the nine months ended September 30, 2012, SCE had power purchase contracts with additional commitments estimated to be: $17 million in 2014, $43 million in 2015, $66 million in 2016 and $970 million for the period remaining thereafter. Some of these power purchase agreements are classified as operating leases. The additional commitments for these leases, which are also included in the amounts above, are estimated to be: $21 million in 2015, $45 million in 2016 and $942 million for the period remaining thereafter.

Indemnities

Indemnity Provided as Part of the Acquisition of Mountainview

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

Mountainview Filter Cake Indemnity

SCE has indemnified the City of Redlands, California in connection with Mountainview's California Energy Commission permit for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.

Other 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 indemnities for specified environmental liabilities and income taxes with respect to assets sold. SCE's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties. SCE has not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.

Contingencies

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

San Onofre Outage, Inspection and Repair Issues

SCE replaced four steam generators at San Onofre Units 2 and 3 in 2010 and 2011, respectively. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. Unit 3 was safely taken off-line. At the time, San Onofre Unit 2 was off-line for a planned outage when areas of unexpected wear in some of its

17

heat transfer tubes were found. Both Units have remained off-line for extensive inspections, testing and analysis of their steam generators. Each Unit will be restarted only when and if SCE determines that it is safe to do so and when start-up has been approved by the NRC pursuant to the terms of a Confirmatory Action Letter (“CAL”) issued by the NRC in March 2012. The CAL requires NRC permission to restart Unit 2 and Unit 3 and outlines actions SCE must complete before permission to restart either Unit may be sought. In October 2012, SCE submitted to the NRC a response to the CAL and restart plans for Unit 2. SCE proposed to restart Unit 2 and operate at a reduced power level (70%) for approximately five months, followed by a mid-cycle scheduled outage.

In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million after adjustment for inflation) for SCE's 78.21% share of San Onofre to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $594 million through September 30, 2012 on the steam generator replacement project, including $95 million reflected in construction work in progress primarily related to the disposal of the replaced steam generators. Those expenditures remain subject to CPUC reasonableness review. Final costs for the project will not be known until after disposal of the original steam generators is completed.

As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre are being purchased in the market by SCE (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market costs through September 30, 2012 were approximately $221 million, net of avoided nuclear fuel costs, and are recoverable through the ERRA balancing account subject to CPUC reasonableness review. Because of the uncertainties associated with when and at what output levels the Units will or may be returned to service, total potential market power costs cannot be estimated at this time.

Through September 2012, SCE's share of incremental inspection and repair costs totaled $96 million for both Units. At September 30, 2012, the repairs to restart Unit 2 at the reduced power levels described above have been substantially completed. The costs for Unit 2 may increase following NRC review under the CAL and any new developments that may result from further analysis, testing and inspection, and there is no assurance that start-up of Unit 2 will occur as described above. Total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain.

In addition to the amounts for inspection and repair and market power costs discussed below, SCE has collected through customer rates an estimated $625 million of revenue through third quarter 2012 (based on current authorized revenue requirements) associated with the plant. SCE's total 2012 San Onofre annual revenue requirement, including the 2012 GRC proposed decision, is approximately $820 million, made up of $170 million in refueling outage, nuclear fuel and decommissioning costs and $650 million for its direct operating and maintenance costs, depreciation and return on its investment in San Onofre Unit 2, Unit 3 and related common plant. At September 30, 2012, SCE's rate base and net investment and inventory associated with San Onofre was $1.2 billion and $2.1 billion, respectively.

Under California Public Utilities Code Section 455.5, SCE is required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months (not including preplanned outages). SCE will provide such notice to the CPUC on November 1, 2012 for Unit 3 and expects to do so by December 6, 2012 for Unit 2. The CPUC is required within 45 days of SCE's notice for a particular Unit to initiate an investigation to determine whether to remove from customer rates some or the entire revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5 any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation.

In October 2012, in advance of SCE's required notification under Section 455.5, the CPUC issued an order instituting investigation ("OII") that will consolidate all San Onofre issues in related regulatory proceedings and consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, market power costs, capital and operations and maintenance costs, and seismic study costs. The order requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent included in rates, collected subject to refund. The order also states that the CPUC will determine whether to order the immediate removal, effective as of the date of the order, of all costs related to San Onofre from SCE's rates, with placement of those costs in a deferred debit account pending the return of one or both Units to useful service, or other possible action. SCE will file its response to the order by November 26, 2012. SCE must also file testimony by December 10, 2012 detailing proposed rate adjustments due to the outages, including the amount of San Onofre costs in current rates, the amount to be removed, if any, the effective date, and related information. A pre-hearing conference will be scheduled early in 2013 after the issuance of a Scoping Memo by the Assigned Commissioner.

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In parallel with the order instituting investigation, the 2012 GRC proposed decision would, if adopted, require SCE to track San Onofre-related costs in a memorandum account subject to refund, beginning January 1, 2012. SCE would be required by January 30, 2013 to file an application for reasonableness review of these costs and the proposed decision would allow that application to be consolidated with other proceedings. The 2012 GRC proposed decision also approves expenditures incurred through 2011 for the high pressure turbine project, but disallows recovery for post-2011 expenditures associated with the project and directs SCE to record those costs in either the memorandum account or seek future rate recovery in the next GRC. SCE anticipates that the inter-relationship between the Section 455.5 process and the issues to be reviewed in the investigation or pursuant to a final decision in the GRC will be addressed by the CPUC as it continues to develop the scope of the issues to be consolidated within the investigation.

The steam generators were designed and supplied by MHI and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions. In September 2012, SCE submitted an invoice to MHI for costs paid through June 30, 2012 in the amount of $45 million for both SCE's and the other co-owners' share of steam generator repair costs. SCE expects to continue to invoice MHI for costs incurred. No amounts have been recognized in the financial statements as of September 30, 2012.

San Onofre carries both property damage and outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. In October 2012, SCE filed separate proofs of loss for Unit 2 and Unit 3 under the outage policy. Pursuant to these proofs of loss SCE is seeking the weekly indemnity amounts provided under the policy for each Unit. Because the outage is ongoing, SCE will supplement these proofs of loss in the future. No amounts have been recognized in SCE's financial statements, pending further actions by NEIL. To the extent any costs are recovered under the outage policy, SCE expects to refund those amounts to ratepayers through the ERRA balancing account.

SCE will pursue recoveries arising from available agreements, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements.

CPSD Investigations

San Gabriel Valley Windstorm Investigation

In November 2011, a windstorm resulted in significant damage to SCE’s electric system and service outages for SCE customers primarily in the San Gabriel Valley. The CPUC directed its Consumer Protection and Safety Division (“CPSD”) to conduct an investigation focused on the cause of the outages, SCE’s service restoration effort, and SCE’s customer communications during the outages. The CPSD issued its preliminary report on February 1, 2012. The report asserts that SCE and others with whom SCE shares utility poles violated certain CPUC safety rules applicable to overhead line construction, maintenance and operation, which may have caused the failures of affected poles and supporting cables. The report also concludes that SCE’s restoration time was not adequate and makes other assertions. Additionally, the report contends that SCE violated CPUC rules by failing to preserve evidence relevant to the investigation when it did not retain damaged poles that were replaced following the windstorm. If theCPUC issues an OII regarding this matter and SCE is found to have violated any CPUC rules, it could face penalties. SCE is unable to estimate a possible loss or range of loss associated with any penalties that may be imposed by the CPUC on SCE.

The proposed decision in SCE’s 2012 GRC would direct SCE to, among other things, make an assessment of a representative sampling of its loaded poles to determine their conformance with current legal standards and report by January 31, 2013 on the results of this assessment. The cost of any large scale review of poles or other equipment for safety compliance, as well as any remediation measures required to assure compliance, could be significant.

Malibu Fire Order Instituting Investigation

Following a 2007 wildfire in Malibu, California, the CPUC issued an OII to determine if any statutes, CPUC general orders, rules or regulations were violated by SCE or telecomm providers (“OII Respondents”) that shared the use of three failed power poles in the wildfire area. The CPSD has alleged, among other things, that the poles were overloaded, that the OII Respondents violated the CPUC's rules governing the design, construction and inspection of poles and misled the CPUC during its investigation of the fire, and that SCE failed to preserve evidence relevant to the investigation. In October 2011, the CPSD proposed that the OII Respondents be assessed penalties of approximately $99 million, with SCE being allocated

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approximately $50 million of the total. SCE has denied the allegations and believes the proposed penalties are excessive. In September 2012, the CPUC approved a partial settlement between the CPSD and three telecomm providers, leaving SCE and a non-settling telecomm provider as the remaining respondents. The partial settlement did not resolve any of the claims against SCE or the remaining telecomm provider.

Four Corners New Source Review Litigation

In October 2011, four private environmental organizations filed a CAA citizen lawsuit against the co-owners of Four Corners. The complaint alleges that certain work performed at the Four Corners generating units 4 and 5, over the approximate periods of 1985-1986 and 2007-present, constituted plant “major modifications” and the plant's failure to obtain permits and install best available control technology ("BACT") violated the PSD requirements and the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violations of BACT air emissions limits. The lawsuit seeks injunctive and declaratory relief, civil penalties, including a mitigation project and litigation costs. In November 2010, SCE entered into an agreement to sell its ownership interest in generating units 4 and 5 to APS. The sale is subject to certain closing conditions, including APS obtaining a long-term fuel supply agreement for the plant, and is expected to close no earlier than December 2012. Under the agreement SCE would remain responsible for its pro rata share of certain environmental liabilities, including penalties arising from environmental violations prior to the sale, but SCE would not be liable for any costs of installing BACT or other costs related to continuing or extending Four Corners operations. SCE is unable to estimate a possible loss or range of loss associated with this matter.

Environmental Remediation

SCE 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. SCE 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, operation and maintenance, monitoring and site closure. Unless there is a single probable amount, SCE records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.

At September 30, 2012, SCE's recorded estimated minimum liability to remediate its 25 identified material sites (sites in which the upper end of the range of the costs is at least $1 million) and 33 identified immaterial sites was $113 million (which includes $78 million related to San Onofre) and $3 million, respectively. Of the $116 million total environmental remediation liability, $113 million has been recorded as a regulatory asset. SCE expects to recover $31 million through an incentive mechanism that allows SCE to recover 90% of its environmental remediation costs at certain sites (SCE may request to include additional sites) and $82 million through a mechanism that allows SCE to recover 100% of the costs incurred at certain sites through customer rates. SCE'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 SCE 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.

The ultimate costs to clean up SCE'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. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs at the identified material sites and immaterial sites could exceed its recorded liability by up to $185 million and $6 million, respectively. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.

SCE expects to clean up and mitigate its identified sites over a period of up to 30 years. Remediation costs for 2012 and in each of the next four years are expected to range from $7 million to $14 million. Costs incurred for the nine months ended September 30, 2012 and 2011 were $5 million and $9 million, respectively.

Based upon the CPUC's regulatory treatment of environmental remediation costs, SCE believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to estimates.

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Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $12.6 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor licensees. 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, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.

Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.

NEIL, a mutual insurance company owned by entities with nuclear facilities, issues primary property damage, decontamination and excess property damage and accidental outage insurance policies. At San Onofre and Palo Verde, property damage insurance covers losses up to $500 million, including decontamination costs. Decontamination liability and excess property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than the federal requirement of a minimum of approximately $1.1 billion. Property damage insurance also covers damages caused by acts of terrorism up to specified limits. Additional outage insurance covers part of replacement power expenses during an accident-related nuclear unit outage.

If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $49 million per year. Insurance premiums are charged to operating expense.

Wildfire Insurance

Severe wildfires in California have given rise to large damage claims against California utilities for fire-related losses alleged to be the result of the failure of electric and other utility equipment. Invoking a California Court of Appeal decision, plaintiffs pursuing these claims have relied on the doctrine of inverse condemnation, which can impose strict liability (including liability for a claimant's attorneys' fees) for property damage. On September 15, 2012, SCE's parent, Edison International, renewed its insurance coverage, which included coverage for SCE's wildfire liabilities up to a $550 million limit (with a self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in additional self-insured costs in the event of multiple wildfire occurrences during the policy period (September 15, 2012 to August 31, 2013). SCE may experience coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.

Spent Nuclear Fuel

Under federal law, the 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 contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.

In June 2010, the United States Court of Federal Claims issued a decision granting SCE and the San Onofre co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. SCE received payment from the federal government in the amount of the damage award in November 2011. SCE has returned to the San Onofre co-owners their respective share of the damage award paid. SCE, as operating agent, filed a lawsuit on behalf of the San Onofre owners against the DOE in the Court of Federal Claims in December 2011 seeking damages of approximately $98 million for the period from January 1, 2006 to December 31, 2010 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel. Additional legal action would be necessary to recover damages incurred after December 31, 2010. Any damages recovered by SCE are subject to CPUC review as to how these amounts would be distributed among customers, shareholders, or to offset fuel decommissioning or storage costs.

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Note 10.    Environmental Developments

Greenhouse Gas Regulation

In March 2012, the US EPA announced proposed carbon dioxide emissions limits for new power plants. The status of the US EPA's efforts to develop greenhouse gas emissions performance standards for existing plants is unknown.

In June 2012, the U.S. Court of Appeals for the D.C. Circuit dismissed the challenge by industry groups and some states to the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule." In August 2012, states and industry groups challenging the rule filed a petition seeking to have the decision reviewed by the full District of Columbia Circuit.

In July 2012, the US EPA published a final rule maintaining the CO₂ equivalent emissions thresholds (for purposes of PSD and Title V permitting) originally established in the GHG tailoring rule.

Greenhouse Gas Litigation

In March 2012, the federal district court in Mississippi dismissed, in its entirety, the purported class action complaint filed by private citizens in May 2011, naming a large number of defendants, including SCE and other Edison International subsidiaries, for damages allegedly arising from Hurricane Katrina. In April 2012, the plaintiffs filed an appeal with the Fifth Circuit Court of Appeals. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of greenhouse gases that have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal district court where the current case has been filed.

In September 2012, a three-judge panel of the U.S Court of Appeals for the Ninth Circuit affirmed the dismissal of a case brought against SCE's parent company, Edison International, and other defendants, by the Alaskan Native Village of Kivalina. In October 2012, the plaintiffs requested a rehearing by a larger panel of Ninth Circuit judges.

Note 11.    Supplemental Cash Flows Information

SCE's supplemental cash flows information is:

	Nine months ended September 30,
(in millions)	2012			2011
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized	$	394		$	369
Tax refunds – net	(243		)	(126		)
Noncash investing and financing activities:
Details of debt exchange:
Pollution-control bonds redeemed	$	—		$	(86	)
Pollution-control bonds issued	—			86
Dividends declared but not paid:
Preferred and preference stock	$	6		$	12

Accrued capital expenditures at September 30, 2012 and 2011 were $414 million and $362 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.

Note 12.    Preferred and Preference Stock

During the first quarter of 2012, SCE issued 350,000 shares of 6.25% Series E Preference Stock (cumulative, $1,000 liquidation value). The Series E preference shares may not be redeemed prior to February 1, 2022. After February 1, 2022, SCE may at its option, redeem the shares, in whole or in part for a price of $1,000 per share plus accrued and unpaid dividends, if any. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings and to fund SCE's capital program.

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During the second quarter of 2012, SCE issued 190,004 shares of 5.625% Series F Preference Stock (cumulative, $2,500 liquidation value) to SCE Trust I, a special purpose entity formed to issue trust securities as discussed in Note 3. Variable Interest Entities. The Series F Preference Stock may not be redeemed prior to June 15, 2017. After June 15, 2017, SCE may at its option, redeem the shares, in whole or in part for a price of $2,500 per share plus accrued and unpaid dividends, if any.

The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings, for general corporate purposes and to redeem and retire $75 million of the Series A Preference Stock.

Note 13.    Regulatory Assets and Liabilities

Regulatory Assets

Regulatory assets included on the consolidated balance sheets are:

(in millions)	September 30, 2012		December 31, 2011
Current:
Regulatory balancing accounts	$	108	$	223
Energy derivatives	161		264
Other	1		7
Total Current	270		494
Long-term:
Deferred income taxes – net	2,148		2,020
Pensions and other postretirement benefits	1,657		1,703
Energy derivatives	964		836
Unamortized investments - net	484		484
Unamortized loss on reacquired debt	233		249
Nuclear-related investment – net	145		156
Regulatory balancing accounts	102		69
Other	335		298
Total Long-term	6,068		5,815
Total Regulatory Assets	$	6,338	$	6,309

Regulatory Liabilities

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	September 30, 2012		December 31, 2011
Current:
Regulatory balancing accounts	$	478	$	661
Other	15		9
Total Current	493		670
Long-term:
Costs of removal	2,745		2,697
Asset Retirement Obligations	1,378		1,105
Regulatory balancing accounts	1,119		864
Other	7		4
Total Long-term	5,249		4,670
Total Regulatory Liabilities	$	5,742	$	5,340

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Note 14.    Other Investments

Nuclear Decommissioning Trusts

Future decommissioning costs of removal of nuclear assets are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $23 million per year through SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.

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

		Amortized Cost				Fair Value
(in millions)	Longest Maturity Dates	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Stocks	—	$	957	$	865	$	2,227	$	1,899
Municipal bonds	2054	520		625		654		756
U.S. government and agency securities	2042	526		516		589		580
Corporate bonds	2054	287		259		374		317
Short-term investments and receivables/payables	One-year	147		38		153		40
Total		$	2,437	$	2,303	$	3,997	$	3,592

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $428 million and $962 million for the three months ended September 30, 2012 and 2011, respectively, and $1.5 billion and $2.1 billion for the nine months ended September 30, 2012 and 2011, respectively. Unrealized holding gains, net of losses, were $1.6 billion and $1.3 billion at September 30, 2012 and December 31, 2011, respectively.

The following table sets forth a summary of changes in the fair value of the trust:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Balance at beginning of period	$	3,810		$	3,657		$	3,592		$	3,480
Gross realized gains	13			46			54			81
Gross realized losses	—			(5		)	(5		)	(5		)
Unrealized gains (losses) – net	156			(305		)	272			(199		)
Other-than-temporary impairments	(7		)	(22		)	(30		)	(35		)
Interest, dividends, contributions and other	25			22			114			71
Balance at end of period	$	3,997		$	3,393		$	3,997		$	3,393

Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.

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Note 15.    Other Income and Expenses

Other income and expenses are as follows:

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2012		2011		2012		2011
Other income:
Equity allowance for funds used during construction	$	23	$	18	$	71	$	74
Increase in cash surrender value of life insurance policies	6		6		20		19
Other	7		2		12		10
Total other income	$	36	$	26	$	103	$	103
Other expenses:
Civic, political and related activities and donations	$	5	$	6	$	22	$	21
Other	4		4		14		14
Total other expenses	$	9	$	10	$	36	$	35

Note 16.     Planned Sale of Interest in Four Corners

In November 2010, SCE entered into an agreement to sell its ownership interest in Units 4 and 5 of the Four Corners Generating Station, a coal-fired electric generating facility in New Mexico, to the operator of the facility, Arizona Public Service Company. During 2012, the CPUC and the Arizona Corporation Commission ("ACC") approved the transaction. As part of its sale approval, the ACC stipulated that the sale cannot close earlier than December 1, 2012 which under the adjustment mechanism set forth in the sales agreement would reduce the sale price from $294 million to $279 million. The price is also subject to further adjustments. The closing of the sale is contingent upon the receipt of other specified closing conditions, including APS obtaining a long-term fuel supply agreement for the plant. The sale agreement provides for either party to terminate if it is not completed by December 31, 2012. Any gain on the sale will be for the benefit of SCE's customers and, therefore, will not affect SCE's earnings.

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ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect SCE's current expectations and projections about future events based on SCE'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 SCE 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 from those currently expected, or that otherwise could impact SCE, include, but are not limited to:

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

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

• possible customer bypass or departure due to technological advancements or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable;

• risks inherent in the construction of transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable the acceptance of power delivery), and governmental approvals;

• risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts;

• risk that Units 2 and/or Unit 3 at San Onofre may not recommence operations or may require extensive repairs or replacement of the steam generators; with the cost of the related outcome not being recoverable from SCE's supplier, insurance coverage or through regulatory processes;

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

• cost of capital and the ability to borrow funds and access to capital markets on reasonable terms;

• the cost and availability of electricity including the ability to procure sufficient resources to meet expected customer needs to replace power that would have been provided by San Onofre but for the current outage or in the event of other power plant outages or significant counterparty defaults under power-purchase agreements;

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

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

• governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by Independent System Operators and Regional Transmission Organizations;

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

• cost and availability of labor, equipment and materials;

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

• effects of legal proceedings, changes in or interpretations of tax laws, rates or policies;

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• potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;

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

• 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;

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

• risk that competing transmission systems will be built by merchant transmission providers in SCE's service area; and

• weather conditions and natural disasters.

Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in SCE's 2011 Form 10-K, including the "Risk Factors" section in Part I, Item 1A. Readers are urged to read this entire report, including the information incorporated by reference, as well as the 2011 Form 10-K, and carefully consider the risks, uncertainties and other factors that affect SCE's business. Forward-looking statements speak only as of the date they are made and SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE with the U.S. Securities and Exchange Commission.

The MD&A for the three- and nine-month periods ended September 30, 2012 discusses material changes in the consolidated financial condition, results of operations and other developments of SCE since December 31, 2011 and as compared to the three- and nine-month periods ended September 30, 2011. This discussion presumes that the reader has read or has access to SCE's MD&A for the calendar year 2011 (the "year-ended 2011 MD&A"), which was included in the 2011 Form 10-K.

MANAGEMENT OVERVIEW

Highlights of Operating Results

	Three months ended September 30,							Nine months ended September 30,
(in millions)	2012		2011		Change			2012		2011		Change
Core earnings	$	363	$	406	$	(43	)	$	736	$	838	$	(102	)
Non-core items	—		—		—			—		—		—
Net income available for common stock	$	363	$	406	$	(43	)	$	736	$	838	$	(102	)

SCE's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings for financial planning and for analysis of performance. Core earnings are also used when communicating with analysts and investors regarding SCE's earnings results to facilitate comparisons of the performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to SCE less income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of certain tax, regulatory or legal matters or proceedings.

SCE's 2012 core earnings decreased $43 million and $102 million for the quarter and year-to-date, respectively. Core earnings in both periods decreased primarily due to a delay in the 2012 CPUC General Rate Case decision as higher depreciation and net interest expenses are not being recovered in currently authorized revenue, as well as higher costs at San Onofre. SCE has incurred $48 million and $96 million of incremental steam generator inspection and repair costs related to outages at San Onofre for the quarter and year-to-date periods in 2012, respectively, and $30 million in severance costs. These costs were partially offset by other operations and maintenance cost reductions in both periods. The revenue requirement ultimately adopted by the CPUC will be retroactive to January 1, 2012.

2012 CPUC General Rate Case

As discussed in the year-ended 2011 MD&A, SCE's 2012 GRC application, which requested a 2012 base rate revenue requirement of $6.29 billion, has been under submission to the CPUC.

On October 19, 2012, the CPUC assigned administrative law judge issued a proposed decision, which, if adopted, would result in a 2012 base rate revenue requirement of $5.69 billion, a decrease of $601 million from SCE's requested revenue requirement, primarily related to decreases in operations and maintenance expenses with some plant-related capital

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reductions, including potential disallowances of recorded capital investments for specific projects. The proposed decision, if adopted, would result in an increase of approximately $400 million over currently authorized revenue. The proposed decision approves San Onofre costs subject to refund and reasonableness review and includes a requirement to track those costs in a memorandum account. See “—San Onofre” below for further information. The proposed decision also accepts SCE's requested rate-making treatment of tax repair deductions. See "SCE Notes to Consolidated Financial Statements—Note 7. Income Taxes" for further discussion.

The proposed decision would allow a post-test year ratemaking methodology that escalates capital additions by 3.05% for 2013 and 2.93% for 2014. It would also allow operations and maintenance expense to be escalated for 2013 and 2014 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology adopted in the proposed decision would result in a revenue requirement of $6.08 billion for 2013 and $6.43 billion for 2014.

SCE is currently recognizing revenue largely based on the 2011 authorized revenue requirement. The CPUC has authorized the establishment of a GRC memorandum account, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

SCE is required to file comments within 20 days of receiving the proposed decision. The final CPUC decision could result in material changes to the proposed decision. A final CPUC decision is expected by year-end.

2013 Cost of Capital Application

In June 2012, the CPUC issued an order in the 2013 Cost of Capital proceeding consolidating SCE's 2013 application with the three other California investor-owned utilities' applications and splitting the proceeding into two phases. The first phase will address the 2013 ratemaking capital structure and cost of capital for the utilities and contemplates a final decision in December 2012. The second phase will consider whether the current multi-year mechanism should be continued or modified. A final decision for the second phase is expected in April 2013.

SCE's 2013 cost of capital application, which was filed in April 2012, requested a ratemaking capital structure of 43% long-term debt, 9% preferred equity and 48% common equity consistent with the current capital structure. In October 2012, SCE submitted an update to its requested cost of capital further reducing its current cost of capital as follows: cost of long-term debt from 6.22% to 5.49%, authorized cost of preferred equity from 6.01% to 5.79% and authorized return on common equity from 11.5% to 11.1%. The application also requested the continuation of the current multi-year mechanism, which would have retained the authorized capital structure through 2015 with annual adjustments of the cost components if certain thresholds are reached.

San Onofre

Outage, Inspection and Repair Issues

As discussed in the 2011 Form 10-K, four replacement steam generators were installed at San Onofre Units 2 and 3 in 2010 and 2011, respectively. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. Unit 3 was safely taken off-line. At the time, San Onofre Unit 2 was off-line for a planned outage when areas of unexpected wear in some of its heat transfer tubes were found. Both Units have remained off-line for extensive inspections, testing and analysis of their steam generators. Each Unit will be restarted only when and if SCE determines that it is safe to do so and when start-up has been approved by the NRC pursuant to the terms of a Confirmatory Action Letter (“CAL”) issued by the NRC in March 2012. The CAL requires NRC permission to restart Unit 2 and Unit 3 and outlines actions SCE must complete before permission to restart either Unit may be sought. In October 2012, SCE submitted to the NRC a response to the CAL and restart plans for Unit 2 as described below.

Tube Leak and Repairs

The water leak in the Unit 3 steam generator was caused by excessive wear resulting from tube-to-tube contact in the area of the leak. During the inspection and testing of the Unit 3 steam generators, additional pressure tests of certain tubes were completed to determine the safety significance of the wear. Eight of the 129 tubes subjected to the additional tests failed the tests for structural integrity as a result of excessive wear, and the NRC was notified as required. The same areas were re-inspected in the Unit 2 steam generators using a more sensitive inspection method than had previously been employed, and similar wear from tube-to-tube contact was found on two tubes in one of the steam generators at wear levels below the detection capability of the initial inspection. Earlier tests performed on the Unit 2 steam generators during the planned outage additionally found levels of unexpected wear at points where some tubes were in contact with retainer bars of the tube support structure. Subsequent inspections on Unit 3 found similar tube-to-support structure wear.

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As a result of these findings, SCE has plugged and removed from service all tubes showing excessive wear in each of the steam generators. In addition, SCE preventively plugged all tubes in contact with retainer bars or in the area of the tube bundles where tube-to-tube contact occurred. Each steam generator has over 9,700 heat transfer tubes and is designed to include sufficient tubes to accommodate a need to remove some from service for a variety of reasons, and the tubes that SCE has removed from service are within this margin.

A team of outside experts was assembled to assist SCE and Mitsubishi Heavy Industries, Inc. (“MHI”), the manufacturer of the steam generators, in the analysis of the causes of the tube-to-tube wear and potential remedial actions. As a result of their work, SCE understands that the tube-to-tube contact arises from excessive vibration of the tubes in certain areas of the steam generators. The excessive vibration that caused the tube-to-tube wear on Unit 3 resulted from a phenomenon called fluid elastic instability. This phenomenon arises from a combination of thermal hydraulic conditions (steam velocity and moisture content of the steam), and ineffectiveness of the tube supports in the areas where the vibration occurs. Unit 2 is susceptible to the same thermal hydraulic conditions as Unit 3, but the Unit 2 supports largely remained effective for the entire time that it operated as compared to Unit 3. This difference is likely the result of manufacturing differences between the pairs of steam generators in the two Units.

SCE's restart plans for Unit 2 and its response to the CAL are based on work done by engineering groups of three independent firms with expertise in steam generator design and manufacturing. Restart plans for only Unit 2 were submitted because of the extensive tube-to-tube wear in Unit 3, which was not experienced in Unit 2 (in which only one point of tube-to-tube wear between two tubes was identified). Using different methodologies, each independent outside engineering group concluded that it would be safe to restart Unit 2 and operate at a reduced power level (70%) for approximately five months, followed by a mid-cycle scheduled outage. The power level is being reduced to avoid the steam velocity and moisture content conditions that cause fluid elastic instability. The five month operating period is less than half the time Unit 3 operated and was validated by the independent experts as providing a safety margin to provide assurance of safe operation. In addition to these requirements, the restart plan covers repairs, corrective actions and operating parameters and also includes additional monitoring, detection and response activities.

Inasmuch as Unit 3 had much more tube-to-tube wear than Unit 2, it is not clear at this time whether Unit 3 will be able to restart without extensive additional repairs and corrective actions. Unit 3 will not restart this year and it is uncertain when or whether a restart plan will be submitted. The Unit 3 reactor is de-fueled and SCE is placing appropriate systems in a lay-up condition while analysis and testing continue. SCE is also engaged in the analysis of what repairs, if any, could be undertaken to restore the steam generators on both Units to their originally specified capabilities safely, but it has not determined what those repairs might be or whether the generators will need to be replaced for the Units to operate at their prior output levels. Each Unit will only be restarted when any necessary repairs and appropriate mitigation plans for that Unit are completed in accordance with the CAL, and the NRC and SCE are satisfied that it is safe to do so.

NRC Processes

The timing of restart of the Units will also be affected by the nature of and schedule for regulatory processes required by the NRC. There is no set or predetermined time period for approval of Unit 2's proposed restart, and, accordingly, there can be no assurance about the length of time the NRC may take to review SCE's request to restart or whether any such request would be granted in whole or in part.

The NRC will conduct one or more on-site inspections to verify that SCE has performed the actions described in the CAL response and will hold public meetings to discuss the CAL response as well as the results of the on-site inspections. There is no timeline for the NRC's review of the CAL response. It is also possible that one or more amendments to the NRC operating license for San Onofre might be required (whether or not as a prerequisite to return a Unit to safe operation). The NRC could also choose to impose additional processes and assessments that could result in significant costs or additional delay.

Following the failure of pressure tests on the eight tubes in Unit 3, the NRC launched an Augmented Inspection Team (“AIT”) to assess the tube failures and their causes, SCE's operation of the Units, and SCE's oversight of the design, fabrication, shipping, and construction process. In July 2012, the NRC issued a report providing the results of the AIT inspection. That report concluded that the replacement steam generators' design and configuration did not provide the necessary margin to prevent fluid elastic instability and that these deficiencies appear to be related to MHI's computer code used to model thermal hydraulic conditions in the steam generators. The report further stated that SCE was adequately pursuing the causes of the unexpected steam generator tube-to-tube degradation. The AIT report also identified a number of as-yet unresolved issues that are continuing to be examined. The unresolved issues include further evaluation of manufacturing differences between Unit 2 and Unit 3, with particular focus on the control of critical dimensions affecting the

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clearances between tubes and tube supports. The NRC will conduct subsequent inspections or reviews to determine what, if any, regulatory actions result from these unresolved items. Should the NRC find a deficiency in SCE's performance, SCE could be subject to additional NRC actions, and the findings could be taken into consideration in the CPUC regulatory proceedings described below.

CPUC Review

Under California Public Utilities Code Section 455.5, SCE is required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months (not including preplanned outages). SCE will provide such notice to the CPUC on November 1, 2012 for Unit 3 and expects to do so by December 6, 2012 for Unit 2. The CPUC is required within 45 days of SCE's notice for a particular Unit to initiate an investigation to determine whether to remove from customer rates some or the entire revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5 any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation.

In October 2012, in advance of SCE's required notification under Section 455.5, the CPUC issued an order instituting investigation that will consolidate all San Onofre issues in related regulatory proceedings and consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, market power costs, capital and operations and maintenance costs, and seismic study costs. The order requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent included in rates, collected subject to refund. The order also states that the CPUC will determine whether to order the immediate removal, effective as of the date of the order, of all costs related to San Onofre from SCE's rates, with placement of those costs in a deferred debit account pending the return of one or both Units to useful service, or other possible action. SCE will file its response to the order by November 26, 2012. SCE must also file testimony by December 10, 2012 detailing proposed rate adjustments due to the outages, including the amount of San Onofre costs in current rates, the amount to be removed, if any, the effective date, and related information. A pre-hearing conference will be scheduled early in 2013 after the issuance of a Scoping Memo by the Assigned Commissioner.

In parallel with the order instituting investigation, the 2012 GRC proposed decision would, if adopted, require SCE to track San Onofre-related costs in a memorandum account subject to refund, beginning January 1, 2012. SCE would be required by January 30, 2013 to file an application for reasonableness review of these costs and the proposed decision would allow that application to be consolidated with other proceedings. The 2012 GRC proposed decision also approves expenditures incurred through 2011 for the high pressure turbine project, but disallows recovery for post-2011 expenditures associated with the project and directs SCE to record those costs in either the memorandum account or seek future rate recovery in the next GRC. SCE anticipates that the inter-relationship between the Section 455.5 process and the issues to be reviewed in the investigation or pursuant to a final decision in the GRC will be addressed by the CPUC as it continues to develop the scope of the issues to be consolidated within the investigation.

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In addition to the amounts for inspection and repair and market power costs discussed below, SCE has collected through customer rates an estimated $625 million of revenue through third quarter 2012 (based on current authorized revenue requirements) associated with the plant. SCE's total 2012 San Onofre annual revenue requirement, including the 2012 GRC proposed decision, is approximately $820 million, made up of $170 million in refueling outage, nuclear fuel and decommissioning costs and $650 million for its direct operating and maintenance costs, depreciation and return on its investment in San Onofre Unit 2, Unit 3 and related common plant. At September 30, 2012, SCE's rate base and net investment associated with San Onofre were as set forth in the following table:

(in millions)	Unit 2			Unit 3			Common Plant			Total
Net investment
Net plant in service	$	593		$	418		$	261		$	1,272
Materials and supplies	—			—			99			99
Construction work in progress	77			141			76			294
Nuclear fuel	153			212			101			466
Net investment	$	823		$	771		$	537		$	2,131
Rate base
Net plant in service	$	593		$	418		$	261		$	1,272
Materials and supplies	—			—			99			99
Accumulated deferred income taxes	(95		)	(45		)	(66		)	(206		)
Amounts in rate base	$	498		$	373		$	294		$	1,165

In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million after adjustment for inflation) for SCE's 78.21% share of San Onofre to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $594 million through September 30, 2012 on the steam generator replacement project, including $95 million reflected in construction work in progress primarily related to the disposal of the replaced steam generators. Those expenditures remain subject to CPUC reasonableness review. Final costs for the project will not be known until after disposal of the original steam generators is completed.

As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre are being purchased in the market by SCE (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market costs through September 30, 2012 were approximately $221 million, net of avoided nuclear fuel costs, and are recoverable through the ERRA balancing account subject to CPUC reasonableness review. Because of the uncertainties associated with when and at what output levels the Units will or may be returned to service, total potential market power costs cannot be estimated at this time.

Through September 2012, SCE's share of incremental inspection and repair costs totaled $96 million for both Units. At September 30, 2012, the repairs to restart Unit 2 at the reduced power levels described above have been substantially completed. The costs for Unit 2 may increase following NRC review under the CAL and any new developments that may result from further analysis, testing and inspection, and there is no assurance that start-up of Unit 2 will occur as described above. Total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain.

Contractual Matters

The steam generators were designed and supplied by MHI and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions. In September 2012, SCE submitted an invoice to MHI for costs paid through June 30, 2012 in the amount of $45 million for both SCE's and the other co-owners' share of steam generator repair costs. SCE expects to continue to invoice MHI for costs incurred. No amounts have been recognized in the financial statements as of September 30, 2012.

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San Onofre carries both property damage and outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. The property damage policy (including excess coverage) provides insurance for certain costs and expenses resulting from “Accidental Property Damage” with a $2.5 million deductible and a $2.75 billion limit of liability. After a twelve week deductible period, the outage policy provides insurance for an outage caused by “Accidental Property Damage” of up to $3.5 million per week for each Unit (or $2.8 million per Unit per week if both Units are out because of the same "Accident"), with a $490 million limit for each Unit ($392 million each if both Units are out because of the same "Accident"). The NEIL policies have a number of exclusions and limitations that may reduce or eliminate coverage. For instance, coverage may be reduced or excluded if it is determined that the outage resulted from any condition which develops, progresses or changes over time, or from wear and tear. Further, costs to "make good" faulty workmanship or design and amounts collectible from third parties are excluded from the property damage policy. Proof of loss must be submitted within 12 months of the Accidental Property Damage under the property damage insurance and within 12 months of the end of the outage under the outage policy. In October 2012, SCE filed separate proofs of loss for Unit 2 and Unit 3 under the outage policy. Pursuant to these proofs of loss SCE is seeking the weekly indemnity amounts provided under the policy for each Unit. Because the outage is ongoing, SCE will supplement these proofs of loss in the future. No amounts have been recognized in SCE's financial statements, pending further actions by NEIL. To the extent any costs are recovered under the outage policy, SCE expects to refund those amounts to ratepayers through the ERRA balancing account. For further information, see "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

SCE will pursue recoveries arising from available agreements, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements.

CAISO Summer Readiness Planning

In addition to providing up to 2,200 MW of electric power, San Onofre also provides significant reliability support to the electric grid, including support for grid voltage and stability. SCE continues to work with the CAISO to maintain grid reliability for summer 2013 and beyond while the San Onofre Units are out of service. SCE is supporting CAISO in its negotiations to obtain local grid voltage support. SCE has also accelerated certain transmission projects and will expand its demand response programs to help maintain grid reliability. The majority of these efforts are projects that are already included in SCE's capital expenditure plan, but their timing has been accelerated. In addition, SCE has proposed to the CAISO projects such as transmission line reconfiguration and installation of equipment to support voltage and stability. The projects, if approved could result in additional capital expenditures from $100 million to $125 million over the period 2013 – 2015.

Workforce Reduction

In August 2012, SCE announced plans for downsizing to bring the San Onofre organization and cost structure in line with industry peers. SCE plans to reduce the San Onofre workforce by 730 employees to 1,500 employees beginning in the fourth quarter of 2012 and continuing in 2013. At September 30, 2012, SCE had recorded $30 million in estimated cash severance costs (SCE's share) related to the non-represented employee workforce reduction.

Capital Program

During the first nine months of 2012, SCE's capital investment program focused on maintaining reliability and expanding the capability of SCE's transmission and distribution system; upgrading and constructing new transmission lines and substations; installing digital meters; and replacing generation asset equipment. Total capital expenditures (including accruals) were $2.6 billion during the first nine months of 2012 compared to $2.5 billion during the same period in 2011. SCE expects that 2012 capital expenditures will be below the lower end of the previously projected $4.4 billion to $5.0 billion range due to the delay in the GRC decision, the delay related to the Tehachapi Project and outages at San Onofre. However, SCE continues to project that 2012 – 2014 total capital expenditures will be in the range of $11.8 billion to $13.2 billion. Actual capital spending will be affected by: changes in regulatory, environmental and engineering design requirements; permitting and project delays; cost and availability of labor, equipment and materials; outcome of the San Onofre mitigation plans; and other factors.

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RESULTS OF OPERATIONS

SCE's results of operations are derived mainly through two sources:

• Utility earning activities – representing revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of authorized operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in utility earnings activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.

• Utility cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery of specific project or program costs, subject to reasonableness review or compliance with upfront standards.

The following tables summarize SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities. Beginning in 2012, SCE classified revenues and costs related to programs that provide for recovery of actual costs plus a return on capital as utility earning activities. Previously, SCE classified the recovery of actual costs incurred under these programs as utility cost-recovery activities. The tables presented below reflect a reclassification of the revenues and costs for 2011 consistent with the presentation in 2012. The reclassification of revenues and costs had no impact on earnings.

During the first nine months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. This has resulted in a decrease in net income as higher depreciation and net interest expenses are not being recovered in currently authorized revenue. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. Recognition of the revenue for the period January 1, 2012 through the date of a final decision, as well as any delays in certain expenditures and changes in authorized treatment of specific costs, will impact the timing of earnings in 2012 (see "Management Overview—2012 CPUC General Rate Case" for further discussion).

Three Months Ended September 30, 2012 versus September 30, 2011

	Three months ended September 30, 2012								Three months ended September 30, 2011
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue	$	1,754		$	1,977	$	3,731		$	1,759		$	1,627	$	3,386
Fuel and purchased power	—			1,694		1,694			—			1,374		1,374
Operations and maintenance	623			283		906			566			253		819
Depreciation decommissioning and amortization	399			—		399			358			—		358
Property taxes and other	73			—		73			71			—		71
Total operating expenses	1,095			1,977		3,072			995			1,627		2,622
Operating income	659			—		659			764			—		764
Net interest expense and other	(95		)	—		(95		)	(98		)	—		(98		)
Income before income taxes	564			—		564			666			—		666
Income tax expense	176			—		176			245			—		245
Net income	388			—		388			421			—		421
Dividends on preferred and preference stock	25			—		25			15			—		15
Net income available for common stock	$	363		$	—	$	363		$	406		$	—	$	406
Core Earnings1						$	363							$	406
Non-Core Earnings						—								—
Total SCE GAAP Earnings						$	363							$	406

¹  See use of Non-GAAP financial measures in "Management Overview—Highlights of Operating Results."

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Utility Earning Activities

Utility earning activities were primarily affected by the following:

• Higher operations and maintenance expense of $57 million was primarily due to increased costs at San Onofre, including $48 million related to the steam generator inspection and repair at San Onofre and $30 million of estimated cash severance costs related to the planned San Onofre reduction in workforce; partially offset by lower operations and maintenance expenses. These increases were partially offset by EdisonSmartConnect^® benefits realized and other cost savings and timing of expenses.

• Higher depreciation, decommissioning and amortization expense of $41 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs.

• Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information.

• Higher preferred and preference stock dividends of $10 million related to new issuances in 2012.

Utility Cost-Recovery Activities

Utility cost-recovery activities were primarily affected by the following:

• Higher fuel and purchased power expense of $320 million was primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below) and $104 million of market costs net of lower nuclear fuel costs related to the outage at San Onofre in 2012 (see "Management Overview—San Onofre" for further information). These increases were partially offset by lower power prices in 2012.

• Higher operations and maintenance expense of $30 million was primarily due to increased energy efficiency program costs.

Nine Months Ended September 30, 2012 versus September 30, 2011

	Nine months ended September 30, 2012									Nine months ended September 30, 2011
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue	$	4,670		$	4,124		$	8,794		$	4,596		$	3,467	$	8,063
Fuel and purchased power	—			3,269			3,269			—			2,691		2,691
Operations and maintenance	1,774			848			2,622			1,675			775		2,450
Depreciation decommissioning and amortization	1,187			—			1,187			1,058			—		1,058
Property taxes and other	227			2			229			216			1		217
Total operating expenses	3,188			4,119			7,307			2,949			3,467		6,416
Operating income	1,482			5			1,487			1,647			—		1,647
Net interest expense and other	(296		)	(5		)	(301		)	(269		)	—		(269		)
Income before income taxes	1,186			—			1,186			1,378			—		1,378
Income tax expense	384			—			384			496			—		496
Net income	802			—			802			882			—		882
Dividends on preferred and preference stock	66			—			66			44			—		44
Net income available for common stock	$	736		$	—		$	736		$	838		$	—	$	838
Core Earnings1							$	736							$	838
Non-Core Earnings							—								—
Total SCE GAAP Earnings							$	736							$	838

¹  See use of Non-GAAP financial measures in "Management Overview—Highlights of Operating Results."

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Utility Earning Activities

Utility earning activities were primarily affected by the following:

• Higher operating revenue of $74 million was primarily due to $80 million of increased revenue related to authorized CPUC projects not included in SCE's GRC process, including the EdisonSmartConnect^® project and the Solar Photovoltaic project (approximately $65 million primarily recovered operations and maintenance and depreciation expense associated with the related CPUC projects). The change in revenue also reflects revenue recognized in 2012 related to the San Onofre Unit 2 scheduled outage costs. In December 2011, the CPUC authorized revenue requirements for 2012 refueling outages for San Onofre. These increases were partially offset by decreases in other operating revenue.

• Higher operation and maintenance expense of $99 million was primarily due to increased costs at San Onofre, including $96 million of costs related to the steam generator inspection and repair as well as $35 million related to the 2012 San Onofre Unit 2 scheduled maintenance and refueling outage and $30 million of estimated cash severance costs related to the planned San Onofre reduction in workforce (see "Management Overview—San Onofre" for further information); partially offset by lower operations and maintenance expenses. These increases were partially offset by EdisonSmartConnect^® benefits realized and other cost savings and timing of expenses.

• Higher depreciation, decommissioning and amortization expense of $129 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs and CPUC capital-related projects discussed above.

• Higher net interest expense and other of $27 million was primarily due to higher outstanding balances on long-term debt.

• Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information.

• Higher preferred and preference stock dividends of $22 million related to new issuances in 2012.

Utility Cost-Recovery Activities

Utility cost-recovery activities were primarily affected by the following:

• Higher fuel and purchased power expense of $578 million was primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below) and $221 million of market costs net of lower nuclear fuel costs related to the San Onofre outage in 2012 (see "Management Overview—San Onofre" for further information). These increases were partially offset by lower power prices in 2012.

• Higher operation and maintenance expense of $73 million was primarily due to increased pension contributions.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $3.7 billion and $8.7 billion for the three- and nine-month periods ended September 30, 2012, respectively, compared to $3.3 billion and $7.8 billion for the respective periods in 2011. The increase in revenue reflects:

• A sales volume increase of $677 million and $1.4 billion for the three- and nine-month periods, respectively, primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011. Prior to 2012, SCE remitted to CDWR and did not recognize as revenue the amounts that SCE billed and collected from its customers for the portion of electric power purchased and sold by the CDWR to SCE's customers.

• A rate decrease of $294 million and $502 million for the three- and nine-month periods, respectively, resulting from rate adjustments in June 2011 and August 2012, primarily reflecting lower forecasted fuel and purchased power costs and refunds to customers of overcollected fuel and power procurement-related costs.

As a result of the CPUC-authorized decoupling mechanism, SCE earnings are not affected by changes in retail electricity sales (see "Item 1. Business—Overview of Ratemaking Process" in the 2011 Form 10-K).

Due to warmer weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than other quarters.

35

Income Taxes

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Income before income taxes	$	564		$	666		$	1,186		$	1,378
Provision for income tax at federal statutory rate of 35%	197			233			415			482
Increase (decrease) in income tax from:
State tax – net of federal benefit	10			31			30			61
Property-related	(19		)	(18		)	(39		)	(38		)
Other	(12		)	(1		)	(22		)	(9		)
Total income tax expense	$	176		$	245		$	384		$	496
Effective tax rate	31		%	37		%	32		%	36		%

State income taxes were lower for both the three- and nine-month periods ended September 30, 2012 due to lower pre-tax income and higher benefits related to depreciation, cost of removal and repair deductions, including additional tax deductions reflected in SCE's 2011 tax returns.

For a discussion of the status of Edison International's income tax audits, see "SCE Notes to Consolidated Financial Statements—Note 7. Income Taxes."

LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, fund capital expenditures, and implement its business strategy are dependent upon its cash flow and access to the capital markets. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, interest and dividend payments to investors, and the outcome of tax and regulatory matters.

SCE expects to fund its 2012 obligations, capital expenditures and dividends through operating cash flows and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities to meet operating and capital requirements.

Available Liquidity

During the second quarter of 2012, SCE replaced its existing credit facilities scheduled to mature in early 2013 with a new $2.75 billion five-year revolving credit facility that matures May 2017. The following table summarizes the status of the SCE credit facility at September 30, 2012:

(in millions)	Credit Facilities
Commitment	$	2,750
Outstanding commercial paper supported by credit facilities	(380		)
Outstanding letters of credit	(196		)
Amount available	$	2,174

Debt Covenant

SCE has a debt covenant in its credit facility that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At September 30, 2012, SCE's debt to total capitalization ratio was 0.46 to 1.

36

Capital Investment Plan

Transmission Projects - Tehachapi Project

As discussed in the year-ended 2011 MD&A, the CPUC requested that SCE provide information on potential new options for a portion of the Tehachapi Project, including traversing a state park, changing the nature of some of the towers and undergrounding lines. In July 2012, the Assigned Commissioner issued a ruling requesting SCE to further study and provide more detailed information by the end of February 2013 on two identified undergrounding options for a portion of the project. The ruling set forth a schedule for interested parties to also provide further information, briefing by all parties and evidentiary hearings. The order states that the construction of the affected portion of the project shall remain deferred until the CPUC makes a final determination regarding the options. Adoption of either of the two undergrounding options could create significant additional costs and delay the completion of the project. SCE is required to file revised cost estimates with the CPUC by the end of February 2013. As with all transmission investments, cost recovery will be subject to future rate proceedings.

Regulatory Proceedings

FERC Formula Rates

As discussed in the year-ended 2011 MD&A, the FERC has accepted, subject to refund and settlement procedures, SCE's request to implement formula rates as a means to determine SCE's FERC transmission revenue requirement effective January 1, 2012. SCE's request would result in a total 2012 FERC weighted average ROE of 11.1% including a base ROE of 9.93% and the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives.

In September 2012, SCE filed its proposed formula rate update with the FERC. SCE's proposed request would implement a 2013 transmission revenue requirement of $900 million, representing an increase of $178 million or 25% over the 2012 revenue requirement. The increase is primarily due to higher FERC rate base from transmission investments, including projects under construction. Consistent with SCE's proposed formula rate methodology, the proposed revenue requirement utilizes the 2012 FERC authorized base ROE discussed above, which remains subject to refund and the ongoing settlement negotiations.

The formula rate mechanism, including the base ROE, is subject to final resolution as part of the settlement process or, if a settlement is not achieved, to determination by FERC in a litigated process. SCE and the other parties to the proceeding continue to engage in settlement negotiations.

Dividend Restrictions

The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At September 30, 2012, SCE's 13-month weighted-average common equity component of total capitalization was 48.9% resulting in the capacity to pay $175 million in additional dividends to Edison International. During the first nine months of 2012, SCE made $349 million in dividend payments to its parent, Edison International.

Margin and Collateral Deposits

Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at September 30, 2012, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.

Some of the power procurement contracts contain provisions that require SCE to maintain an investment grade credit rating from the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral.

37

The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of September 30, 2012.

(in millions)
Collateral posted as of September 30, 20121	$	249
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade	64
Posted and potential collateral requirements2	$	313

¹  Collateral provided to counterparties and other brokers consisted of $44 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $9 million of cash reflected in "Other current assets" on the consolidated balance sheets and $196 million in letters of credit.

²  Total posted and potential collateral requirements may increase by $14 million based on SCE's forward positions as of September 30, 2012 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level.

Workers Compensation Self-Insurance Fund

For a discussion of potential collateral requirements related to its self-insured workers compensation plan, refer to "Liquidity and Capital Resources—Workers Compensation Self-Insurance Fund" in the year ended 2011 MD&A.

Historical Consolidated Cash Flows

The table below sets forth condensed historical cash flow information for SCE.

	Nine months ended September 30,
(in millions)	2012			2011
Net cash provided by operating activities	$	2,656		$	2,272
Net cash provided by financing activities	636			672
Net cash used by investing activities	(3,259		)	(3,136		)
Net increase (decrease) in cash and cash equivalents	$	33		$	(192	)

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $384 million in the first nine months of 2012 compared to the same period in 2011. The increase in cash flows provided by operating activities was primarily due to higher net tax receipts in 2012, the impact of higher costs at San Onofre and the timing of cash receipts and disbursements related to working capital items.

38

Net Cash Provided by Financing Activities

The following table summarizes cash provided by financing activities for the nine months ended September 30, 2012 and 2011. Issuances of debt and preference stock are discussed in "SCE Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "Note 12. Preferred and Preference Stock."

	Nine months ended September 30,
(in millions)	2012			2011
Issuances of first and refunding mortgage bonds, net	$	391		$	492
Net issuances of commercial paper1	(45		)	550
Issuances of preference stock, net	804			123
Payments of common stock dividends to Edison International	(349		)	(345		)
Redemptions of preference stock	(75		)	—
Bonds purchased	—			(86		)
Payments of preferred and preference stock dividends	(62		)	(43		)
Other	(28		)	(19		)
Net cash provided by financing activities	$	636		$	672

¹   Issuances of commercial paper are supported by SCE's credit facility.

The timing and amount of SCE's financing activities are largely driven by its capital program.

Net Cash Used by Investing Activities

Cash flows from investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $3.1 billion and $3.0 billion for the nine months ended September 30, 2012 and 2011, respectively (see "Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2011 MD&A for further information on capital expenditures). Net purchases of nuclear decommissioning trust investments and other were $164 million and $146 million for the nine months ended September 30, 2012 and 2011, respectively.

Contractual Obligations and Contingencies

Contractual Obligations

SCE has power purchase commitments which are discussed in "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

Contingencies

SCE has contingencies related to the San Onofre Outage, Inspection and Repair Issues, CPSD Investigations, Four Corners New Source Review Litigation, Nuclear Insurance, Wildfire Insurance and Spent Nuclear Fuel, which are discussed in "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

Environmental Remediation

As of September 30, 2012, SCE had identified 25 material sites for remediation and recorded an estimated minimum liability of $113 million. SCE expects to recover 90% of its remediation costs at certain sites. See "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" for further discussion.

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. Derivative instruments are used, as appropriate, to manage market risks for customers and SCE. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "SCE Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities" and "—Note 4. Fair Value Measurements."

39

Commodity Price Risk

The fair value of outstanding derivative instruments used to mitigate SCE's exposure to commodity price risk was a net liability of $1.0 billion and $936 million at September 30, 2012 and December 31, 2011, respectively. To the extent San Onofre Unit 2 and Unit 3 are not operating, SCE may be exposed to market prices associated with replacement power costs. SCE's hedging program has taken this exposure into consideration and has entered into forward contracts to address projected market price variability. For further discussion of fair value measurements and the fair value hierarchy, see "SCE Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."

Credit Risk

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. As of September 30, 2012, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

	September 30, 2012
(in millions)	Exposure2		Collateral			Net Exposure
S&P Credit Rating1
A or higher	$	101	$	—		$	101
Not rated3	5		(1		)	4
Total	$	106	$	(1	)	$	105

¹  SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.

²  Exposure excludes amounts related to contracts classified as normal purchases and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable.

³  The exposure in this category relates to long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

For a discussion of SCE's critical accounting estimates and policies, see "Critical Accounting Estimates and Policies" in the year ended 2011 MD&A.

NEW ACCOUNTING GUIDANCE

New accounting guidance is discussed in "SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to this item is included in the MD&A under the heading "Market Risk Exposures" and is incorporated herein by reference.

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ITEM 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SCE's management, under the supervision and with the participation of the company's President and Chief Financial Officer, has evaluated the effectiveness of SCE'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 third quarter of

2012. Based on that evaluation, the President and Chief Financial Officer concluded that, as of the end of the third quarter of 2012, SCE's disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in SCE'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 third quarter of 2012 that have materially affected, or are reasonably likely to materially affect, SCE's internal control over financial reporting.

Jointly Owned Utility Plant

SCE's scope of evaluation of internal control over financial reporting includes its Jointly Owned Utility Projects.

PART II.     OTHER INFORMATION

ITEM 1.     LEGAL PROCEEDINGS

None.

ITEM 6.     EXHIBITS

Exhibit Number	Description
10.1	Edison International 2008 Director Deferred Compensation Plan, as amended and restated effective October 25, 2012 (File No. 1-9936, filed as Exhibit 10.1 to Edison International Form 10-Q for the quarter ended September 30, 2012)*
10.2	Edison International 2008 Executive Deferred Compensation Plan, as amended and restated effective October 24, 2012 (File No. 1-9936, filed as Exhibit 10.2 to Edison International Form 10-Q for the quarter ended September 30, 2012)*
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32	Statement Pursuant to 18 U.S.C. Section 1350
101	Financial statements from the quarterly report on Form 10-Q of Southern California Edison Company for the quarter ended September 30, 2012, filed on November 1, 2012, formatted in XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; and (v) the Notes to Consolidated Financial Statements

______________________________________

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

41

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) 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.

SOUTHERN CALIFORNIA EDISON COMPANY
By:	/s/ Chris C. Dominski
	Chris C. Dominski Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

Date: November 1, 2012

42

EX-31.1

Exhibit 31.1

CERTIFICATION

I, RONALD L. LITZINGER, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, of Southern California Edison Company;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

(a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)    Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)    Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.    The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 1, 2012

/s/ RONALD L. LITZINGER

RONALD L. LITZINGER

President

EX-31.2

Exhibit 31.2

CERTIFICATION

I, LINDA G. SULLIVAN, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, of Southern California Edison Company;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

(a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)    Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)    Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.    The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 1, 2012

/s/ LINDA G. SULLIVAN

LINDA G. SULLIVAN

Chief Financial Officer

EX-32

Exhibit 32

STATEMENT PURSUANT TO 18 U.S.C. SECTION 1350, AS

ENACTED BY SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (the “Quarterly Report”), of Southern California Edison Company (the “Company”), and pursuant to 18 U.S.C. Section 1350, as enacted by Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned certifies, to the best of his or her knowledge, that:

1. The Quarterly Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

2. The information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 1, 2012

/s/ RONALD L. LITZINGER

RONALD L. LITZINGER

President

Southern California Edison Company

/s/ LINDA G. SULLIVAN

LINDA G. SULLIVAN

Chief Financial Officer

Southern California Edison Company

This statement accompanies the Quarterly Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

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Fair Value Measurements (Changes in Level 3 Net Derivative Assets and Liabilities) (Details) (Level 3, USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Level 3
Fair Value Disclosures Level 3
Fair value of net assets (liabilities) at beginning of period	$ (739)		$ (359)		$ (754)		$ 6
Total realized/unrealized gains (losses), net:
Included in regulatory assets	(180)	[1]	(128)	[1]	(203)	[1]	(510)	[1]
Purchases	33		19		84		35
Settlements	(44)		(2)		(57)		(1)
Transfers into Level 3	0		0		0		0
Transfers out of Level 3	0		0		0		0
Fair value of net liabilities at end of period	(930)		(470)		(930)		(470)
Change during the period in unrealized gains (losses) related to assets and liabilities held at the end of the period	$ (222)		$ (135)		$ (244)		$ (502)

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

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Other Investments (Amortized Cost and Fair Value of Nuclear Decommissioning Trusts) (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2010
Fair Value Disclosures:
Contributions received for decommissioning trusts			$ 23,000,000
Period of reviewing contributions from decommissioning trusts (in years)			3 years
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	2,437,000,000		2,437,000,000		2,303,000,000
Fair Value	3,997,000,000	3,393,000,000	3,997,000,000	3,393,000,000	3,592,000,000	3,810,000,000	3,657,000,000	3,480,000,000
Proceeds from sale of securities	428,000,000	962,000,000	1,525,000,000	2,108,000,000
Unrealized holding gains, net of losses			1,600,000,000		1,300,000,000
Stocks
Nuclear Decommissioning Trusts Disclosures
Amortized Cost	957,000,000		957,000,000		865,000,000
Fair Value	2,227,000,000		2,227,000,000		1,899,000,000
Municipal bonds
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			2054
Amortized Cost	520,000,000		520,000,000		625,000,000
Fair Value	654,000,000		654,000,000		756,000,000
U.S. government and agency securities
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			2042
Amortized Cost	526,000,000		526,000,000		516,000,000
Fair Value	589,000,000		589,000,000		580,000,000
Corporate bonds
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			2054
Amortized Cost	287,000,000		287,000,000		259,000,000
Fair Value	374,000,000		374,000,000		317,000,000
Short-term investments and receivables/payables
Nuclear Decommissioning Trusts Disclosures
Longest maturity dates decommissioning trust investments (in years)			One-year
Amortized Cost	147,000,000		147,000,000		38,000,000
Fair Value	$ 153,000,000		$ 153,000,000		$ 40,000,000

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Compensation and Benefit Plans (Details) (USD $) In Millions, unless otherwise specified		9 Months Ended	1 Months Ended		3 Months Ended		9 Months Ended			3 Months Ended				9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012 Work force Reduction San Onofre	Aug. 31, 2012 Work force Reduction San Onofre Minimum positions	Aug. 31, 2012 Work force Reduction San Onofre Maximum positions	Sep. 30, 2012 Pension Plans	Sep. 30, 2011 Pension Plans	Sep. 30, 2012 Pension Plans	Sep. 30, 2011 Pension Plans	Sep. 30, 2012 Pension Plans Previous Estimate	Sep. 30, 2012 Postretirement Benefits Other Than Pensions		Sep. 30, 2011 Postretirement Benefits Other Than Pensions		Sep. 30, 2012 Postretirement Benefits Other Than Pensions		Sep. 30, 2011 Postretirement Benefits Other Than Pensions
Pension and Other Postretirement Benefits
Plan year contributions					$ 154		$ 154		$ 263
Employer contributions							136							15
Additional plan year contributions										47				47
Requested recovery of plan contributions					168		168
Expense components are:
Service cost					46	38	120	114		12		10		36		30
Interest cost					45	47	135	141		28		31		84		93
Expected return on plan assets					(52)	(56)	(162)	(168)		(27)		(27)		(81)		(81)
Special termination benefits										3	[1]	0	[1]	3	[1]	0	[1]
Amortization of prior service cost (credit)					1	2	3	6		(9)		(9)		(27)		(27)
Amortization of net loss					15	4	45	12		11		9		33		27
Total expense					55	35	141	105		18		14		48		42
Regulatory adjustment (deferred)					(57)	(6)	(3)	(18)
Total expense recognized					(2)	29	138	87
After tax liability related to postretirment benefits to be assumed by Edison International	116
Cash severance costs		$ 30
Expected number of positions to be eliminated			730	1,500

[1] Due to the reduction in the workforce at San Onofre, SCE has incurred costs for enhanced retiree health care coverage. See below for further information.

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Other Investments (Summary of Changes in Fair Value of the Nuclear Decommissioning Trusts) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Summary Of Changes In The Fair Value [Roll Forward]
Balance at beginning of period	$ 3,810	$ 3,657	$ 3,592	$ 3,480
Gross realized gains	13	46	54	81
Gross realized losses	0	(5)	(5)	(5)
Unrealized gains (losses) - net	156	(305)	272	(199)
Other-than-temporary impairments	(7)	(22)	(30)	(35)
Interest, dividends, contributions and other	25	22	114	71
Balance at end of period	$ 3,997	$ 3,393	$ 3,997	$ 3,393

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Derivative Instruments and Hedging Activities (Margin and Collateral Desposits) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Collateral provided to counterparties:
Offset against derivative liabilities	$ 44	$ 51
Reflected in other current assets	$ 9	$ 17

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Other Investments (Tables)

9 Months Ended

Sep. 30, 2012

Regulated Entity, Other Assets, Noncurrent [Abstract]

Amortized Cost and Fair Value of the Trust Investments

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

		Amortized Cost				Fair Value
(in millions)	Longest Maturity Dates	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Stocks	—	$	957	$	865	$	2,227	$	1,899
Municipal bonds	2054	520		625		654		756
U.S. government and agency securities	2042	526		516		589		580
Corporate bonds	2054	287		259		374		317
Short-term investments and receivables/payables	One-year	147		38		153		40
Total		$	2,437	$	2,303	$	3,997	$	3,592

Summary of Changes in the Fair Value of Trust

The following table sets forth a summary of changes in the fair value of the trust:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2012			2011			2012			2011
Balance at beginning of period	$	3,810		$	3,657		$	3,592		$	3,480
Gross realized gains	13			46			54			81
Gross realized losses	—			(5		)	(5		)	(5		)
Unrealized gains (losses) – net	156			(305		)	272			(199		)
Other-than-temporary impairments	(7		)	(22		)	(30		)	(35		)
Interest, dividends, contributions and other	25			22			114			71
Balance at end of period	$	3,997		$	3,393		$	3,997		$	3,393

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Planned Sale of Interest in Four Corners (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012
Discontinued Operations and Disposal Groups [Abstract]
Sales price	$ 294
Sales price, after adjustment	$ 279

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2012

Accounting Policies [Abstract]

Inventory Components

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

(in millions)	September 30, 2012		December 31, 2011
Fuel	$	19	$	24
Materials and supplies, spare parts	319		326
Total inventory	$	338	$	350

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Commitments and Contingencies (Contingencies) (Details) (USD $)	1 Months Ended		3 Months Ended	9 Months Ended			1 Months Ended		9 Months Ended			9 Months Ended		1 Months Ended
	Dec. 31, 2011	Jun. 30, 2010	Sep. 30, 2012	Sep. 30, 2012 sites	Sep. 30, 2011	Sep. 15, 2012	Oct. 31, 2011 Malibu Fire Order Instituting Investigation	Oct. 31, 2011 Alleged violations of PSD requirements and New Source Performance Standards of the CAA private_environmental_organization	Sep. 30, 2012 Insurance Claims	Sep. 30, 2012 San Onofre generator	Mar. 31, 2012 San Onofre heat_transfer_tube	Sep. 30, 2012 San Onofre Outage, Inspection and Repair Issues H	Sep. 30, 2012 San Onofre and Palo Verde Insurance Claims	Oct. 31, 2011 OII Respondents Malibu Fire Order Instituting Investigation
Contingencies
Number of steam generators replaced (in generators)										4
Heat transfer tubes with water leak (in heat transfer tubes)											1
Reduced power level of operation (as a percentage)												70.00%
Term of reduced power level of operation (in months)												5 months
Authorized expenditures												$ 525,000,000
Authorized expenditures, after adjustments for inflation												665,000,000
Ownership percentage (as a percentage)										78.21%
Costs incurred to date												594,000,000
Construction work in progress												95,000,000
Authorized expenditures by authoritative body, market costs incurred												221,000,000
Incremental inspection and repair costs												96,000,000
Collected revenue, based on current authorized revenue requirements												625,000,000
Annual revenue requirement request												820,000,000
Annual revenue requirement request, nuclear fuel-related and decommissioning costs												170,000,000
Direct operating and maintenance costs, depreciation and return on investment												650,000,000
Rate base												1,200,000,000
Net investment and inventory associated with plant												2,100,000,000
Term of outage for which notification is required (in months)												9 months
Required term, from notice of investigation to remove revenue requirements from customer rates												45 days
Continuous hours of operation, after which rates may be readjusted (in hours)												100
Warranty period												20 years
MHI's limited liability under purchase agreement, excluding consequential damages												138,000,000
Invoiced amount to MHI												45,000,000
Damages sought	98,000,000						50,000,000							99,000,000
Number of plantiffs								4
Maximum expected period for cleanup of identified sites (in years)			30 years
Accrued liability for environmental remediation			113,000,000	113,000,000						78,000,000
Identified material sites for environmental remediation (in number of sites)				25
Identified material sites, minimum amount of upper end of range of costs				1,000,000
Number of Immaterial Sites for Environmental Remediation				33
Immaterial sites, range of liability, minimum			3,000,000	3,000,000
Environmental remediation liability			116,000,000	116,000,000
Environmental remediation liability, recorded as regulatory asset			113,000,000	113,000,000
Portion of Recorded Liability Recoverable From Incentive Mechanism				31,000,000
Percentage of Environmental Remediation Costs Recoverable From Incentive Mechanism				90.00%
Recorded Liability Incurred at Majority of Remaining Sites Through Customer Rates			82,000,000	82,000,000
Percentage of Environmental Remediation Costs to be Recovered				100.00%
Amount that Cleanup Costs for Identified Material Sites Could Exceed Recorded Liability				185,000,000
Amount that Cleanup Costs for Immaterial Sites Could Exceed Recorded Liability				6,000,000
Expected Annual Environmental Remediation Costs, Low End of Range				7,000,000
Expected Annual Environmental Remediation Costs, High End of Range				14,000,000
Environmental Remediation Expense				5,000,000	9,000,000
Federal Limit on Public Liability Claims from Nuclear Incident, Approximate									12,600,000,000
Private Primary Insurance Purchased									375,000,000
Maximum Deferred Insurance Premium Per Nuclear Incident									235,000,000
Maximum Yearly Assessment Per Nuclear Incident									35,000,000
Loss Limit, Property Damage Insurance													500,000,000
Loss Limit, Property Damage Insurance, Federal Minimum Requirement													1,100,000,000
Limit on Assessment of Retrospective Premium Adjustments, Per Year, Approximate									49,000,000
Insurance Coverage for Wildfire Liabilities Limit						550,000,000
Self Insurance Retention Per Wildfire Occurence						10,000,000
Amount Of Damages Decision By US Court Of Federal Claims Spent Nuclear Fuel Litigation		$ 142,000,000

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Debt and Credit Agreements (Details) (USD $)	Sep. 30, 2012	Dec. 31, 2011	Mar. 31, 2012 First and refunding mortgage bonds	Jun. 30, 2012 Revolving credit facility	Sep. 30, 2012 Letter of credit
Debt Instrument [Line Items]
Long-term debt - Gross			$ 400,000,000
Interest rate on debt (as a percent)			4.05%
Outstanding short-term debt	380,000,000	419,000,000
Short-term debt, weighted average interest rate (as a percent)	0.43%	0.44%
Credit facility				2,750,000,000
Credit facility, term (in years)				5 years
Outstanding credit facility					$ 196,000,000

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Variable Interest Entities (Details) (USD $)			3 Months Ended	9 Months Ended	1 Months Ended		3 Months Ended			3 Months Ended		9 Months Ended
	Sep. 30, 2012	Dec. 31, 2011	Sep. 30, 2012 SCE Trust I	Sep. 30, 2012 SCE Trust I	May 31, 2012 SCE Trust I Trust Securities	Sep. 30, 2012 SCE Trust I Trust Securities	Jun. 30, 2012 SCE Trust I Series F	Sep. 30, 2012 SCE Trust I Series F	May 31, 2012 SCE Trust I Series F	Sep. 30, 2012 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts agreements contracts MW	Sep. 30, 2011 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts	Sep. 30, 2012 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts agreements contracts MW	Sep. 30, 2011 Variable Interest Entity, Not Primary Beneficiary SCE Power Purchase Contracts
Details of projects or entities
Number of projects										17		17
Power purchase agreement with tolling agreement (in agreements)										7		7
Power purchase agreement with qualified facilities (in contracts)										10		10
Power generating capacity for majority interest (in megawatts)										3,900		3,900
Payments to unconsolidated VIEs, power purchase contracts										$ 158,000,000	$ 178,000,000	$ 292,000,000	$ 347,000,000
Unconsolidated Trust
Trust securities, percentage rate					5.625%		5.625%
Trust securities, liquidation preference (in dollars per share)					$ 25		$ 2,500		$ 2,500
Trust securities, liquidation preference					475,000,000
Common stock	2,168,000,000	2,168,000,000	10,000	10,000	10,000
Common stock, percentage issued to Southern California Edison					100.00%
Preferred and preference stock	1,795,000,000	1,045,000,000				475,000,000		475,000,000	475,000,000
Dividend income and accrued dividend payments			$ 7,000,000	$ 10,000,000

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Preferred and Preference Stock (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended			3 Months Ended
	Mar. 31, 2012 6.25% Series E	Jun. 30, 2012 5.625% Series F SCE Trust I	May 31, 2012 5.625% Series F SCE Trust I	Jun. 30, 2012 Series A
Preferred and Preference Stock of Utility
Shares issued (in shares)	350,000	190,004
Preference stock (as a percent)	6.25%	5.625%
Preference share, liquidation value (in dollars per share)	$ 1,000	$ 2,500	$ 2,500
Stock redeemed and reitred				$ 75