UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2013
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	Exact Name of Registrant as specified in its charter	State or Other Jurisdiction of Incorporation or Organization	IRS Employer Identification Number
1-9936	EDISON INTERNATIONAL	California	95-4137452
1-2313	SOUTHERN CALIFORNIA EDISON COMPANY	California	95-1240335

EDISON INTERNATIONAL	SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue (P.O. Box 976) Rosemead, California 91770 (Address of principal executive offices)	2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California 91770 (Address of principal executive offices)
(626) 302-2222 (Registrant's telephone number, including area 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.

Edison International        Yes þ No oSouthern California Edison Company    Yes þ 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).

Edison International        Yes þ No oSouthern California Edison Company    Yes þ No ¨

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 "accelerated filer," "large accelerated filer," and "smaller reporting company" in Rule 12b-12 of the Exchange Act. (Check One):
Edison International	Large Accelerated Filer þ	Accelerated Filer ¨	Non-accelerated Filer ¨	Smaller Reporting Company ¨
Southern California Edison Company	Large Accelerated Filer ¨	Accelerated Filer ¨	Non-accelerated Filer þ	Smaller Reporting Company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Edison International        Yes ¨ No þSouthern California Edison Company    Yes ¨ No þ

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

Common Stock outstanding as of October 25, 2013:
Edison International	325,811,206 shares
Southern California Edison Company	434,888,104 shares

TABLE OF CONTENTS

GLOSSARY				iii
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS				2
	Edison International Consolidated Statements of Income			2
	Edison International Consolidated Statements of Comprehensive Income			3
	Edison International Consolidated Balance Sheets			4
	Edison International Consolidated Statements of Cash Flows			6
	SCE Consolidated Statements of Income			9
	SCE Consolidated Statements of Comprehensive Income			9
	SCE Consolidated Balance Sheets			10
	SCE Consolidated Statements of Cash Flows			12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS				13
	Note 1. Summary of Significant Accounting Policies			13
	Note 2. Consolidated Statements of Changes in Equity			16
	Note 3. Variable Interest Entities			17
	Note 4. Fair Value Measurements			18
	Note 5. Debt and Credit Agreements			23
	Note 6. Derivative Instruments			24
	Note 7. Income Taxes			26
	Note 8. Compensation and Benefit Plans			28
	Note 9. Permanent Retirement of San Onofre			30
	Note 10. Other Investments			33
	Note 11. Regulatory Assets and Liabilities			34
	Note 12. Commitments and Contingencies			35
	Note 13. Preferred and Preference Stock of Utility			39
	Note 14. Accumulated Other Comprehensive Loss			39
	Note 15. Interest and Other Income and Other Expenses			40
	Note 16. Discontinued Operations			40
	Note 17. Supplemental Cash Flows Information			41
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				42
FORWARD-LOOKING STATEMENTS				42
MANAGEMENT OVERVIEW				44
	Highlights of Operating Results			44
	San Onofre Outage, Inspection and Retirement			45
	ERRA Balancing Account			49
	2015 General Rate Case			50
	Capital Program			50
	EME Chapter 11 Bankruptcy Filing			51
RESULTS OF OPERATIONS				52
	SCE			52
		Three months ended September 30, 2013 versus September 30, 2012		52
			Utility Earning Activities	53
			Utility Cost-Recovery Activities	53

i

		Nine months ended September 30, 2013 versus September 30, 2012		54
			Utility Earnings Activities	54
			Utility Cost-Recovery Activities	55
	Supplemental Operating Revenue Information			55
	Income Taxes			55
	Edison International Parent and Other			56
	Loss from Discontinued Operations (Net of Tax)			56
LIQUIDITY AND CAPITAL RESOURCES				56
	SCE			56
		Available Liquidity		56
		Capital Investment Plan		57
		Regulatory Proceedings		58
		Dividend Restrictions		59
		Margin and Collateral Deposits		59
	Edison International Parent and Other			59
	Historical Cash Flows			60
		SCE		60
		Edison International Parent and Other		61
	Contingencies			62
		Environmental Remediation		62
MARKET RISK EXPOSURES				62
	Commodity Price Risk			62
	Credit Risk			62
CRITICAL ACCOUNTING ESTIMATES AND POLICIES				63
NEW ACCOUNTING GUIDANCE				63
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				63
ITEM 4. CONTROLS AND PROCEDURES				63
	Disclosure Controls and Procedures			63
	Changes in Internal Control Over Financial Reporting			63
	Jointly Owned Utility Plant			63
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS				64
	EME Chapter 11 Bankruptcy Filing			64
	Catalina South Coast Air Quality Management District Environmental Proceeding			64
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS				64
	Purchases of Equity Securities by Edison International and Affiliated Purchasers			64
ITEM 6. EXHIBITS				65
SIGNATURES				66

This is a combined Form 10-Q separately filed by Edison International and Southern California Edison Company. Information contained herein relating to an individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.

ii

GLOSSARY

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

2012 Form 10-K	Edison International's and SCE's combined Annual Report on Form 10-K for the year-ended December 31, 2012
APS	Arizona Public Service Company
ARO(s)	asset retirement obligation(s)
BACT	best available control technology
Bankruptcy Code	Chapter 11 of the United States Bankruptcy Code
Bankruptcy Court	United States Bankruptcy Court for the Northern District of Illinois, Eastern Division
Bcf	billion cubic feet
CAA	Clean Air Act
CAISO	California Independent System Operator
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
EME	Edison Mission Energy
EMG	Edison Mission Group Inc.
EPS	earnings per share
ERRA	energy resource recovery account
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
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
GWh	gigawatt-hours
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
MHI	Mitsubishi Heavy Industries, Inc.
Mohave	two coal fueled electric generating facilities that have been decommissioned and site remediated located in Clark County, Nevada in which SCE holds a 56% ownership interest
Moody's	Moody's Investors Service
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
NRC	Nuclear Regulatory Commission
NSR	New Source Review
OII	Order Instituting Investigation

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)
Petition Date	December 17, 2012 (date on which EME and certain of its wholly-owned subsidiaries filed for protection under Chapter 11 of the Bankruptcy Code)
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 that has been permanently retired in which SCE holds a 78.21% ownership interest
SCE	Southern California Edison Company
SCR	selective catalytic reduction equipment
SDG&E	San Diego Gas & Electric
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or CPSD
Settlement Transaction	Certain transactions related to EME's Chapter 11 bankruptcy filing
Support Agreement	Transaction Support Agreement dated as of December 16, 2012 by and among Edison Mission Energy, Edison International and the Noteholders named therein
Tehachapi Project	an 11-segment project consisting of new and upgraded transmission lines and associated substations primarily built to enhance reliability and enable the delivery of renewable energy
US EPA	U.S. Environmental Protection Agency
VIE(s)	variable interest entity(ies)

iv

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1

PART I.    FINANCIAL INFORMATION

ITEM 1.     FINANCIAL STATEMENTS

Consolidated Statements of Income	Edison International
	Three months ended September 30,						Nine months ended September 30,
(in millions, except per-share amounts, unaudited)	2013			2012			2013			2012
Operating revenue	$	3,960		$	3,734		$	9,638		$	8,802
Fuel	95			83			249			220
Purchased power	1,713			1,612			3,569			3,049
Operation and maintenance	971			993			2,809			2,891
Depreciation, decommissioning and amortization	392			399			1,224			1,187
Asset impairment and others	—			(66		)	575			(65		)
Total operating expenses	3,171			3,021			8,426			7,282
Operating income	789			713			1,212			1,520
Interest and other income	28			38			91			110
Interest expense	(137		)	(131		)	(402		)	(390		)
Other expenses	(15		)	(10		)	(38		)	(36		)
Income from continuing operations before income taxes	665			610			863			1,204
Income tax expense	177			228			173			421
Income from continuing operations	488			382			690			783
Loss from discontinued operations, net of tax	(25		)	(167		)	(1		)	(360		)
Net income	463			215			689			423
Dividends on preferred and preference stock of utility	25			25			75			66
Net income attributable to Edison International common shareholders	$	438		$	190		$	614		$	357
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	463		$	357		$	615		$	717
Loss from discontinued operations, net of tax	(25		)	(167		)	(1		)	(360		)
Net income attributable to Edison International common shareholders	$	438		$	190		$	614		$	357
Basic earnings (loss) per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding	326			326			326			326
Continuing operations	$	1.42		$	1.09		$	1.88		$	2.20
Discontinued operations	(0.08		)	(0.51		)	—			(1.11		)
Total	$	1.34		$	0.58		$	1.88		$	1.09
Diluted earnings (loss) per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities	328			329			329			328
Continuing operations	$	1.41		$	1.09		$	1.87		$	2.18
Discontinued operations	(0.07		)	(0.51		)	—			(1.09		)
Total	$	1.34		$	0.58		$	1.87		$	1.09
Dividends declared per common share	$	0.3375		$	0.325		$	1.0125		$	0.975

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

2

Consolidated Statements of Comprehensive Income	Edison International
	Three months ended September 30,					Nine months ended September 30,
(in millions, unaudited)	2013		2012			2013			2012
Net income	$	463	$	215		$	689		$	423
Other comprehensive income (loss), net of tax:
Pension and postretirement benefits other than pensions:
Net loss arising during the period, net of income tax benefit of $4 and $3 for the nine months ended September 30, 2013 and 2012, respectively	—		—			(2		)	(3		)
Amortization of net loss included in net income, net of income tax expense of $1 and $2 for the three months ended September 30, 2013 and 2012 and $3 and $7 for the nine months ended September 30, 2013 and 2012, respectively	3		4			10			12
Unrealized loss on derivatives qualified as cash flow hedges:
Unrealized holding loss arising during the period, net of income tax benefit of $11 for the three months and $13 for the nine months ended September 30, 2012, respectively	—		(16		)	—			(19		)
Reclassification adjustments included in net income, net of income tax expense (benefit) of $1 for the three months and $(12) for the nine months ended September 30, 2012, respectively	—		1			—			(19		)
Other comprehensive income (loss), net of tax	3		(11		)	8			(29		)
Comprehensive income	466		204			697			394
Less: Comprehensive income attributable to noncontrolling interests	25		25			75			66
Comprehensive income attributable to Edison International	$	441	$	179		$	622		$	328

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

3

Consolidated Balance Sheets	Edison International
(in millions, unaudited)	September 30, 2013		December 31, 2012
ASSETS
Cash and cash equivalents	$	610	$	170
Receivables, less allowances of $72 and $75 for uncollectible accounts at respective dates	1,174		762
Accrued unbilled revenue	798		550
Inventory	272		340
Prepaid taxes	27		22
Derivative assets	47		129
Margin and collateral deposits	14		8
Regulatory assets	506		572
Other current assets	155		119
Total current assets	3,603		2,672
Nuclear decommissioning trusts	4,332		4,048
Other investments	201		186
Total investments	4,533		4,234
Utility property, plant and equipment, less accumulated depreciation of $7,817 and $7,424 at respective dates	29,734		30,200
Nonutility property, plant and equipment, less accumulated depreciation of $74 and $123 at respective dates	75		73
Total property, plant and equipment	29,809		30,273
Derivative assets	207		85
Restricted deposits	4		4
Regulatory assets	8,015		6,422
Other long-term assets	527		704
Total long-term assets	8,753		7,215
Total assets	$	46,698	$	44,394

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

4

Consolidated Balance Sheets	Edison International
(in millions, except share amounts, unaudited)	September 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
Short-term debt	$	1,528		$	175
Current portion of long-term debt	401			—
Accounts payable	1,240			1,423
Accrued taxes	103			61
Accrued interest	102			176
Customer deposits	199			193
Derivative liabilities	174			126
Regulatory liabilities	629			536
Deferred income taxes	159			64
Other current liabilities	854			990
Total current liabilities	5,389			3,744
Long-term debt	9,232			9,231
Deferred income taxes	6,546			6,127
Deferred investment tax credits	106			104
Customer advances	132			149
Derivative liabilities	1,137			939
Pensions and benefits	2,237			2,614
Asset retirement obligations	3,371			2,782
Regulatory liabilities	4,989			5,214
Other deferred credits and other long-term liabilities	2,117			2,299
Total deferred credits and other liabilities	20,635			20,228
Total liabilities	35,256			33,203
Commitments and contingencies (Note 12)
Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at each date)	2,397			2,373
Accumulated other comprehensive loss	(79		)	(87		)
Retained earnings	7,371			7,146
Total Edison International's common shareholders' equity	9,689			9,432
Preferred and preference stock of utility	1,753			1,759
Total noncontrolling interests	1,753			1,759
Total equity	11,442			11,191
Total liabilities and equity	$	46,698		$	44,394

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

5

Consolidated Statements of Cash Flows	Edison International
	Nine months ended September 30,
(in millions, unaudited)	2013			2012
Cash flows from operating activities:
Net income	$	689		$	423
Less: Loss from discontinued operations	(1		)	(360		)
Income from continuing operations	690			783
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,224			1,187
Regulatory impacts of net nuclear decommissioning trust earnings	265			147
Other amortization and other	54			51
Asset impairment	575			—
Gain on sale of assets and other	(2		)	(65		)
Stock-based compensation	18			24
Deferred income taxes and investment tax credits	257			176
Proceeds from U.S. treasury grants	—			29
Changes in operating assets and liabilities:
Receivables	(406		)	(328		)
Inventory	68			13
Margin and collateral deposits, net of collateral received	(74		)	6
Prepaid taxes	(5		)	319
Other current assets	(276		)	(254		)
Accounts payable	155			162
Accrued taxes	27			61
Other current liabilities	(130		)	(124		)
Derivative assets and liabilities, net	207			1
Regulatory assets and liabilities, net	94			210
Other assets	127			(26		)
Other liabilities	(615		)	326
Operating cash flows from continuing operations	2,253			2,698
Operating cash flows from discontinued operations, net	—			(540		)
Net cash provided by operating activities	2,253			2,158
Cash flows from financing activities:
Long-term debt issued	398			395
Long-term debt issuance costs	(4		)	(4		)
Long-term debt repaid	(5		)	(4		)
Bonds remarketed, net	195			—
Bonds purchased	(196		)	—
Preference stock issued, net	387			804
Preference stock redeemed	(400		)	(75		)
Short-term debt financing, net	1,352			(31		)
Settlements of stock-based compensation, net	(40		)	(34		)
Dividends to noncontrolling interests	(82		)	(63		)
Dividends paid	(330		)	(318		)
Financing cash flows from continuing operations	1,275			670
Financing cash flows from discontinued operations, net	—			354
Net cash provided by financing activities	$	1,275		$	1,024

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

6

Consolidated Statements of Cash Flows	Edison International
	Nine months ended September 30,
(in millions, unaudited)	2013			2012
Cash flows from investing activities:
Capital expenditures	$	(2,761	)	$	(3,105	)
Proceeds from sale of nuclear decommissioning trust investments	4,574			1,525
Purchases of nuclear decommissioning trust investments and other	(4,857		)	(1,689		)
Proceeds from sale of interest in project, net	—			107
Investments in new businesses	(18		)	—
Customer advances for construction and other investments	(26		)	7
Investing cash flows from continuing operations	(3,088		)	(3,155		)
Investing cash flows from discontinued operations, net	—			(361		)
Net cash used by investing activities	(3,088		)	(3,516		)
Net increase (decrease) in cash and cash equivalents	440			(334		)
Cash and cash equivalents at beginning of period	170			1,469
Cash and cash equivalents at end of period	610			1,135
Cash and cash equivalents from discontinued operations	—			753
Cash and cash equivalents from continuing operations	$	610		$	382

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

7

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8

Consolidated Statements of Income Southern California Edison Company

	Three months ended September 30,						Nine months ended September 30,
(in millions, unaudited)	2013			2012			2013			2012
Operating revenue	$	3,957		$	3,731		$	9,631		$	8,794
Fuel	95			82			249			220
Purchased power	1,713			1,612			3,569			3,049
Operation and maintenance	875			906			2,540			2,622
Depreciation, decommissioning and amortization	392			399			1,223			1,187
Property and other taxes	78			73			229			229
Asset impairment	—			—			575			—
Total operating expenses	3,153			3,072			8,385			7,307
Operating income	804			659			1,246			1,487
Interest and other income	27			38			89			108
Interest expense	(131		)	(124		)	(384		)	(373		)
Other expenses	(15		)	(9		)	(38		)	(36		)
Income before income taxes	685			564			913			1,186
Income tax expense	183			176			196			384
Net income	502			388			717			802
Less: Dividends on preferred and preference stock	25			25			75			66
Net income available for common stock	$	477		$	363		$	642		$	736

Consolidated Statements of Comprehensive Income
	Three months ended September 30,				Nine months ended September 30,
(in millions, unaudited)	2013		2012		2013			2012
Net income	$	502	$	388	$	717		$	802
Other comprehensive income (loss), net of tax:
Pension and postretirement benefits other than pensions:
Net loss arising the during period, net of income tax benefit of $3 for both the nine months ended September 30, 2013 and 2012	—		—		(4		)	(4		)
Amortization of net loss included in net income, net of income tax expense of $1 for both the three months ended September 30, 2013 and 2012 and $3 and $4 for the nine months ended September 30, 2013 and 2012, respectively	2		1		5			5
Other comprehensive income, net of tax	2		1		1			1
Comprehensive income	$	504	$	389	$	718		$	803

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

9

Consolidated Balance Sheets Southern California Edison Company

(in millions, unaudited)	September 30, 2013		December 31, 2012
ASSETS
Cash and cash equivalents	$	522	$	45
Receivables, less allowances of $72 and $75 for uncollectible accounts at respective dates	1,127		755
Accrued unbilled revenue	798		550
Inventory	272		340
Prepaid taxes	22		48
Derivative assets	47		129
Regulatory assets	506		572
Other current assets	167		123
Total current assets	3,461		2,562
Nuclear decommissioning trusts	4,332		4,048
Other investments	130		116
Total investments	4,462		4,164
Utility property, plant and equipment, less accumulated depreciation of $7,817 and $7,424 at respective dates	29,734		30,200
Nonutility property, plant and equipment, less accumulated depreciation of $68 and $117 at respective dates	70		70
Total property, plant and equipment	29,804		30,270
Derivative assets	207		85
Regulatory assets	8,015		6,422
Other long-term assets	372		531
Total long-term assets	8,594		7,038
Total assets	$	46,321	$	44,034

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

10

Consolidated Balance Sheets Southern California Edison Company

(in millions, except share amounts, unaudited)	September 30, 2013			December 31, 2012
LIABILITIES AND EQUITY
Short-term debt	$	1,354		$	175
Current portion of long-term debt	400			—
Accounts payable	1,228			1,297
Accrued taxes	148			72
Accrued interest	101			172
Customer deposits	199			193
Derivative liabilities	174			126
Regulatory liabilities	629			536
Deferred income taxes	159			81
Other current liabilities	842			861
Total current liabilities	5,234			3,513
Long-term debt	8,828			8,828
Deferred income taxes	7,033			6,669
Deferred investment tax credits	106			104
Customer advances	132			149
Derivative liabilities	1,137			939
Pensions and benefits	1,726			2,245
Asset retirement obligations	3,371			2,782
Regulatory liabilities	4,989			5,214
Other deferred credits and other long-term liabilities	1,774			1,848
Total deferred credits and other liabilities	20,268			19,950
Total liabilities	34,330			32,291
Commitments and contingencies (Note 12)
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	589			581
Accumulated other comprehensive loss	(28		)	(29		)
Retained earnings	7,467			7,228
Total common shareholder's equity	10,196			9,948
Preferred and preference stock	1,795			1,795
Total equity	11,991			11,743
Total liabilities and equity	$	46,321		$	44,034

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

11

Consolidated Statements of Cash Flows Southern California Edison Company

	Nine months ended September 30,
(in millions, unaudited)	2013			2012
Cash flows from operating activities:
Net income	$	717		$	802
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,223			1,187
Regulatory impacts of net nuclear decommissioning trust earnings	265			147
Other amortization	55			55
Asset impairment	575			—
Stock-based compensation	11			13
Deferred income taxes and investment tax credits	197			426
Proceeds from U.S. treasury grants	—			29
Changes in operating assets and liabilities:
Receivables	(371		)	(336		)
Inventory	68			13
Margin and collateral deposits, net of collateral received	(74		)	6
Prepaid taxes	26			230
Other current assets	(279		)	(295		)
Accounts payable	174			165
Accrued taxes	76			49
Other current liabilities	(131		)	(120		)
Derivative assets and liabilities, net	207			63
Regulatory assets and liabilities, net	94			147
Other assets	142			(26		)
Other liabilities	(629		)	101
Net cash provided by operating activities	2,346			2,656
Cash flows from financing activities:
Long-term debt issued	398			395
Long-term debt issuance costs	(4		)	(4		)
Long-term debt repaid	(5		)	(4		)
Bonds remarketed, net	195			—
Bonds purchased	(196		)	—
Preference stock issued, net	387			804
Preference stock redeemed	(400		)	(75		)
Short-term debt financing, net	1,178			(45		)
Settlements of stock-based compensation, net	(36		)	(24		)
Dividends paid	(321		)	(411		)
Net cash provided by financing activities	1,196			636
Cash flows from investing activities:
Capital expenditures	(2,761		)	(3,105		)
Proceeds from sale of nuclear decommissioning trust investments	4,574			1,525
Purchases of nuclear decommissioning trust investments and other	(4,857		)	(1,689		)
Customer advances for construction and other investments	(21		)	10
Net cash used by investing activities	(3,065		)	(3,259		)
Net increase in cash and cash equivalents	477			33
Cash and cash equivalents, beginning of period	45			57
Cash and cash equivalents, end of period	$	522		$	90

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

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1.    Summary of Significant Accounting Policies

Organization and Basis of Presentation

Edison International is the parent holding company of Southern California Edison Company ("SCE"). 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. Edison International is also the parent company of nonutility subsidiaries that are engaged in competitive businesses related to the delivery or use of electricity. Such competitive business activities are currently not material to report as a separate business segment. These combined notes to the consolidated financial statements apply to both Edison International and SCE unless otherwise described. Edison International's consolidated financial statements include the accounts of Edison International, SCE and other wholly owned and controlled subsidiaries. References to Edison International refer to the consolidated group of Edison International and its subsidiaries. References to Edison International Parent and Other refer to Edison International Parent and its nonutility subsidiaries. SCE's consolidated financial statements include the accounts of SCE and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated from the consolidated financial statements.

Edison International's and SCE's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements" included in the 2012 Form 10-K. The same accounting policies are followed for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2013, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2012 Form 10-K.

Beginning in the fourth quarter of 2012, Edison Mission Energy ("EME") met the definition of a discontinued operation and was classified separately in Edison International's consolidated financial statements. Except as indicated, amounts in the notes to the consolidated financial statements relate to continuing operations of Edison International. See Note 16 for information related to discontinued operations.

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, 2013 are not necessarily indicative of the operating results for the full year.

The December 31, 2012 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. Generally, the carrying value of cash equivalents equals the fair value, as these investments have original maturities of three months or less. The cash equivalents were as follows:

	Edison International				SCE
(in millions)	September 30, 2013		December 31, 2012		September 30, 2013		December 31, 2012
Money market funds	$	518	$	107	$	453	$	5

Cash is temporarily invested until required for check clearing from the primary disbursement accounts. Checks issued, but not yet paid by the financial institution, are reclassified from cash to accounts payable at the end of each reporting period as follows:

	Edison International				SCE
(in millions)	September 30, 2013		December 31, 2012		September 30, 2013		December 31, 2012
Uncleared checks reclassified to accounts payable	$	202	$	247	$	201	$	242

13

Inventory

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

(in millions)	September 30, 2013		December 31, 2012
Materials, supplies and spare parts	$	250	$	319
Fuel	22		21
Total inventory	$	272	$	340

As a result of the permanent retirement of San Onofre, SCE has reclassified $100 million of its inventory to a regulatory asset, see Note 9 for further details.

Greenhouse Gas Allowances

SCE is allocated greenhouse gas ("GHG") allowances annually which it is then required to sell them into quarterly auctions. GHG proceeds from the auction are recorded as a regulatory liability to be refunded to customers. SCE purchases GHG allowances from quarterly auctions or bilateral parties to satisfy its compliance obligations and recovers such costs of GHG from customers. GHG allowances held for use are classified as "Other current assets" on the consolidated balance sheets and are stated at the lower of weighted-average cost or market.

Earnings Per Share

Edison International computes earnings per share ("EPS") using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's participating securities are stock-based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. EPS attributable to Edison International common shareholders was computed as follows:

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2013		2012		2013		2012
Basic earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	463	$	357	$	615	$	717
Weighted average common shares outstanding	326		326		326		326
Basic earnings per share – continuing operations	$	1.42	$	1.09	$	1.88	$	2.20
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	463	$	357	$	615	$	717
Income impact of assumed conversions	—		—		1		—
Income from continuing operations available to common shareholders and assumed conversions	$	463	$	357	$	616	$	717
Weighted average common shares outstanding	326		326		326		326
Incremental shares from assumed conversions	2		3		3		2
Adjusted weighted average shares – diluted	328		329		329		328
Diluted earnings per share – continuing operations	$	1.41	$	1.09	$	1.87	$	2.18

Stock-based compensation awards to purchase 4,109,363 and 3,238,581 shares of common stock for the three months ended September 30, 2013 and 2012, respectively, and 4,109,363 and 4,819,683 for the nine months ended September 30, 2013 and 2012, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares during the respective periods and, therefore, the effect would have been antidilutive.

14

Asset Retirement Obligation

SCE is in the process of developing a comprehensive decommissioning plan following its decision to permanently retire San Onofre. See Note 9 for further details. The asset retirement obligation ("ARO") liability related to San Onofre increased by $455 million in the second quarter of 2013 based on an updated decommissioning cost estimate for the retirement of both San Onofre Units 2 and 3. The ARO liability related to San Onofre at September 30, 2013 was $2.71 billion.

The following table summarizes the changes in SCE's ARO liability, including San Onofre and Palo Verde:

(in millions)	September 30, 2013		December 31, 2012
Beginning balance	$	2,782	$	2,610
Accretion expense1	134		161
Revisions	455		12
Liabilities settled	—		(1		)
Ending balance	$	3,371	$	2,782

¹  An asset retirement obligation represents the present value of a future obligation. Accretion expense is an increase in the liability to account for the time value of money resulting from discounting.

Related-Party Transactions

In 2008, EME was awarded by SCE, through a competitive bidding process, a 10-year power sales contract with SCE for the output of a 479 MW gas-fired peaking facility referred to as the Walnut Creek project. The power sales agreement was approved by the CPUC and FERC in 2008. Deliveries under the power sales agreement commenced in June 2013 and the expense for power purchased was $64 million and $70 million for the three- and nine-months ended September 30, 2013, respectively.

New Accounting Guidance

Accounting Guidance Adopted in 2013

Offsetting Assets and Liabilities

In January 2013, the FASB issued accounting standard updates modifying the disclosure requirements about the nature of an entity's rights of offsetting recognized assets and liabilities in the statement of financial position under master netting agreements and similar arrangements associated with derivative instruments, repurchase agreements and securities lending transactions. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and descriptions of setoff rights. Edison International and SCE adopted this guidance effective January 1, 2013. The adoption of this standard did not impact the consolidated income statements, balance sheets or cash flows of Edison International or SCE. See Note 6 for further details.

Items Reclassified out of Accumulated Other Comprehensive Income

In February 2013, the FASB issued an accounting standards update which requires disclosure related to items reclassified out of accumulated other comprehensive income ("AOCI"). The guidance requires companies to present separately, for each component of other comprehensive income, current period reclassifications and the remainder of the current-period other comprehensive income. In addition, for certain current period reclassifications, an entity is required to disclose the effect of the item reclassified out of AOCI on the respective line item(s) of net income. Edison International and SCE adopted this guidance effective January 1, 2013. See Note 14 for further details.

Accounting Guidance Not Yet Adopted

In July 2013, the FASB issued an accounting standards update that will require that an unrecognized tax benefit be presented on the balance sheet as a reduction of a deferred tax asset for a net operating loss ("NOL") or tax credit carryforward under certain circumstances. This proposal is effective January 1, 2014 and is not expected to have a material impact on the consolidated financial statements.

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Note 2.    Consolidated Statements of Changes in Equity

The following table provides Edison International's changes in equity for the nine months ended September 30, 2013:

	Equity Attributable to Edison International											Noncontrolling Interests
(in millions)	Common Stock		Accumulated Other Comprehensive Loss			Retained Earnings			Subtotal			Preferred and Preference Stock			Total Equity
Balance at December 31, 2012	$	2,373	$	(87	)	$	7,146		$	9,432		$	1,759		$	11,191
Net income	—		—			614			614			75			689
Other comprehensive income	—		8			—			8			—			8
Common stock dividends declared ($1.0125 per share)	—		—			(330		)	(330		)	—			(330		)
Dividends, distributions to noncontrolling interests	—		—			—			—			(75		)	(75		)
Stock-based compensation and other	5		—			(45		)	(40		)	—			(40		)
Noncash stock-based compensation and other	19		—			(6		)	13			(1		)	12
Issuance of preference stock	—		—			—			—			387			387
Redemption of preference stock	—		—			(8		)	(8		)	(392		)	(400		)
Balance at September 30, 2013	$	2,397	$	(79	)	$	7,371		$	9,689		$	1,753		$	11,442

During the first quarter of 2013, SCE redeemed all outstanding shares of Series B and C preference stock and charged the issuance costs to retained earnings.

The following table provides Edison International's changes in equity for the nine months ended September 30, 2012:

	Equity Attributable to Edison International												Noncontrolling Interests
(in millions)	Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings			Subtotal			Other			Preferred and Preference Stock			Total Equity
Balance at December 31, 2011	$	2,360		$	(139	)	$	7,834		$	10,055		$	2		$	1,029		$	11,086
Net income	—			—			357			357			—			66			423
Other comprehensive loss	—			(29		)	—			(29		)	—			—			(29		)
Contributions from noncontrolling interests	—			—			—			—			238			—			238
Transfer of assets to Capistrano Wind Partners	(21		)	—			—			(21		)	—			—			(21		)
Common stock dividends declared ($0.975 per share)	—			—			(318		)	(318		)	—			—			(318		)
Dividends, distributions to noncontrolling interests and other	—			—			—			—			(2		)	(66		)	(68		)
Stock-based compensation and other	19			—			(64		)	(45		)	—			—			(45		)
Noncash stock-based compensation and other	27			—			(2		)	25			—			—			25
Issuance of preference stock	—			—			—			—			—			804			804
Redemption of preference stock	—			—			(1		)	(1		)	—			(74		)	(75		)
Balance at September 30, 2012	$	2,385		$	(168	)	$	7,806		$	10,023		$	238		$	1,759		$	12,020

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The following table provides SCE's changes in equity for the nine months ended September 30, 2013:

	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, 2012	$	2,168	$	581		$	(29	)	$	7,228		$	1,795		$	11,743
Net income	—		—			—			717			—			717
Other comprehensive income	—		—			1			—			—			1
Dividends declared on common stock	—		—			—			(360		)	—			(360		)
Dividends declared on preferred and preference stock	—		—			—			(75		)	—			(75		)
Stock-based compensation and other	—		3			—			(39		)	—			(36		)
Noncash stock-based compensation and other	—		10			—			4			—			14
Issuance of preference stock	—		(13		)	—			—			400			387
Redemption of preference stock	—		8			—			(8		)	(400		)	(400		)
Balance at September 30, 2013	$	2,168	$	589		$	(28	)	$	7,467		$	1,795		$	11,991

During the first quarter of 2013, SCE redeemed all outstanding shares of Series B and C preference stock and charged the issuance costs to retained earnings.

The following table provides SCE's 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

Note 3.    Variable Interest Entities

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has power purchase agreements ("PPAs") that are classified as variable interests in variable interest entities ("VIEs"), including tolling agreements through which SCE provides the natural gas to fuel the plants and 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

17

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 in the 2012 Form 10-K. As a result, there is no significant potential exposure to loss to SCE from its variable interest in these VIEs. The aggregate contracted capacity dedicated to SCE for these VIE projects was 5,290 MW and 2,094 MW at September 30, 2013 and 2012, respectively, and the amounts that SCE paid to these projects were $330 million and $158 million for the three months ended September 30, 2013 and 2012, respectively, and $527 million and $292 million for the nine months ended September 30, 2013 and 2012, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.

Unconsolidated Trusts of SCE

SCE Trust I and Trust II were formed in 2012 and 2013, respectively, for the exclusive purpose of issuing the 5.625% and 5.10% trust preference securities, respectively (“trust securities”). The trusts are VIEs. SCE has concluded that it is not the primary beneficiary of these VIEs as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trusts.

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.

In January 2013, SCE Trust II issued $400 million (aggregate liquidation preference) of 5.10% 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 G Preference Stock issued by SCE in the principal amount of $400 million (cumulative, $2,500 per share liquidation value) and which have substantially the same payment terms as the trust securities.

The Series F and Series G Preference Stock and the corresponding trust securities do not have a maturity date. Upon any redemption of any shares of the Series F or Series G Preference Stock, a corresponding dollar amount of trust securities will be redeemed by the applicable trust (for further information see Note 13). The applicable trust will make distributions at the same rate and on the same dates on the applicable series of trust securities when and if the SCE board of directors declares and makes dividend payments on the Series F or Series G Preference Stock. The applicable trusts will use any dividends it receives on the Series F or Series G Preference Stock to make its corresponding distributions on the applicable series of trust securities. If SCE does not make a dividend payment to either 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 trust distributions, if and when SCE pays dividends on the Series F and Series G Preference Stock.

The Trust I balance sheet as of September 30, 2013 and December 31, 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 dividend distributions of $7 million and $7 million each for the three months ended September 30, 2013 and 2012, respectively, and $20 million and $10 million each for the nine months ended September 30, 2013 and 2012, respectively.

The Trust II balance sheet as of September 30, 2013, consisted of an investment of $400 million in the Series G Preference Stock, $400 million of trust securities and $10,000 of common stock. The trust's income statement consisted of dividend income and dividend distributions of $5 million each for the three months ended September 30, 2013 and $14 million each for the nine months ended September 30, 2013.

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. As of September 30, 2013 and December 31, 2012, nonperformance risk was not material for Edison International and SCE.

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).

18

SCE

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

	September 30, 2013
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at fair value
Money market funds	$	453	$	—	$	—		$	—		$	453
Mutual funds	29		—		—			—			29
Derivative contracts:
Congestion revenue rights	—		—		245			—			245
Electricity	—		1		—			—			1
Natural gas	—		1		—			(1		)	—
Tolling	—		—		8			—			8
Subtotal of derivative contracts	—		2		253			(1		)	254
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks2	2,027		—		—			—			2,027
U.S. government and agency securities	823		101		—			—			924
Municipal bonds	—		796		—			—			796
Corporate bonds	—		221		—			—			221
Short-term investments, primarily cash equivalents4	322		45		—			—			367
Subtotal of nuclear decommissioning trusts	3,172		1,163		—			—			4,335
Total assets	3,662		1,165		253			(1		)	5,079
Liabilities at fair value
Derivative contracts:
Electricity	—		5		12			(3		)	14
Natural gas	—		43		—			(18		)	25
Tolling	—		—		1,272			—			1,272
Subtotal of derivative contracts	—		48		1,284			(21		)	1,311
Total liabilities	—		48		1,284			(21		)	1,311
Net assets (liabilities)	$	3,662	$	1,117	$	(1,031	)	$	20		$	3,768

19

	December 31, 2012
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral1			Total
Assets at fair value
Money market funds	$	5	$	—	$	—		$	—		$	5
Derivative contracts:
Congestion revenue rights	—		—		186			—			186
Electricity	—		—		31			(13		)	18
Natural gas	—		8		—			(2		)	6
Tolling	—		—		4			—			4
Subtotal of derivative contracts	—		8		221			(15		)	214
Long-term disability plan	8		—		—			—			8
Nuclear decommissioning trusts:
Stocks2	2,271		—		—			—			2,271
Municipal bonds	—		644		—			—			644
U.S. government and agency securities	477		126		—			—			603
Corporate bonds	—		410		—			—			410
Short-term investments, primarily cash equivalents4	121		—		—			—			121
Subtotal of nuclear decommissioning trusts	2,869		1,180		—			—			4,049
Total assets	2,882		1,188		221			(15		)	4,276
Liabilities at fair value
Derivative contracts:
Electricity	—		2		5			(2		)	5
Natural gas	—		113		2			(60		)	55
Tolling	—		—		1,005			—			1,005
Subtotal of derivative contracts	—		115		1,012			(62		)	1,065
Total liabilities	—		115		1,012			(62		)	1,065
Net assets (liabilities)	$	2,882	$	1,073	$	(791	)	$	47		$	3,211

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  Approximately 69% and 66% of SCE's equity investments were located in the United States at September 30, 2013 and December 31, 2012, respectively.

³  At September 30, 2013 and December 31, 2012, SCE's corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $32 million and $56 million, respectively.

⁴  Excludes net payables of $3 million and $1 million at September 30, 2013 and December 31, 2012, respectively, of interest and dividend receivables as well as receivables and payables related to SCE's pending securities sales and purchases.

Edison International Parent and Other

Assets measured at fair value consisted of money market funds of $518 million and $107 million at September 30, 2013 and December 31, 2012, respectively, classified as Level 1.

20

SCE Fair Value of Level 3

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

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2013			2012			2013			2012
Fair value of net liabilities at beginning of period	$	(967	)	$	(739	)	$	(791	)	$	(754	)
Total realized/unrealized gains (losses):
Included in regulatory assets and liabilities1	(50		)	(180		)	(205		)	(203		)
Purchases	19			33			56			84
Settlements	(33		)	(44		)	(91		)	(57		)
Fair value of net liabilities at end of period	$	(1,031	)	$	(930	)	$	(1,031	)	$	(930	)
Change during the period in unrealized losses related to assets and liabilities held at the end of the period	$	(65	)	$	(222	)	$	(198	)	$	(244	)

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

Edison International and SCE recognize the fair value for transfers in and transfers out of each level at the end of each reporting period. There were no transfers between any levels during 2013 and 2012.

Valuation Techniques Used to Determine Fair Value

Level 1

The fair value of Edison International and SCE's 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 and derivatives, U.S. treasury securities, mutual funds and money market funds.

Level 2

SCE's Level 2 assets and liabilities include fixed income securities and over-the-counter derivatives. The fair value of fixed income securities is determined using a market 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. For further discussion on fixed income securities, see "—Nuclear Decommissioning Trusts" below.

The fair value of SCE's over-the-counter derivative contracts is determined using an income approach. SCE uses 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 SCE's 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 SCE's risk management department, which reports to SCE's 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 SCE's valuation techniques and significant unobservable inputs used to determine fair value for Level 3 assets and liabilities:

	Fair Value (in millions)							Significant	Range
September 30, 2013	Assets			Liabilities			Valuation Technique(s)	Unobservable Input	(Weighted Average)
Electricity:
Options	$	2		$	10		Option model	Volatility of gas prices	24% - 30% (28%)
								Volatility of power prices	28% - 45% (39%)
								Power prices	$40.60 - $49.80 ($43.50)
Forwards	—			4			Discounted cash flow	Power prices	$7.70 - $40.80 ($31.40)
CRRs	245			—			Market simulation model	Load forecast	7,603 MW - 24,896 MW
								Power prices	$(9.86) - $108.56
								Gas prices	$3.50 - $7.10
Tolling	8			1,272			Option model	Volatility of gas prices	16% - 30% (19%)
								Volatility of power prices	25% - 45% (29%)
								Power prices	$35.90 - $62.60 ($46.90)
Netting	(2		)	(2		)
Total derivative contracts	$	253		$	1,284

	Fair Value (in millions)							Significant	Range
December 31, 2012	Assets			Liabilities			Valuation Technique(s)	Unobservable Input	(Weighted Average)
Electricity:
Options	$	40		$	12		Option model	Volatility of gas prices	25% - 36% (33%)
								Volatility of power prices	29% - 64% (42%)
								Power prices	$41.70 - $59.20 ($47.00)
Forwards	2			4			Discounted cash flow	Power prices	$23.10 - $44.90 ($31.10)
CRRs	186			—			Market simulation model	Load forecast	7,597 MW - 26,612 MW
								Power prices	$(13.90) - $226.75
								Gas prices	$2.95 - $7.78
Gas options	—			2			Option model	Volatility of gas prices	28% - 36% (34%)
Tolling	4			1,005			Option model	Volatility of gas prices	17% - 36% (22%)
								Volatility of power prices	26% - 64% (29%)
								Power prices	$35.00 - $84.10 ($55.40)
Netting	(11		)	(11		)
Total derivative contracts	$	221		$	1,012

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Level 3 Fair Value Sensitivity

Gas Options, Electricity Options, and Tolling Arrangements

The fair values of SCE's 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) fair value.

Congestion Revenue Rights

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.

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 Edison International and SCE's long-term debt is as follows:

	September 30, 2013				December 31, 2012
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
SCE	$	8,828	$	9,590	$	8,828	$	10,505
Edison International	9,232		10,016		9,231		10,944

Fair value of Edison International and SCE's 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 Edison International and SCE's trade receivables and payables, other investments, and short-term debt approximates fair value.

Note 5.    Debt and Credit Agreements

Long-Term Debt

In March 2013, SCE issued $400 million of 3.90% first and refunding mortgage bonds due in 2043. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

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Credit Agreements and Short-Term Debt

In July 2013, SCE and Edison International Parent amended their credit facilities to extend the maturity dates to July 2018 for $2.6 billion and $1.182 billion, respectively. The remaining $150 million and $68 million of the SCE and Edison International Parent credit facilities, respectively, will mature in May 2017.

At September 30, 2013, SCE's outstanding commercial paper was $1.35 billion at a weighted-average interest rate of 0.25%. This commercial paper was supported by a $2.75 billion multi-year revolving credit facility. At September 30, 2013, letters of credit issued under SCE's credit facility aggregated $140 million and are scheduled to expire in twelve months or less. At December 31, 2012, the outstanding commercial paper was $175 million at a weighted-average interest rate of 0.37%.

At September 30, 2013, Edison International Parent's outstanding short-term debt was $174 million at a weighted-average interest rate of 1.46%. This short-term debt was supported by a $1.25 billion multi-year revolving credit facility. At December 31, 2012, Edison International had no outstanding short-term debt.

Financing Subsequent to September 30, 2013

In October 2013, SCE issued $200 million of floating rate due in 2014, $600 million of 3.50% due in 2023, and $800 million of 4.65% first and refunding mortgage bonds due in 2043. The proceeds from these bonds were used to redeem $800 million of outstanding first mortgage bonds in October 2013 (due in March 2014), to repay commercial paper borrowings and to fund SCE's capital program.

Note 6.    Derivative Instruments

Derivative financial instruments are used to manage exposure to commodity price risk. SCE manages commodity price risk in part by entering into forward commodity transactions, including options, swaps and forwards, tolling arrangements and CRRs. To mitigate credit and default risk SCE enters into master netting agreements or similar agreements whenever possible. 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"), and as a result, exposure to commodity price and credit and default risks are not expected to impact earnings, but may impact cash flows.

Commodity Price Risk

Commodity price risk represents the potential impact that can be caused by a change in the market value of a particular commodity. 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.

Credit and Default Risk

Credit and default risk represents the potential impact that can be caused if a counterparty were to default on its contractual obligations and SCE would be exposed to 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 the sales of excess power and realized gains on derivative instruments.

Certain power contracts contain master netting agreements or similar agreements, which generally allows counterparties subject to the agreement to set-off amounts when certain criteria are met, such as in the event of default. The objective of netting is to reduce credit exposure. Additionally, to reduce SCE's risk exposures counterparties may be required to pledge collateral depending on the creditworthiness of each counterparty and the risk associated with the transaction.

Certain 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 net fair value of all derivative liabilities with these credit-risk-related contingent features was $53 million and $6 million as of September 30, 2013 and December 31, 2012, 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, 2013, SCE would be required to post collateral in the amount of $14 million, excluding the impact of unpaid closed positions as their settlement is not impacted by the credit-risk-related contingent features.

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Fair Value of Derivative Instruments

SCE presents its derivative assets and liabilities on a net basis on its consolidated balance sheets when subject to master netting agreements or similar agreements. Derivative positions are offset against margin and cash collateral deposits. In addition, SCE has provided collateral in the form of letters of credit. Collateral requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments and other factors. The following table summarizes the gross and net fair values of SCE's commodity derivative instruments:

	September 30, 2013
	Derivative Assets								Derivative Liabilities
(in millions)	Short-Term			Long-Term		Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Commodity derivative contracts
Gross amounts recognized	$	53		$	207	$	260		$	195		$	1,143		$	1,338		$	1,078
Gross amounts offset in the consolidated balance sheets	(6		)	—		(6		)	(6		)	—			(6		)	—
Cash collateral posted1	—			—		—			(15		)	(6		)	(21		)	(21		)
Net amounts presented in the consolidated balance sheets	$	47		$	207	$	254		$	174		$	1,137		$	1,311		$	1,057

	December 31, 2012
	Derivative Assets									Derivative Liabilities
(in millions)	Short-Term			Long-Term			Subtotal			Short-Term			Long-Term			Subtotal			Net Liability
Commodity derivative contracts
Gross amounts recognized	$	151		$	91		$	242		$	186		$	954		$	1,140		$	898
Gross amounts offset in the consolidated balance sheets	(22		)	(6		)	(28		)	(22		)	(6		)	(28		)	—
Cash collateral posted1	—			—			—			(38		)	(9		)	(47		)	(47		)
Net amounts presented in the consolidated balance sheets	$	129		$	85		$	214		$	126		$	939		$	1,065		$	851

¹  In addition, at September 30, 2013 and December 31, 2012, SCE had posted $14 million and $8 million, respectively, of collateral that is not offset against the derivative liabilities and is reflected in "Other current assets" on the consolidated balance sheets.

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 SCE's economic hedging activity:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2013			2012			2013			2012
Realized losses	$	(15	)	$	(77	)	$	(38	)	$	(199	)
Unrealized losses	(41		)	(91		)	(159		)	(29		)

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Notional Volumes of Derivative Instruments

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

		Economic Hedges
Commodity	Unit of Measure	September 30, 2013	December 31, 2012
Electricity options, swaps and forwards	GWh	8,964	15,884
Natural gas options, swaps and forwards	Bcf	12	100
Congestion revenue rights	GWh	127,772	149,774
Tolling arrangements	GWh	97,893	101,485

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)	2013			2012			2013			2012
Edison International:
Income from continuing operations before income taxes	$	665		$	610		$	863		$	1,204
Provision for income tax at federal statutory rate of 35%	233			214			302			421
Increase (decrease) in income tax from:
State tax, net of federal benefit	22			46			5			60
Property-related	(57		)	(20		)	(121		)	(39		)
Uncertain tax positions	(5		)	1			13			2
Other	(16		)	(13		)	(26		)	(23		)
Total income tax expense from continuing operations	$	177		$	228		$	173		$	421
Effective tax rate	26.6		%	37.4		%	20.0		%	35.0		%
SCE:
Income from continuing operations before income taxes	$	685		$	564		$	913		$	1,186
Provision for income tax at federal statutory rate of 35%	240			197			319			415
Increase (decrease) in income tax from:
State tax, net of federal benefit	21			10			12			30
Property-related	(57		)	(19		)	(121		)	(39		)
Uncertain tax positions	(6		)	1			11			1
Other	(15		)	(13		)	(25		)	(23		)
Total income tax expense from continuing operations	$	183		$	176		$	196		$	384
Effective tax rate	26.7		%	31.2		%	21.5		%	32.4		%

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.

Property-related items include recognition of income tax benefits from repair deductions for income tax purposes.

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Tax Disputes

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.

Tax Years 2003 – 2006

The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included proposed adjustments for the following two items:

• A proposed adjustment increasing the taxable gain on the 2004 sale of EME's international assets, which if sustained, would result in a federal tax payment of approximately $205 million, including interest and penalties through September 30, 2013 (the IRS has asserted a 40% penalty for understatement of tax liability related to this matter).

• 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 $99 million, including interest through September 30, 2013.

Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011. The appeals process to date has not resulted in a change in the proposed adjustment by the IRS on the taxable gain on the 2004 sale of EME's international assets. If a deficiency notice is issued on this item, it would require payment of the tax, interest and any penalties within 90 days of its issuance or a filing of a petition in United States Tax Court.

Tax Years 2007 – 2009

The IRS examination phase of tax years 2007 through 2009 was completed during the first quarter of 2013. Edison International received a Revenue Agent Report from the IRS on February 28, 2013 which included a proposed adjustment to disallow a component of SCE's repair allowance deduction (similar to the 2003 – 2006 tax years). The proposed adjustment to disallow a component of SCE's repair allowance deduction, if sustained, would result in a federal tax payment of approximately $74 million, including interest through September 30, 2013. Edison International disagrees with the proposed adjustment and filed a protest with the IRS in April 2013.

Net Operating Loss and Tax Credit Carryforwards

Edison International recently completed filing its 2012 tax returns. As adjusted for the amounts reflected in these tax returns, Edison International had $311 million of federal tax credit carryforwards of which $289 million expire between 2029 and 2032 and the remainder has no expiration date. In addition, as adjusted for the amounts reflected in these tax returns there were $1.3 billion of net operating loss carryforwards (tax effected) of which $32 million expire between 2015 and 2024, and the remainder expire in 2031 and 2032.

As adjusted for the amounts reflected in these tax returns, SCE had $44 million of federal tax credit carryforwards of which $30 million expire between 2030 and 2032 and the remainder has no expiration date. In addition, as adjusted for the amounts reflected in these tax returns, there were $177 million of net operating loss carryforwards (tax effected) of which $18 million expire between 2015 and 2016, and the remainder expires in 2031 and 2032.

Edison International has recorded deferred tax assets related to net operating losses and tax credit carryforwards that pertain to Edison International's consolidated or combined federal and state tax returns. Edison International continues to consolidate EME for federal and certain combined state tax returns. Under federal and state tax regulations, a tax deconsolidation of EME in future periods, as expected through the bankruptcy proceeding would reduce the amounts that Edison International would be eligible to use in future periods. As a result of the expected future tax deconsolidation and separation of EME from Edison International, Edison International has recorded a valuation allowance based on the estimated amount of such benefits as calculated under the applicable federal and state tax regulations. During the third quarter of 2013, Edison International revised its estimate of the tax impact of net operating losses and valuation allowance based on completion of the 2012 tax returns, as well as the estimated impact during 2013, which resulted in a $25 million tax provision (recorded as part of discontinued operations). The tax impact related to completion of the 2012 tax returns resulted from lower net operating losses from EME and an increase in the amount of projected net operating loss retained by EME upon deconsolidation and separation from Edison International. Changes in the amount of tax attributes may impact the amount of the valuation allowance and thereby affect income or losses from discontinued operations (see Note 16).

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Note 8.    Compensation and Benefit Plans

Pension Plans

Edison International made contributions of $175 million during the nine months ended September 30, 2013, which includes contributions of $163 million by SCE. Edison International expects to make contributions of $13 million during the remainder of 2013, which includes $2 million from SCE. Annual contributions made to most of SCE's pension plans are anticipated to be recovered through CPUC-approved regulatory mechanisms. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.

Expense components for continuing operations are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2013			2012			2013			2012
Edison International:
Service cost	$	38		$	44		$	114		$	121
Interest cost	42			46			126			137
Expected return on plan assets	(58		)	(53		)	(172		)	(164		)
Settlement costs1	24			1			73			4
Amortization of prior service cost	1			1			3			3
Amortization of net loss2	15			18			45			48
Expense under accounting standards	$	62		$	57		$	189		$	149
Regulatory adjustment (deferred)	(7		)	(57		)	(21		)	(3		)
Total expense recognized	$	55		$	—		$	168		$	146
SCE:
Service cost	$	37		$	46		$	111		$	120
Interest cost	41			45			123			135
Expected return on plan assets	(57		)	(52		)	(171		)	(162		)
Settlement costs	24			1			72			3
Amortization of prior service cost	1			1			3			3
Amortization of net loss2	14			14			42			42
Expense under accounting standards	$	60		$	55		$	180		$	141
Regulatory adjustment (deferred)	(7		)	(57		)	(21		)	(3		)
Total expense recognized	$	53		$	(2	)	$	159		$	138

¹  Includes the amount of net loss reclassified from other comprehensive loss. The amount reclassified for Edison International was $2 million for the nine months ended September 30, 2013.

²  Includes the amount of net loss reclassified from other comprehensive loss. The amount reclassified for Edison International and SCE was $4 million and $3 million for the three months ended September 30, 2013, respectively, and $11 million and $8 million for the nine months ended September 30, 2013, respectively.

Under generally accepted accounting principles (“GAAP”), a settlement is recorded when lump-sum payments exceed estimated annual service and interest costs. As of May 31, 2013 and August 31, 2013, lump-sum payments to employees retiring in 2013 from the SCE Retirement Plan (primarily due to workforce reductions described below) exceeded the estimated service and interest costs for the year. A settlement requires re-measurement of both the plan pension obligations and plan assets as of the date of the settlement. The re-measurement of the SCE Retirement Plan as of May 31, 2013 and August 31, 2013 resulted in total actuarial gains of $338 million, including $341 million for SCE. The actuarial gains are primarily due to an increase in the discount rate (from 3.75% at December 31, 2012 to 4.25% as of May 31, 2013 and 4.50% as of August 31, 2013) due to higher interest rates and performance of the plan assets.

After re-measurement, GAAP requires an acceleration of a portion of unrecognized net losses attributable to such lump-sum payments as additional pension expense as reflected in the above table. The additional pension expense related to SCE did not impact net income as such amounts are probable of recovery through future rates.

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The projected benefit obligations exceeded the fair value of the SCE Retirement Plan assets by $739 million, including $701 million for SCE, at August 31, 2013 compared to $1.11 billion, including $1.07 billion for SCE, at December 31, 2012.

Postretirement Benefits Other Than Pensions

Edison International made contributions of $22 million during the nine months ended September 30, 2013 and expects to make contributions of $13 million during the remainder of 2013, all of which are expected to be made by SCE. Annual contributions made to SCE plans are anticipated to be recovered through CPUC-approved regulatory mechanisms and 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 for continuing operations are:

	Three months ended September 30,						Nine months ended September 30,
(in millions)	2013			2012			2013			2012
Edison International:
Service cost	$	14		$	13		$	42		$	37
Interest cost	26			28			78			85
Expected return on plan assets	(30		)	(27		)	(90		)	(81		)
Special termination benefits1	—			3			10			3
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss2	7			12			21			35
Total expense	$	8		$	20		$	34		$	52
SCE:
Service cost	$	14		$	12		$	41		$	36
Interest cost	26			28			78			84
Expected return on plan assets	(30		)	(27		)	(90		)	(81		)
Special termination benefits1	—			3			10			3
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss2	7			11			21			33
Total expense	$	8		$	18		$	33		$	48

¹  Due to the reduction in workforce, SCE has incurred costs for extended retiree health care coverage.

²  Includes the amount of net loss reclassified from other comprehensive loss. The amount reclassified for Edison International and SCE was less than $1 million and zero for the three- and nine-months ended September 30, 2013, respectively.

Workforce Reductions

In 2012, SCE commenced multiple efforts to reduce its workforce, which were largely completed by the end of the second quarter of 2013, in order to reflect SCE's strategic direction to optimize its cost structure, moderate customer rate increases and align its cost structure with its peers. In addition, in June 2013, SCE announced plans to permanently retire San Onofre. This announcement will result in a further reduction of the San Onofre workforce by approximately 960 employees and support organizations by approximately 175 employees. The majority of such reductions occurred in 2013. See Note 9 for further details. The following table provides a summary of changes in the accrued severance liability associated with these reductions:

(in millions)
Balance at January 1, 2013	$	104
Additions	109
Payments	(132		)
Balance at September 30, 2013	$	81

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The liability presented in the table above is reflected in "Other current liabilities" on the consolidated balance sheets. The severance costs are included in "Operation and maintenance" on the consolidated income statements.

Note 9. Permanent Retirement of San Onofre

Tube Leak and Response

Replacement steam generators were installed at San Onofre in 2010 and 2011. 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. The Unit was safely taken off-line and subsequent inspections revealed excessive tube to tube wear. At the time, Unit 2 was off-line for a planned outage when areas of unexpected tube to support structure wear were found. Both Units have remained shut down since early 2012 and have undergone extensive inspections, testing and analysis following discovery of the leak. In October 2012, SCE submitted a restart plan to the Nuclear Regulatory Commission (“NRC”).

Permanent Retirement

On June 6, 2013 SCE decided to permanently retire Units 2 and 3. SCE concluded that despite the NRC's extensive review of SCE's restart plan for Unit 2 since October 2012, there still remained considerable uncertainty about when the review process would be concluded. Given the considerable uncertainty of when or whether SCE would be permitted to restart Unit 2, SCE concluded that it was in the best interest of its customers, shareholders and other stakeholders to permanently retire the Units and focus on planning for the replacement resources which will eventually be required for grid reliability. SCE also concluded that its decision to retire the Units would facilitate more orderly planning for California's energy future without the uncertainty of whether, when or how long San Onofre would continue to operate.

CPUC Review

In October 2012 the CPUC issued an Order Instituting Investigation (“OII”) that consolidated all San Onofre issues in related regulatory proceedings to consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, substitute market power costs, capital expenditures, operation and maintenance costs, and seismic study costs. The OII requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent collected in rate levels authorized in the 2012 GRC or other proceeding, be 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 OII, of costs and rate base related to San Onofre from SCE's rates. Various other parties have filed testimony in the OII asking for disallowance of some or all of the San Onofre-related costs, including costs in excess of the amount impaired by SCE.

A summary of financial items related to San Onofre and implicated in the OII are as follows:

• Approximately $1.1 billion of SCE's authorized revenue requirement collected since January 1, 2012 (subject to refund) associated with operating and maintenance expenses, depreciation, taxes and return on SCE's investment in Unit 2, Unit 3 and common plant. In June 2013, SCE recorded approximately $56 million in severance costs associated with its decision to retire both Units. Until funding of post June 6, 2013 activities related to the permanent closure of the plant is transitioned from base rates to SCE's nuclear decommissioning trusts set up for that purpose, SCE will continue to record these costs through the San Onofre OII memorandum account, subject to reasonableness review.

• At May 31, 2013, SCE's net investment associated with San Onofre was $2.1 billion, including net book value of remaining property, plant and equipment, construction work-in-progress, nuclear fuel inventory and materials and supplies.

• In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million based on SCE's estimate after adjustment for inflation using the Handy-Whitman Index) for SCE's 78.21% share of the costs to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $602 million on the steam generator replacement project, not including inspection, testing and repair costs subsequent to the replacement steam generator leak in Unit 3.

• As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre were purchased in the market by SCE. These market power costs will be reviewed as part of the CPUC's OII proceeding. Estimated market power costs calculated in accordance with the OII methodology were approximately $680 million as of June 6, 2013, excluding avoided nuclear fuel costs which are no longer included as a reduction due to SCE's decision to permanently retire Units 2 and 3. Such amount includes costs of approximately $65 million associated with planned outage periods. SCE believes that such costs should be excluded as they would have been incurred even had the replacement steam generators performed as expected. Estimated market power costs calculated

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in accordance with the OII methodology from June 7, 2013 through September 30, 2013 was approximately $191 million. The CPUC will ultimately determine a final methodology for estimating market power costs as it continues its review of the issues in the OII.

• Through September 30, 2013, SCE's share of incremental inspection and repair costs totaled $115 million for both Units (not including payments made by MHI as described below). SCE recorded its share of payments made to date by MHI ($36 million) as a reduction of incremental inspection and repair costs in 2012.

SCE believes that the actions taken and costs incurred in connection with the San Onofre replacement steam generators, outages and permanent retirement have been prudent. Nevertheless, SCE cannot provide assurance that the CPUC will not disallow costs incurred or order refunds to customers of amounts collected in rates or that SCE will be successful in recovering amounts from third parties. Disallowances of costs and/or refund of amounts received from customers could be material and adversely affect SCE's financial condition, results of operations and cash flows.

Accounting for Early Retirement of San Onofre Units 2 and 3

As a result of the decision to early retire San Onofre Units 2 and 3, GAAP requires reclassification of the amounts recorded in property, plant and equipment and related tangible operating assets to a regulatory asset to the extent that management concludes it is probable of recovery through future rates. Regulatory assets may also be recorded to the extent management concludes it is probable that direct and indirect costs incurred to retire Units 2 and 3 as of each reporting date are recoverable through future rates. These costs may include, but are not limited to, severance benefits to reduce the workforce at San Onofre to the staffing required to safely store and secure the plant prior to conducting decommissioning activities, losses on termination of purchase contracts, including nuclear fuel, and losses on disposition of excess inventory. GAAP also requires recognition of a liability to the extent management concludes it is probable SCE will be required to refund amounts from authorized revenues previously collected from customers.

In assessing whether to record regulatory assets as a result of the decision to retire San Onofre Units 2 and 3 early and whether to record liabilities for refunds to customers, SCE considered the interrelationship of recovery of costs and refunds to customers for accounting purposes, as such matters are being considered by the CPUC on a consolidated basis in the San Onofre OII. SCE also considered that it will continue to use certain portions of the plant (such as fuel storage, security facilities and buildings) as part of ongoing activities at the site. SCE additionally reviewed relevant regulatory precedents and statutory provisions regarding the regulatory recovery of early retired assets previously placed in service and related materials, supplies and fuel. Such precedents have generally permitted cost recovery of the remaining net investment in early retired assets, absent a finding of imprudency. Such precedents vary on whether a full, partial or no rate of return is allowed on the investment in such assets, but generally provide accelerated recovery when less than a full return is authorized. Furthermore, once the Units are removed from rate base, under normal principles of cost of service ratemaking and relevant statutory provisions, SCE should, absent imprudence, recover the costs it incurs to purchase power that might otherwise have been produced by San Onofre. SCE continues to believe that the actions it has taken and the costs it has incurred in connection with the San Onofre replacement steam generators and outages have been prudent.

As a result of such considerations, SCE considered a number of potential outcomes for the matters being considered by the CPUC in the San Onofre OII, none of which are assured, but a number of which in SCE's opinion appeared to be more likely than a number of other outcomes. SCE considered the likelihood of outcomes to determine the amount deemed probable of recovery. These outcomes included a number of variables, including recovery of and return on the components of SCE's net investment, and the potential for refunds to customers for either substitute power or operating costs occurring over different time periods. SCE also included in its consideration of possible outcomes, the requirement under GAAP to discount future cash flows from recovery of assets without a return at its incremental borrowing rate.

As a result of the foregoing assessment, SCE:

• Reclassified $1,521 million of its total investment in San Onofre at May 31, 2013 as described above to a regulatory asset (“San Onofre Regulatory Asset”). Included in the San Onofre Regulatory Asset is approximately $404 million of property, plant and equipment, including construction work in progress that is expected to support ongoing activities at the site. In addition, to the extent the San Onofre Regulatory Asset includes excess nuclear fuel and material and supplies, SCE will, if possible, sell such excess amounts to third parties and reduce the amount of the regulatory asset by such proceeds.

• Recorded an impairment charge of $575 million ($365 million after tax) in the second quarter of 2013.

As part of the decision to permanently retire the Units at San Onofre, SCE announced a workforce reduction of approximately 960 employees and accrued additional severance costs of $56 million (SCE's share) based on its conclusion that it is probable, though not certain, that such costs will be recovered in future rates. The estimate for these costs was

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previously included in SCE's estimate to decommission the units. After acceptance of the decommissioning plan by the NRC, SCE expects a further workforce reduction of approximately 175 employees.

As of September 30, 2013, SCE recorded a net regulatory asset of $1.45 billion comprised of: $1.54 billion of property, plant and equipment; $33 million estimated losses on disposition of nuclear fuel inventory; less $129 million for estimated refunds of authorized revenue recorded in excess of SCE’s costs of service, including a return on capital through June 6, 2013. SCE's judgment that the San Onofre Regulatory Asset recorded at September 30, 2013 is probable, though not certain, of recovery is based on SCE's knowledge of the facts and judgment in applying relevant regulatory principles to the issues under review in the OII proceeding and in accordance with GAAP. Such judgment is subject to considerable uncertainty, and regulatory principles and precedents are not necessarily binding and are capable of interpretation. No decisions have been rendered in the OII proceeding regarding recoverability of costs from future rates or refunds of amounts to customers. The CPUC may or may not agree with SCE, after review of all of the facts and circumstances, and SCE may advocate positions that it believes are supported by relevant precedent and regulatory principles that are more favorable to SCE than the charges it has recorded in accordance with GAAP. The CPUC could also conclude that SCE acted imprudently regarding the San Onofre replacement steam generator project, including its response to the outage that commenced at the end of January 2012. Thus, there can be no assurance that the OII proceeding will provide for recoveries as estimated by SCE, including the recovery of costs recorded as a regulatory asset, or that the CPUC does not order refunds to customers from amounts that were previously authorized as subject to refund. Accordingly, the amount recorded for the San Onofre Regulatory Asset at September 30, 2013, is subject to change based upon future developments and the application of SCE's judgment to those events.

Third-Party Recovery

The replacement 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 with dispatch and to pay specified damages for certain repairs. MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power;" however, limitations in the contract are subject to applicable exceptions both in the contract and under law. SCE has advised MHI that it believes one or more of such exceptions apply and MHI's liability is not limited to $138 million, and MHI has advised SCE that it disagrees. In October 2013, after a prescribed 90-day waiting period from the service of an earlier notice of dispute, SCE sent MHI a formal request for binding arbitration under the auspices of the International Chamber of Commerce in accordance with the purchase contract seeking damages for all losses. In the request for arbitration, SCE alleges that MHI totally and fundamentally failed to deliver what it promised, and that the contractual limitations of liability are subject to applicable exceptions in the contract and under law. Each of the other co-owners filed lawsuits against MHI, alleging claims arising from MHI's supplying the faulty steam generators. MHI has requested that these lawsuits be stayed pending the arbitration with SCE.

SCE, on behalf of itself and the other San Onofre co-owners, has submitted seven invoices to MHI totaling $149 million for steam generator repair costs incurred through April 30, 2013. MHI paid the first invoice of $45 million, while reserving its right to challenge any of the charges in the invoice. In January 2013, MHI advised SCE that it rejected a portion of the first invoice and required further documentation regarding the remainder of the invoice. In September 2013, SCE reiterated its request to MHI for payment of outstanding invoices. SCE has recorded its share of the invoice paid as a reduction of repair and inspection costs.

San Onofre carries both accidental property damage and accidental outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of claims under both policies. The NEIL policies have a number of exclusions and limitations that may reduce or eliminate coverage. The estimated total claims under the accidental outage insurance through June 30, 2013 are approximately $390 million (SCE’s share of which is approximately $306 million). Pursuant to these proofs of loss, SCE is seeking the weekly indemnity amounts provided under the accidental outage policy for each Unit. Accidental outage policy benefits are reduced by 90% for the periods following announcement of the permanent retirement of the Units. SCE has not submitted a proof of loss under the accidental property damage insurance. No amounts have been recognized in SCE's financial statements, pending NEIL's response. SCE's current expectation is that NEIL will make a coverage determination by the end of the first quarter of 2014.

Continuing NRC Proceedings

As part of the NRC's review of the San Onofre outage and proceedings related to the possible restart of Unit 2, the NRC appointed an Augmented Inspection Team to review SCE's performance. In September 2013, the NRC issued an Inspection Report in connection with The Augmented Inspection Team’s review and SCE’s response to an earlier NRC Confirmatory Action Letter. The NRC’s report contained a preliminary “white” finding (low to moderate safety significance) and an apparent violation regarding the steam generators in Unit 3 and a preliminary “green” finding (very low safety significance) for Unit 2’s steam generators for failing to ensure that MHI’s modeling and analysis were adequate. Simultaneously, the NRC

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issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of San Onofre’s steam generators. In October 2013, SCE submitted comments to the NRC on the characterizations contained in the Inspection Report but did not contest the findings or violation. In addition, the NRC's Office of Investigations has been conducting an investigation into the accuracy and completeness of information SCE provided to the Augmented Inspection Team. SCE has also been made aware of an investigation related to San Onofre by the NRC's Office of Inspector General, which generally reviews internal NRC affairs. Certain anti-nuclear groups and individual members of Congress have alleged that SCE knew of deficiencies in the steam generators when they were installed or otherwise did not correctly follow NRC requirements in connection with the design and installation of the replacement steam generators, something which SCE has vigorously denied, and have called for investigations, including by the Department of Justice. SCE cannot predict when or whether ongoing inquiries or investigations by the NRC will be completed or whether inquiries by other government agencies will be initiated. Should the NRC find a deficiency in SCE's provision of information, SCE could be subject to additional NRC actions, including the imposition of penalties, and the findings could be taken into consideration in the CPUC regulatory proceedings described above.

Note 10.    Other Investments

Nuclear Decommissioning Trusts

Future decommissioning costs of removal of SCE's 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.

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

	Longest Maturity Dates	Amortized Cost						Fair Value
(in millions)		September 30, 2013			December 31, 2012			September 30, 2013			December 31, 2012
Stocks	—	$	635		$	978		$	2,027		$	2,271
Municipal bonds	2051	701			518			796			644
U.S. government and agency securities	2043	861			547			924			603
Corporate bonds	2054	176			324			221			410
Short-term investments, primarily cash equivalents	One-year	351			117			367			121
Total investments		2,724			2,484			4,335			4,049
Net payables		(3		)	(1		)	(3		)	(1		)
Total nuclear decommissioning trusts		$	2,721		$	2,483		$	4,332		$	4,048

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 $2.6 billion and $428 million for the three months ended September 30, 2013 and 2012, respectively and $4.6 billion and $1.5 billion for the nine months ended September 30, 2013 and 2012, respectively. Unrealized holding gains, net of losses, were $1.6 billion at both September 30, 2013 and December 31, 2012.

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)	2013			2012			2013			2012
Balance at beginning of period	$	4,182		$	3,810		$	4,048		$	3,592
Gross realized gains	119			13			261			54
Gross realized losses	(17		)	—			(18		)	(5		)
Unrealized gains, net	55			156			46			272
Other-than-temporary impairments	(15		)	(7		)	(44		)	(30		)
Interest, dividends, contributions and other	8			25			39			114
Balance at end of period	$	4,332		$	3,997		$	4,332		$	3,997

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

Note 11.    Regulatory Assets and Liabilities

As a result of the permanent retirement of San Onofre, SCE's net regulatory asset as of September 30, 2013 was $1.45 billion comprised of: $1.54 billion of property, plant and equipment; $33 million estimated losses on disposition of nuclear fuel inventory (see Note 12 for further information); less $129 million of authorized revenue from the 2012 GRC in excess of revenues recognized based on costs incurred and a return on capital through June 6, 2013, pending the outcome of the regulatory proceedings.

Regulatory Assets

Regulatory assets included on the consolidated balance sheets are:

(in millions)	September 30, 2013		December 31, 2012
Current:
Regulatory balancing accounts	$	344	$	502
Energy derivatives	162		70
Total current	506		572
Long-term:
Deferred income taxes, net	2,911		2,663
Pensions and other postretirement benefits	1,105		1,550
Energy derivatives	960		900
Unamortized investments, net	358		507
San Onofre	1,450		—
Unamortized loss on reacquired debt	213		228
Nuclear-related investment, net	34		141
Regulatory balancing accounts	626		73
Other	358		360
Total long-term	8,015		6,422
Total regulatory assets	$	8,521	$	6,994

Regulatory Liabilities

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)	September 30, 2013		December 31, 2012
Current:
Regulatory balancing accounts	$	580	$	484
Other	49		52
Total current	629		536
Long-term:
Costs of removal	2,814		2,731
Asset retirement obligations	954		1,385
Regulatory balancing accounts	1,210		1,091
Other	11		7
Total long-term	4,989		5,214
Total regulatory liabilities	$	5,618	$	5,750

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The regulatory liability related to asset retirement obligations represents the nuclear decommissioning trust assets in excess of the related asset retirement obligations. The decrease in this regulatory liability resulted from a revision to the asset retirement obligations of San Onofre. For further information, see Note 1.

Note 12.    Commitments and Contingencies

Third-Party Power Purchase Agreements

During the nine months ended September 30, 2013, SCE had new power purchase contracts classified as operating leases. The additional commitments are estimated to be: $247 million for 2014, $340 million in 2015, $413 million in 2016, $415 million in 2017 and $4.43 billion for the period remaining thereafter.

Other Commitments

As of December 31, 2012, SCE had nuclear fuel supply commitments of $912 million for the 2013 – 2017 period and thereafter. As a result of the decision to permanently retire San Onofre Units 2 and 3, SCE has submitted fuel contract delivery cancellation notices for these contractual arrangements. As of September 30, 2013, SCE had accrued a liability of $33 million related to estimated costs associated with the cancellation and management of future deliveries of nuclear fuel and recorded a regulatory asset for recovery of costs in the future. See Note 9 for further discussion of SCE's decision to permanently retire San Onofre.

Indemnities

Edison International and SCE have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.

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 in 2004 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

Edison International and SCE provide 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. Edison International's and SCE's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison International and SCE may have recourse against third parties. Edison International and SCE have 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, Edison International and SCE are involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International and SCE believe the outcome of these other proceedings will not, individually or in the aggregate, materially affect its results of operations or liquidity.

San Onofre

SCE believes that the actions taken and costs incurred in connection with the San Onofre replacement steam generators and outages have been prudent. Accordingly, SCE considers its operating, capital, and market power costs, recoverable through

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base rates and the ERRA balancing account, as offset by third-party recoveries where applicable. SCE cannot provide assurance that the CPUC will not disallow costs incurred or order refunds to customers of amounts collected in rates, or that SCE will be successful in recovering amounts from third parties. Disallowances of costs and/or refund of amounts received from customers could be material and adversely affect SCE's financial condition, results of operations and cash flows. 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. See Note 9 for further details.

EME Chapter 11 Bankruptcy Filing

On December 17, 2012 (the "Petition Date"), EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of Illinois, Eastern Division ("Bankruptcy Court") (see Note 16 for further details). Under the Transaction Support Agreement (the "Support Agreement") to which EME, Edison International and certain of EME's senior unsecured noteholders ("Consenting Noteholders") were parties, each of them had agreed to support Bankruptcy Court approval of the Settlement Transaction. EME was required to seek authority from the Bankruptcy Court to enter into the Settlement Transaction by the deadline set out in the Support Agreement and did not do so. EME's failure to meet this deadline rendered the Support Agreement terminable by Edison International or the Consenting Noteholders at any time, and on July 25, 2013, a requisite majority of the Consenting Noteholders provided Edison International and EME with a notice terminating the Support Agreement, effective August 1, 2013. As a result, the extension of the Tax Allocation Agreement contemplated by the Support Agreement has also terminated, and the Tax Allocation Agreement is now due to expire by its terms on December 31, 2013. Furthermore, claims, which Edison International submitted in the EME bankruptcy on a contingency basis, will not be released, and inasmuch as Edison International will not be entitled to the benefits of the Settlement Transaction, it will remain subject to any claims of EME and potentially its creditors, including claims relating to or arising out of any shared services, the Tax Allocation Agreement, and any other relationships or transactions between the companies.

On August 1, 2013, the Official Committee of Unsecured Creditors made a motion in the Bankruptcy Court to seek sole authority to file, prosecute and settle alleged claims against Edison International, SCE, certain other subsidiaries of Edison International, and present and former directors of Edison International, SCE and EME. Such motion has not been acted upon by the Bankruptcy Court but was supported by the Consenting Noteholders and was accompanied by a proposed complaint, which has not been filed or served. The motion was opposed by EME, and although EME indicated that immediate litigation was not in EME’s interest, EME indicated that it had been preparing a similar complaint and would file it were it to conclude that it would be in EME’s best interests to do so. The proposed complaint sets forth a variety of theories to allege damages against the named defendants, including, among other things, that $925 million in dividends paid by EME to Mission Energy Holding Company in 2007 are recoverable, that $183 million paid by EME under the Tax Allocation Agreement in September 2012 was not proper, that EME was operated between 2010 and 2012 for Edison International’s benefit and not in accordance with fiduciary duties owed to EME and its creditors, that the amendment of the Tax Allocation Agreement to have it expire December 31, 2013 in the absence of a settlement was a breach of fiduciary duty, that Edison International overcharged EME for shared services, that Edison International and certain of its competitive subsidiaries are alter egos of and should be substantively consolidated with EME and therefore liable for EME’s debts, and that utilization by Edison International and SCE of bonus depreciation following EME’s filing for bankruptcy was a violation of the automatic stay in the EME bankruptcy. Edison International does not know if a complaint containing such allegations or other allegations will be filed and served, but it would vigorously contest such allegations.

CPUC Safety and Enforcement Division 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 Safety and Enforcement Division (“SED”) 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 SED issued its final report on January 11, 2013. 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 the CPUC 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.

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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 SED 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 that SCE failed to preserve evidence relevant to the investigation and misled the CPUC during its investigation of the fire. In May 2013, SCE and the SED agreed to the terms of a proposed settlement that would cause SCE to pay a total of $37 million, $17 million of which will be allocated to pole safety studies and remediation in the Malibu area and $20 million of which will be a penalty paid to the State General Fund. The settlement was approved by the CPUC in September 2013.

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 – 2010, 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 2012, the parties requested a stay of the litigation to allow for settlement discussion, and the matter is currently stayed. In November 2010, SCE entered into an agreement to sell its ownership interest in generating units 4 and 5 to APS. The sale remains contingent upon APS obtaining a long-term fuel supply agreement for the plant. As of January 2013, the sale agreement became terminable by either party, but as of the date of this report, the agreement has not been terminated. The purchase price is subject to certain adjustments under the sale agreement, which includes a reduction in the purchase price of $7.5 million for each month between October 1, 2012 and the closing date. 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. SCE is unable to estimate a possible loss or range of loss associated with this matter.

Environmental Remediation

Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operation and maintenance, monitoring and site closure. Unless there is a single probable amount, Edison International 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, 2013, Edison International's recorded estimated minimum liability to remediate its 19 identified material sites (sites in which the upper end of the range of the costs is at least $1 million) at SCE was $129 million, including $90 million related to San Onofre. In addition to its identified material sites, SCE also has 39 immaterial sites for which the total minimum recorded liability was $4 million. Of the $133 million total environmental remediation liability for SCE, $129 million has been recorded as a regulatory asset. SCE expects to recover $38 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 $91 million through a mechanism that allows SCE to recover 100% of the costs incurred at certain sites through customer rates. Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at the identified material sites and immaterial sites could exceed its recorded liability by up to $161 million and $7 million, respectively, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes.

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SCE expects to clean up and mitigate its identified sites over a period of up to 30 years. Remediation costs for 2013 and in each of the next five years are expected to range from $6 million to $31 million. Costs incurred for the nine months ended September 30, 2013 and 2012 were $5 million for both respective periods.

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

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $13.6 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 $255 million per nuclear incident. However, it would have to pay no more than approximately $38 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 $1.06 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 $52 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 1, 2013, Edison International, renewed its liability insurance coverage, which included coverage for SCE's wildfire liabilities up to a $500 million limit (with a self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up this insurance coverage could result in additional self-insured costs in the event of multiple wildfire occurrences during the policy period (September 1, 2013 to May 31, 2014). SCE also has additional coverage for certain wildfire liabilities of $450 million, which applies when total covered wildfire claims exceed $550 million, through May 31, 2014. 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

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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 DOE's failure to meet its obligation to begin accepting spent nuclear fuel for the period from January 1, 2006 to December 31, 2010. Additional legal action would be necessary to recover damages incurred after December 31, 2010. All 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.

Note 13.    Preferred and Preference Stock of Utility

During the first quarter of 2013, SCE issued 160,004 shares of 5.10% Series G preference stock (cumulative, $2,500 liquidation value) to SCE Trust II, a special purpose entity formed to issue trust securities as discussed in Note 3. The Series G preference stock may be redeemed at par, in whole, but not in part, at any time prior to March 15, 2018 if certain changes in tax or investment company laws occur. After March 15, 2018, SCE may redeem the Series G shares at par, in whole or in part. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to redeem all outstanding shares of Series B and C preference stock.

Note 14.    Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consists of:

	Pension and PBOP – Net Loss
(in millions)	Three months ended September 30, 2013			Nine months ended September 30, 2013
Edison International:
Balance at beginning of period	$	(82	)	$	(87	)
Other comprehensive loss before reclassifications	—			(2		)
Amounts reclassified from accumulated other comprehensive loss1	3			10
Net current-period other comprehensive loss	3			8
Balance at end of period	$	(79	)	$	(79	)
Reclassifications from accumulated other comprehensive loss:
Amortization of net loss included in net income	$	4		$	13
Tax expense	1			3
Total reclassification, net of tax	$	3		$	10
SCE:
Balance at beginning of period	$	(30	)	$	(29	)
Other comprehensive loss before reclassifications	—			(4		)
Amounts reclassified from accumulated other comprehensive loss1	2			5
Net current-period other comprehensive loss	2			1
Balance at end of period	$	(28	)	$	(28	)
Reclassifications from accumulated other comprehensive loss:
Amortization of net loss included in net income	$	3		$	8
Tax expense	1			3
Total reclassification, net of tax	$	2		$	5

¹  These items are included in the computation of net periodic pension and PBOP expense. See Note 8 for additional information.

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Note 15.    Interest and Other Income and Other Expenses

Interest and other income and expenses are as follows:

	Three months ended September 30,				Nine months ended September 30,
(in millions)	2013		2012		2013		2012
SCE interest and other income:
Equity allowance for funds used during construction	$	14	$	23	$	54	$	71
Increase in cash surrender value of life insurance policies	10		6		24		20
Interest income	2		2		8		5
Other	1		7		3		12
Total SCE interest and other income	27		38		89		108
Edison International Parent and Other income	1		—		2		2
Total Edison International interest and other income	$	28	$	38	$	91	$	110
SCE other expenses:
Civic, political and related activities and donations	$	9	$	5	$	24	$	22
Other	6		4		14		14
Total SCE other expenses	15		9		38		36
Edison International Parent and Other other expenses	—		1		—		—
Total Edison International other expenses	$	15	$	10	$	38	$	36

Note 16.    Discontinued Operations

EME Chapter 11 Bankruptcy Filing

EME and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. See Note 12 for further details.

Deconsolidation

EME and those subsidiaries in Chapter 11 proceedings retain control of their assets and are authorized to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court. Effective December 17, 2012, Edison International no longer consolidates the earnings and losses of EME or its subsidiaries and has reflected its ownership interest in EME utilizing the cost method of accounting prospectively, under which Edison International's investment in EME is reflected as a single amount on the consolidated balance sheet of Edison International at December 31, 2012. Furthermore, Edison International has recorded a full impairment of the investment.

Edison International will not be affected by changes in EME's future financial results, other than those changes related to certain tax matters. Edison International has evaluated the continuing cash flows with EME and determined that these cash flows generated are indirect and immaterial. Edison International's continuing cash flows will not include any significant revenue-producing and cost-generating activities of EME.

Edison International considers EME to be an abandoned asset under generally accepted accounting principles, and, as a result, the operations of EME prior to December 17, 2012 and for all prior years are reflected as discontinued operations in the consolidated financial statements. Included in Edison International's consolidated income statement was an income tax expense of $25 million and $1 million for discontinued operations for the three- and nine-months ended September 30, 2013, respectively. Operating revenue and loss before income taxes for discontinued operations were $461 million and $262 million, respectively, for the three months ended September 30, 2012, and $1.31 billion and $645 million, respectively, for the nine months ended September 30, 2012.

Contingencies

Edison International Parent has not guaranteed the obligations of EME, however, under the Internal Revenue Code and applicable state statutes, Edison International Parent is jointly liable for qualified retirement plans and federal and specific state tax liabilities. As a result of the deconsolidation and the existence of joint liabilities, Edison International has recorded

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liabilities of $80 million for qualified retirement plans related to plan participants of EME and $192 million of liabilities related to joint tax liabilities. Under the qualified plan documents and tax allocation agreements, EME is obligated to pay for such liabilities and, accordingly, Edison International has recorded receivables of $238 million from EME net of amounts recorded in accumulated other comprehensive income of $34 million (related to actuarial losses under the qualified retirement plans).

If the Settlement Transaction had been approved and implemented, Edison International Parent would not have been entitled to receive reimbursement of the net receivable of $46 million and would be obligated to assume certain other retirement liabilities as specified in such agreement (estimated at $104 million). Inasmuch as the Settlement Transaction has been terminated, Edison International Parent will seek recovery of such joint liabilities as part of the EME bankruptcy proceeding. The outcome of the EME bankruptcy proceeding is uncertain, as was the disposition of the Support Agreement. Accordingly, management judgment was required to assess the collectibility of the receivables recorded and outcome of the bankruptcy proceeding. Management concluded that it is probable that a loss would be incurred and estimated a loss of $150 million. The outcome of the EME bankruptcy could result in losses different than the amounts recorded by Edison International and such amounts could be material.

For a discussion of other contingencies related to EME, see Tax Disputes discussed in Note 7 and potential litigation discussed in Note 12.

Note 17.    Supplemental Cash Flows Information

Supplemental cash flows information for continuing operations is:

	Edison International					SCE
	Nine months ended September 30,
(in millions)	2013		2012			2013		2012
Cash payments (receipts) for interest and taxes:
Interest, net of amounts capitalized	$	431	$	394		$	415	$	394
Tax payments (refunds), net	27		(239		)	18		(243		)
Non-cash financing and investing activities:
Dividends declared but not paid:
Common stock	$	110	$	106		$	120	$	—
Preferred and preference stock	4		6			4		6

SCE's accrued capital expenditures at September 30, 2013 and 2012 were $401 million and $414 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.

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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 Edison International's and SCE's current expectations and projections about future events based on Edison International's and 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 Edison International and 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 Edison International and SCE, include, but are not limited to:

• ability of SCE to recover its costs in a timely manner from its customers through regulated rates, including regulatory assets related to San Onofre and under-collection of fuel and purchased power costs;

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

• the ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms;

• 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 power generating facilities including: public safety issues, the failure, availability, efficiency, and output of equipment, the cost of repairs and retrofits of equipment, and availability and cost of spare parts;

• risks associated with the operation, retirement and decommissioning of nuclear generating facilities;

• physical security of our critical assets and personnel and the cyber security of our critical information technology systems for grid control, and business and customer data;

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

• environmental laws and regulations, at both 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;

• risk that the costs incurred in connection with the steam generators at Unit 2 and/or Unit 3 at San Onofre, as well as other costs incurred due to the outages may not be recoverable from SCE's supplier or insurance coverage;

• the termination of the Support Agreement related to the EME bankruptcy;

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

• changes in interest rates and rates of inflation, including escalation 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 the California Independent System Operator, Regional Transmission Organizations, and adjoining regions;

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• 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;

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

• cost and availability of fuel for generating facilities 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;

• 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 Edison International's and SCE's combined 2012 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 2012 Form 10-K, and carefully consider the risks, uncertainties and other factors that affect Edison International's and SCE's businesses. Forward-looking statements represent estimates and assumptions only as of the date they are made and neither Edison International nor SCE are obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International and SCE with the SEC.

The MD&A for the nine months ended September 30, 2013 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International and SCE since December 31, 2012, and as compared to the three months and nine months ended September 30, 2012. This discussion presumes that the reader has read or has access to Edison International's and SCE's MD&A for the calendar year 2012 (the "year-ended 2012 MD&A"), which was included in the 2012 Form 10-K.

Except when otherwise stated, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to "Edison International Parent and Other" mean Edison International Parent and its non-utility subsidiaries.

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MANAGEMENT OVERVIEW

Highlights of Operating Results

Edison International is the parent holding company of SCE. SCE is an investor-owned public utility primarily engaged in the business of supplying electricity. References to Edison International refer to the consolidated group of Edison International and its subsidiaries. References to Edison International Parent and Other refer to Edison International Parent and its nonutility subsidiaries. Unless otherwise described, all of the information contained in this report relates to both filers.

	Three months ended September 30,									Nine months ended September 30,
(in millions)	2013			2012			Change			2013			2012			Change
Net income (loss) attributable to Edison International
Continuing operations
SCE	$	477		$	363		$	114		$	642		$	736		$	(94	)
Edison International Parent and Other	(14		)	(6		)	(8		)	(27		)	(19		)	(8		)
Discontinued operations	(25		)	(167		)	142			(1		)	(360		)	359
Edison International	438			190			248			614			357			257
Less: Non-core items
SCE – asset impairment	—			—			—			(365		)	—			(365		)
Edison International Parent and Other	—			31			(31		)	7			31			(24		)
Discontinued operations	(25		)	(167		)	142			(1		)	(360		)	359
Total non-core items	(25		)	(136		)	111			(359		)	(329		)	(30		)
Core earnings (losses)
SCE	477			363			114			1,007			736			271
Edison International Parent and Other	(14		)	(37		)	23			(34		)	(50		)	16
Edison International	$	463		$	326		$	137		$	973		$	686		$	287

Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including sale of certain assets, and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings. On December 17, 2012 (the "Petition Date"), EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Edison International considers EME to be an abandoned asset under generally accepted accounting principles, and, as a result, the operations of EME prior to December 17, 2012 are reflected as discontinued operations.

SCE's 2013 core earnings increased $114 million and $271 million for the third quarter and year-to-date, respectively, primarily due to the timing of finalizing SCE's 2012 General Rate Case and income tax benefits. In addition, SCE's return on its investment resulting from rate base growth was offset by a lower authorized 2013 return on common equity. During last year, pending the outcome of the 2012 CPUC GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement. In the fourth quarter of 2012, SCE implemented its 2012 GRC which allowed SCE to recover its revenue requirement retroactive to January 1, 2012. The estimated revenue attributable to the third quarter and year-to-date of 2012 was $160 million and $325 million, respectively.

Edison International Parent and Other 2013 core losses decreased $23 million and $16 million for the third quarter and year-to-date, respectively, primarily due to higher consolidated state income taxes in prior periods.

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Consolidated non-core items for 2013 and 2012 for Edison International and SCE included:

• An impairment charge of $575 million ($365 million after tax) in the second quarter of 2013 related to the permanent retirement of San Onofre Units 2 and 3.

• An after-tax earnings benefit of $31 million ($65 million pre-tax gain) recorded in 2012 attributable to Edison Capital's sale of its lease interest in Unit No. 2 of the Beaver Valley Nuclear Power Plant to a third party for $108 million. The final determination of state income taxes was not completed until the first quarter of 2013 which resulted in $7 million of lower state income tax than previously estimated.

• An income tax loss of $25 million and $1 million for the third quarter and year-to-date, respectively, from a revised estimate of the tax impact of expected future tax deconsolidation and separation of EME from Edison International. Edison International continues to consolidate EME for federal and certain combined state tax returns. Changes in the amount of tax attributes during the first three quarters of 2013 affected income taxes of discontinued operations. Such benefits may or may not continue in future periods. For further information, see "Notes to Consolidated Financial Statements—Note 7. Income Taxes."

San Onofre Outage, Inspection and Retirement

Tube Leak and Response

As discussed in the 2012 Form 10-K, replacement steam generators were installed at San Onofre in 2010 and 2011. 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. The Unit was safely taken off-line and subsequent inspections revealed excessive tube to tube wear. At the time, Unit 2 was off-line for a planned outage when areas of unexpected tube to support structure wear were found. Both Units have remained shut down since early 2012 and have undergone extensive inspections, testing and analysis following discovery of the leak. In October 2012, SCE submitted a restart plan to the Nuclear Regulatory Commission (“NRC”), seeking to restart Unit 2 at a reduced power level (70%) for an initial period of approximately five months, based on work done by engineering groups from three independent firms with expertise in steam generator design and manufacturing. SCE did not develop a restart plan for Unit 3.

Permanent Retirement

On June 6, 2013 SCE decided to permanently retire Units 2 and 3. SCE concluded that despite the NRC's extensive review of SCE's restart plan for Unit 2 since October 2012, there still remained considerable uncertainty about when the review process would be concluded. Given the considerable uncertainty of when or whether SCE would be permitted to restart Unit 2, SCE concluded that it was in the best interest of its customers, shareholders and other stakeholders to permanently retire the Units and focus on planning for the replacement resources which will eventually be required for grid reliability. SCE also concluded that its decision to retire the Units would facilitate more orderly planning for California's energy future without the uncertainty of whether, when or how long San Onofre would continue to operate.

CPUC Review

In October 2012 the CPUC issued an Order Instituting Investigation (“OII”) that consolidated all San Onofre issues in related regulatory proceedings to consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, substitute market power costs, capital expenditures, operation and maintenance costs, and seismic study costs. The OII requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent collected in rate levels authorized in the 2012 GRC or other proceeding, be 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 OII, of costs and rate base related to San Onofre from SCE's rates. Various other parties have filed testimony in the OII asking for disallowance of some or all of the San Onofre-related costs, including costs in excess of the amount impaired by SCE, as described below. The first phase of the OII is focused on 2012 costs and was split into two sets of hearings. The first set of hearings covered 2012 capital and operation and maintenance costs and was held in May 2013. The second set of hearings focused on the appropriate calculation to measure 2012 substitute market power costs and was held in August 2013. A decision in the first phase is expected in the fourth quarter of 2013. The second phase is focused on whether to adjust customer rates to remove the plant from rate base and hearings were held in October 2013. A decision in the second phase is expected in the first quarter of 2014. The third and fourth phases of the OII will focus on the steam generator replacement project, reasonableness of costs and the San Onofre 2013 revenue requirement, respectively and have not yet been scheduled.

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A summary of financial items related to San Onofre and implicated in the OII are as follows:

• Approximately $1.1 billion of SCE's authorized revenue requirement collected since January 1, 2012 (subject to refund) associated with operating and maintenance expenses, depreciation, taxes and return on SCE's investment in Unit 2, Unit 3 and common plant. In June 2013, SCE recorded approximately $56 million in severance costs associated with its decision to retire both Units. Until funding of post June 6, 2013 activities related to the permanent closure of the plant is transitioned from base rates to SCE's nuclear decommissioning trusts set up for that purpose, SCE will continue to record these costs through the San Onofre OII memorandum account, subject to reasonableness review.

• At May 31, 2013, SCE's net investment associated with San Onofre is set forth in the following table:

(in millions)	Unit 2		Unit 3		Common Plant		Total
Net investment1	$	606	$	430	$	259	$	1,295
Materials and supplies	—		—		100		100
Construction work in progress	25		99		106		230
Nuclear fuel	153		216		102		471
Total investment	$	784	$	745	$	567	$	2,096

¹  Includes net book value of the replacement steam generators of $542 million.

• In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million based on SCE's estimate after adjustment for inflation using the Handy-Whitman Index) for SCE's 78.21% share of the costs to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $602 million on the steam generator replacement project, not including inspection, testing and repair costs subsequent to the replacement steam generator leak in Unit 3.

• As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre were purchased in the market by SCE. These market power costs will be reviewed as part of the CPUC's OII proceeding. Estimated market power costs calculated in accordance with the OII methodology were approximately $680 million as of June 6, 2013, excluding avoided nuclear fuel costs which are no longer included as a reduction due to SCE's decision to permanently retire Units 2 and 3. Such amount includes costs of approximately $65 million associated with planned outage periods. SCE believes that such costs should be excluded as they would have been incurred even had the replacement steam generators performed as expected. Estimated market power costs calculated in accordance with the OII methodology from June 7, 2013 through September 30, 2013 was approximately $191 million. The CPUC will ultimately determine a final methodology for estimating market power costs as it continues its review of the issues in the OII.

• Through September 30, 2013, SCE's share of incremental inspection and repair costs totaled $115 million for both Units (not including payments made by MHI as described below). SCE recorded its share of payments made to date by MHI ($36 million) as a reduction of incremental inspection and repair costs in 2012.

SCE believes that the actions taken and costs incurred in connection with the San Onofre replacement steam generators, outages and permanent retirement have been prudent. Nevertheless, SCE cannot provide assurance that the CPUC will not disallow costs incurred or order refunds to customers of amounts collected in rates or that SCE will be successful in recovering amounts from third parties. Disallowances of costs and/or refund of amounts received from customers could be material and adversely affect SCE's financial condition, results of operations and cash flows.

Accounting for Early Retirement of San Onofre Units 2 and 3

As a result of the decision to early retire San Onofre Units 2 and 3, GAAP requires reclassification of the amounts recorded in property, plant and equipment and related tangible operating assets to a regulatory asset to the extent that management concludes it is probable of recovery through future rates. Regulatory assets may also be recorded to the extent management concludes it is probable that direct and indirect costs incurred to retire Units 2 and 3 as of each reporting date are recoverable through future rates. These costs may include, but are not limited to, severance benefits to reduce the workforce at San Onofre to the staffing required to safely store and secure the plant prior to conducting decommissioning activities, losses on termination of purchase contracts, including nuclear fuel, and losses on disposition of excess inventory. GAAP also requires recognition of a liability to the extent management concludes it is probable SCE will be required to refund amounts from authorized revenues previously collected from customers.

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In assessing whether to record regulatory assets as a result of the decision to retire San Onofre Units 2 and 3 early and whether to record liabilities for refunds to customers, SCE considered the interrelationship of recovery of costs and refunds to customers for accounting purposes, as such matters are being considered by the CPUC on a consolidated basis in the San Onofre OII. SCE also considered that it will continue to use certain portions of the plant (such as fuel storage, security facilities and buildings) as part of ongoing activities at the site. SCE additionally reviewed relevant regulatory precedents and statutory provisions regarding the regulatory recovery of early retired assets previously placed in service and related materials, supplies and fuel. Such precedents have generally permitted cost recovery of the remaining net investment in early retired assets, absent a finding of imprudency. Such precedents vary on whether a full, partial or no rate of return is allowed on the investment in such assets, but generally provide accelerated recovery when less than a full return is authorized. Furthermore, once the Units are removed from rate base, under normal principles of cost of service ratemaking and relevant statutory provisions, SCE should, absent imprudence, recover the costs it incurs to purchase power that might otherwise have been produced by San Onofre. SCE continues to believe that the actions it has taken and the costs it has incurred in connection with the San Onofre replacement steam generators and outages have been prudent.

As a result of such considerations, SCE considered a number of potential outcomes for the matters being considered by the CPUC in the San Onofre OII, none of which are assured, but a number of which in SCE's opinion appeared to be more likely than a number of other outcomes. SCE considered the likelihood of outcomes to determine the amount deemed probable of recovery. These outcomes included a number of variables, including recovery of and return on the components of SCE's net investment, and the potential for refunds to customers for either substitute power or operating costs occurring over different time periods. SCE also included in its consideration of possible outcomes, the requirement under GAAP to discount future cash flows from recovery of assets without a return at its incremental borrowing rate.

As a result of the foregoing assessment, SCE:

• Reclassified $1,521 million of its total investment in San Onofre at May 31, 2013 as described above to a regulatory asset (“San Onofre Regulatory Asset”). Included in the San Onofre Regulatory Asset is approximately $404 million of property, plant and equipment, including construction work in progress that is expected to support ongoing activities at the site. In addition, to the extent the San Onofre Regulatory Asset includes excess nuclear fuel and material and supplies, SCE will, if possible, sell such excess amounts to third parties and reduce the amount of the regulatory asset by such proceeds.

• Recorded an impairment charge of $575 million ($365 million after tax) in the second quarter of 2013.

As part of the decision to permanently retire the Units at San Onofre, SCE announced a workforce reduction of approximately 960 employees and accrued additional severance costs of $56 million (SCE's share) based on its conclusion that it is probable, though not certain, that such costs will be recovered in future rates. The estimate for these costs was previously included in SCE's estimate to decommission the units. After acceptance of the decommissioning plan by the NRC, SCE expects a further workforce reduction of approximately 175 employees. SCE also recorded severance costs of $14 million related to the indirect employee impacts from the decision to early retire the Units.

As of September 30, 2013, SCE recorded a net regulatory asset of $1.45 billion comprised of: $1.54 billion of property, plant and equipment; $33 million estimated losses on disposition of nuclear fuel inventory; less $129 million for estimated refunds of authorized revenue recorded in excess of SCE’s costs of service, including a return on capital through June 6, 2013. SCE's judgment that the San Onofre Regulatory Asset recorded at September 30, 2013 is probable, though not certain, of recovery is based on SCE's knowledge of the facts and judgment in applying relevant regulatory principles to the issues under review in the OII proceeding and in accordance with GAAP. Such judgment is subject to considerable uncertainty, and regulatory principles and precedents are not necessarily binding and are capable of interpretation. No decisions have been rendered in the OII proceeding regarding recoverability of costs from future rates or refunds of amounts to customers. The CPUC may or may not agree with SCE, after review of all of the facts and circumstances, and SCE may advocate positions that it believes are supported by relevant precedent and regulatory principles that are more favorable to SCE than the charges it has recorded in accordance with GAAP. The CPUC could also conclude that SCE acted imprudently regarding the San Onofre replacement steam generator project, including its response to the outage that commenced at the end of January 2012. Thus, there can be no assurance that the OII proceeding will provide for recoveries as estimated by SCE, including the recovery of costs recorded as a regulatory asset, or that the CPUC does not order refunds to customers from amounts that were previously authorized as subject to refund. Accordingly, the amount recorded for the San Onofre Regulatory Asset at September 30, 2013, is subject to change based upon future developments and the application of SCE's judgment to those events.

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Third-Party Recovery

The replacement 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 with dispatch and to pay specified damages for certain repairs. MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power;" however, limitations in the contract are subject to applicable exceptions both in the contract and under law. SCE has advised MHI that it believes one or more of such exceptions apply and MHI's liability is not limited to $138 million, and MHI has advised SCE that it disagrees. In October 2013, after a prescribed 90-day waiting period from the service of an earlier notice of dispute, SCE sent MHI a formal request for binding arbitration under the auspices of the International Chamber of Commerce in accordance with the purchase contract seeking damages for all losses. In the request for arbitration, SCE alleges that MHI totally and fundamentally failed to deliver what it promised, and that the contractual limitations of liability are subject to applicable exceptions in the contract and under law. Each of the other co-owners filed lawsuits against MHI, alleging claims arising from MHI's supplying the faulty steam generators. MHI has requested that these lawsuits be stayed pending the arbitration with SCE.

SCE, on behalf of itself and the other San Onofre co-owners, has submitted seven invoices to MHI totaling $149 million for steam generator repair costs incurred through April 30, 2013. MHI paid the first invoice of $45 million, while reserving its right to challenge any of the charges in the invoice. In January 2013, MHI advised SCE that it rejected a portion of the first invoice and required further documentation regarding the remainder of the invoice. In September 2013, SCE reiterated its request to MHI for payment of outstanding invoices. SCE has recorded its share of the invoice paid as a reduction of repair and inspection costs.

San Onofre carries both accidental property damage and accidental outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of claims under both policies. The NEIL policies have a number of exclusions and limitations that may reduce or eliminate coverage. The estimated total claims under the accidental outage insurance through June 30, 2013 are approximately $390 million (SCE’s share of which is approximately $306 million). Pursuant to these proofs of loss, SCE is seeking the weekly indemnity amounts provided under the accidental outage policy for each Unit. Accidental outage policy benefits are reduced by 90% for the periods following announcement of the permanent retirement of the Units. SCE has not submitted a proof of loss under the accidental property damage insurance. No amounts have been recognized in SCE's financial statements, pending NEIL's response. SCE's current expectation is that NEIL will make a coverage determination by the end of the first quarter of 2014.

Continuing NRC Proceedings

As part of the NRC's review of the San Onofre outage and proceedings related to the possible restart of Unit 2, the NRC appointed an Augmented Inspection Team to review SCE's performance. In September 2013, the NRC issued an Inspection Report in connection with The Augmented Inspection Team’s review and SCE’s response to an earlier NRC Confirmatory Action Letter. The NRC’s report contained a preliminary “white” finding (low to moderate safety significance) and an apparent violation regarding the steam generators in Unit 3 and a preliminary “green” finding (very low safety significance) for Unit 2’s steam generators for failing to ensure that MHI’s modeling and analysis were adequate. Simultaneously, the NRC issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of San Onofre’s steam generators. In October 2013, SCE submitted comments to the NRC on the characterizations contained in the Inspection Report but did not contest the findings or violation. In addition, the NRC's Office of Investigations has been conducting an investigation into the accuracy and completeness of information SCE provided to the Augmented Inspection Team. SCE has also been made aware of an investigation related to San Onofre by the NRC's Office of Inspector General, which generally reviews internal NRC affairs. Certain anti-nuclear groups and individual members of Congress have alleged that SCE knew of deficiencies in the steam generators when they were installed or otherwise did not correctly follow NRC requirements in connection with the design and installation of the replacement steam generators, something which SCE has vigorously denied, and have called for investigations, including by the Department of Justice. SCE cannot predict when or whether ongoing inquiries or investigations by the NRC will be completed or whether inquiries by other government agencies will be initiated. Should the NRC find a deficiency in SCE's provision of information, SCE could be subject to additional NRC actions, including the imposition of penalties, and the findings could be taken into consideration in the CPUC regulatory proceedings described above.

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Decommissioning

The decommissioning of a nuclear plant requires the management of three related activities: radiological decommissioning, non-radiological decommissioning and the management of spent nuclear fuel. The decommissioning process may take many years as is expected at San Onofre. SCE leases the land on which San Onofre is located from the United States Navy under a lease that requires SCE to return the property to its original condition.

The process for the radiological decommissioning of a nuclear power plant is governed by NRC regulations. SCE expects that the non-radiological decommissioning of the site may eventually involve other governmental agencies and approvals. Under NRC regulations, the process for radiological decommissioning consists of three phases: initial activities, major decommissioning and storage activities, and license termination. Initial activities include providing a notice of permanent cessation of operations and of permanent removal of fuel from the reactor vessel shortly after the retirement of the plant has been announced. Within two years after the announcement of retirement, the licensee must also submit a post-shutdown decommissioning activities report, an irradiated fuel management plan and a site-specific decommissioning cost estimate.

On June 12, 2013, SCE began the initial activity phase of radiological decommissioning by filing with the NRC a certification of permanent cessation of power operations at San Onofre. Notifications of permanent removal of fuel from the reactor vessels were provided on June 28, 2013 and July 22, 2013 for Units 3 and 2, respectively. SCE currently estimates that it will provide the other initial activity phase plans and cost estimates by the end of 2014. Major radiological decommissioning and storage activities may only start 90 days after the NRC receipt of the post-shutdown decommissioning activities report or upon the filing of a decommissioning cost estimate. The license termination phase will begin with the submission of a license termination plan, which is due not less than two years prior to the planned license termination. The NRC regulations regulate the use of decommissioning trust funds for radiological decommissioning by requiring that various decommissioning process milestones be met prior to the use of additional funds. SCE will also need NRC staff approval to use decommissioning funds for non-radiological decommissioning.

SCE has nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $3.07 billion as of September 30, 2013, which is comprised of annual contributions made through rates and earnings on the trust funds’ balances. Other than the use of funds for the planning of radiological decommissioning (up to a maximum of 3% of a generic formula amount under NRC regulations, or $31 million), the CPUC must issue an order granting prior approval for withdrawal of decommissioning trust funds to be used for radiological decommissioning, non-radiological decommissioning and spent fuel management. The CPUC's authority to authorize the use of trust funds for decommissioning activities is provided by the Nuclear Facility Decommissioning Act of 1985 of the California Public Utilities Code. SCE anticipates filing a request with the CPUC that would authorize early release of trust funds for costs up to a specified cost cap.

Once access is authorized by the CPUC, SCE will fund decommissioning of San Onofre through funds in its nuclear decommissioning trust. In order to determine future funding levels, SCE makes regular forecasts of decommissioning cost estimates based on expert advice. Such forecasts are subject to a number of assumptions and uncertainties, such as future dismantling, transportation, labor and similar costs, the length of time that will be needed to decommission, prevailing rates of inflation, burial escalation rates and other assumptions.

In July 2013, SCE submitted supplemental testimony in the Nuclear Decommissioning Cost Triennial Proceeding ("NDCTP") that provided a decommissioning cost estimate for an early shutdown scenario of both Units 2 and 3. The supplemental testimony provided for a higher level of contributions than is currently collected in rates. However, SCE’s supplemental testimony requested the CPUC to defer an increase in the contribution level until SCE has completed an updated site-specific decommissioning plan for San Onofre currently expected in the first half of 2014.

The total ARO liability related to San Onofre was revised based on the July 2013 update to the NDCTP discussed above. See "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Asset Retirement Obligation" for further information.

ERRA Balancing Account

Rates related to fuel and purchased power are set annually based on a forecast of the costs SCE expects to incur in the following year. Actual fuel and power costs that are greater/less than the forecast are tracked in the ERRA balancing account and collected/refunded to customers in subsequent periods. In August 2012, SCE filed its annual 2013 ERRA forecast, requesting a rate increase of approximately $500 million due to a variety of factors. The 2013 ERRA forecast proceeding was deferred by the Assigned Commissioner while issues related to the San Onofre outage are under consideration in the San Onofre OII. See “—San Onofre Outage, Inspection and Retirement” above.

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As a result, SCE continues to recover in rates amounts authorized in the 2012 ERRA proceeding which are significantly below the costs incurred. As of September 30, 2013, the fuel and power procurement-related costs were under-collected by $719 million.

The CPUC has also established a "trigger" mechanism for the ERRA balancing account that allows for a rate adjustment if the balancing account over- or under-collection exceeds 5% of SCE's prior year generation revenue, or approximately $280 million. In July 2013, SCE triggered the mechanism and filed an application with the CPUC. Prior to the application, SCE had also filed a motion with the CPUC proposing an interim ERRA rate increase.

In September 2013, the CPUC issued a proposed decision on SCE's 2013 ERRA forecast that, if adopted, would approve a portion of SCE's 2013 ERRA forecast and allow SCE to increase rates by approximately $200 million. Under the proposed decision, SCE would not be allowed to increase rates to cover its forecasted net San Onofre replacement power costs (the difference between normal San Onofre costs and the San Onofre costs proposed in the 2013 ERRA forecast filing). Rather, such costs would be tracked in the San Onofre memorandum account. In addition, the proposed decision directs SCE to exclude the net San Onofre costs from the ERRA trigger calculation. The proposed decision makes no determination regarding the accuracy of the methodology used to determine the net San Onofre costs or the reasonableness of the costs. Those determinations will be made in the San Onofre OII. It is uncertain whether the CPUC will adopt this proposal, make other changes in rates, or defer a rate change that would mitigate the current impact on cash flows of ERRA under-collections.

SCE’s under-collection is currently forecasted to be approximately $1 billion at December 31, 2013. SCE may finance unrecovered power procurement-related costs with commercial paper or other borrowing, subject to availability in the capital markets. Delays in approval of rate increases to recover under-collection of fuel and purchase power costs would adversely impact SCE’s liquidity.

In August 2013, SCE filed its annual 2014 ERRA forecast requesting a revenue requirement increase of approximately $1.96 billion or 16.3% over the current 2012 ERRA revenue requirement, beginning in January 2014. On October 21, 2013, a pre-hearing conference was held in the 2014 ERRA forecast proceeding to set the scope and preliminary schedule. SCE cannot currently predict the timing or content of a decision in the 2014 ERRA forecast proceeding.

2015 General Rate Case

On September 10, 2013, the CPUC's Office of Ratepayer Advocates, formerly known as the Division of Ratepayer Advocates, accepted SCE's notice of intent (“NOI”) to file a 2015 GRC. The NOI indicates that SCE's GRC application, expected to be filed by year-end 2013, will request a 2015 base rate revenue requirement of $6.279 billion. After considering the effects of sales growth, SCE's request would be a $120 million increase over currently authorized base rate revenue. If the CPUC approves the requested rate increase and allocates the increase to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 2% and 0.6%, respectively. The NOI indicates that SCE's application will propose post-test year increases in 2016 and 2017, net of sales growth, of $368 million and $331 million, respectively. The requested revenue requirement increase is driven by the need to: maintain system reliability, including investment in infrastructure maintenance and replacement, accommodate customer load growth, and ongoing operation and maintenance expenses. The NOI includes forecasted shutdown operating and capital expenses for San Onofre. To the extent that some or all of these expenses are funded by its nuclear decommissioning trust, SCE will not recover such costs through base rates. The NOI also includes a request for 2015 – 2017 capital expenditures as discussed in "—Liquidity" below. SCE anticipates filing its 2015 GRC application in November 2013 with no material change from the NOI. The current schedule anticipates a final decision on SCE's 2015 GRC by the end of 2014. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or when a final decision will be adopted.

Capital Program

During the first nine months of 2013, SCE's capital program continued to emphasize projects for maintaining reliability and expanding the capability of SCE's transmission and distribution system; upgrading and constructing new transmission lines and substations for system reliability and increased access to renewable energy; and maintaining performance of SCE's natural gas, and hydro-electric generating plants. Total capital expenditures (including accruals) were $2.4 billion and $2.6 billion for the first nine months of 2013 and 2012, respectively. SCE expects that the 2013 capital expenditures will be at or below the lower end of the previously projected range of $3.7 billion to $4.0 billion, due to lower costs on two transmission projects placed in service in 2013 and delays experienced with other transmission and distribution projects. SCE forecasts capital expenditures in the range of $18.2 billion to $20.6 billion for 2013 – 2017. 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; and other factors.

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EME Chapter 11 Bankruptcy Filing

As discussed in the 2012 Form 10-K, on the Petition Date EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. Edison International anticipates that the Bankruptcy Court will approve a plan of reorganization in which Edison International ceases to have its ownership interest. As a result of the bankruptcy filing, Edison International no longer consolidates the earnings and losses of EME or its subsidiaries effective December 17, 2012 and has reflected its ownership interest in EME utilizing the cost method. Edison International recorded a full impairment of the investment in EME in 2012. See "Notes to Consolidated Financial Statements—Note 16. Discontinued Operations" for additional information related to these bankruptcy proceedings.

On December 16, 2012, Edison International, EME and certain of EME's senior unsecured noteholders (“Consenting Noteholders”) entered into a Transaction Support Agreement (the "Support Agreement"). The Support Agreement provided that, within 150 days following the Petition Date, EME was to seek authority from the Bankruptcy Court to enter into the Settlement Transaction, which was required to be obtained within 210 days following the Petition Date. EME did not seek such authority within the 150 day period, rendering the Support Agreement terminable, and the parties did not reach agreement on changes to the Support Agreement, which would have altered the original schedule.

On July 25, 2013, a requisite majority of the Consenting Noteholders provided Edison International and EME with a notice terminating the Support Agreement, effective August 1, 2013. As a result, the extension of the Tax Allocation Agreement contemplated by the Support Agreement has also terminated, and the Tax Allocation Agreement is now due to expire by its terms on December 31, 2013. Furthermore, claims, which Edison International submitted in the EME bankruptcy on a contingency basis, will not be released, and inasmuch as Edison International will not be entitled to the benefits of the Settlement Transaction, it will remain subject to any claims of EME and potentially its creditors, including claims relating to or arising out of any shared services, the Tax Allocation Agreement, and any other relationships or transactions between the companies.

On August 1, 2013, the Official Committee of Unsecured Creditors ("Creditors Committee") made a motion in the Bankruptcy Court to seek sole authority to file, prosecute, and settle alleged claims against Edison International, SCE, certain other subsidiaries of Edison International, and present and former directors of Edison International, SCE and EME. Such motion has not been acted upon by the Bankruptcy Court but was supported by the Consenting Noteholders and was accompanied by a proposed complaint, which has not been filed or served. The motion was opposed by EME, and although EME indicated that immediate litigation was not in EME’s interest, EME indicated that it had been preparing a similar complaint and would file it were it to conclude that it would be in EME’s best interests to do so. The proposed complaint sets forth a variety of theories to allege damages against the named defendants, including, among other things, that $925 million in dividends paid by EME to Mission Energy Holding Company in 2007 are recoverable, that $183 million paid by EME under the Tax Allocation Agreement in September 2012 was not proper, that EME was operated between 2010 and 2012 for Edison International’s benefit and not in accordance with fiduciary duties owed to EME and its creditors, that the amendment of the Tax Allocation Agreement to have it expire December 31, 2013 in the absence of a settlement was a breach of fiduciary duty, that Edison International overcharged EME for shared services, that Edison International and certain of its competitive subsidiaries are alter egos of and should be substantively consolidated with EME and therefore liable for EME’s debts, and that utilization by Edison International and SCE of bonus depreciation following EME’s filing for bankruptcy was a violation of the automatic stay in the EME bankruptcy. Edison International does not know if a complaint containing such allegations or other allegations will be filed and served, but it would vigorously contest such allegations.

On October 18, 2013, EME, certain of its wholly-owned subsidiaries, NRG Energy, Inc., NRG Energy Holdings Inc. (together, “NRG”), the Creditors Committee, certain holders of EME’s senior unsecured notes (the “Notes”), and certain other parties entered into a Plan Sponsor Agreement (the “Plan Sponsor Agreement”). Edison International is not a party to the Plan Sponsor Agreement and reserves the right to support it, oppose it, and/or seek modifications to it. The Plan Sponsor Agreement provides for the parties to it to pursue the restructuring of EME and its debtor subsidiaries through a joint chapter 11 plan of reorganization (the “Plan”) that would include the purchase by NRG of substantially all of the assets of EME in accordance with the terms reflected in an asset purchase agreement and a term sheet (the “Plan Term Sheet”). The Plan Term Sheet provides for the currently outstanding stock of EME to be adjusted, modified, cancelled or otherwise discharged, and for the general unsecured creditors of EME to receive a pro rata distribution of sale proceeds and all new common stock or other interests in reorganized EME. The Plan Term Sheet also provides for any and all claims of EME and its subsidiaries against Edison International, its subsidiaries and any of their related parties, including the entities and certain individuals named as defendants in the proposed complaint described above (together, the “EIX Litigation Parties”) to be retained by EME, subject to a procedure for review of any settlement by creditors. The Plan Term Sheet also contains provisions which permit EME and its subsidiaries to take any action necessary to preserve net operating losses, production tax credits, or other tax attributes of EME and its subsidiaries, would enjoin Edison International from taking any actions affecting such tax

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attributes, and would, if necessary, require Edison International to make elections as necessary to preserve such tax attributes. The Plan is to be filed with the Bankruptcy Court by November 15, 2013. The Plan will be subject to objections and will not be effective unless approved by the Bankruptcy Court. Edison International cannot predict whether or when the Plan will be approved by the Bankruptcy Court or become effective in current or modified form.

RESULTS OF OPERATIONS

SCE

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. Utility cost-recovery activities include rates which provide recovery, subject to reasonableness review of, among other things, fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses and nuclear decommissioning expenses.

The following table summarizes SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities. The 2012 GRC decision eliminated the balancing account treatment for Palo Verde operation and maintenance costs effective January 1, 2012. The tables presented below reflect a reclassification of the revenue and costs for 2012 consistent with the presentation in 2013. The reclassification of revenue and costs had no impact on earnings.

Three months ended September 30, 2013 versus September 30, 2012

	Three months ended September 30, 2013									Three months ended September 30, 2012
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue	$	1,845		$	2,112		3,957			$	1,778		$	1,953	$	3,731
Fuel and purchased power	—			1,808			1,808			—			1,694		1,694
Operation and maintenance	572			303			875			647			259		906
Depreciation, decommissioning and amortization	392			—			392			399			—		399
Property taxes and other	78			—			78			73			—		73
Total operating expenses	1,042			2,111			3,153			1,119			1,953		3,072
Operating income	803			1			804			659			—		659
Interest income and other	12			—			12			29			—		29
Interest expense	(130		)	(1		)	(131		)	(124		)	—		(124		)
Income before income taxes	685			—			685			564			—		564
Income tax expense	183			—			183			176			—		176
Net income	502			—			502			388			—		388
Dividends on preferred and preference stock	25			—			25			25			—		25
Net income available for common stock	$	477		$	—		$	477		$	363		$	—	$	363
Core earnings1							$	477							$	363
Non-core earnings							—								—
Total SCE GAAP earnings							$	477							$	363

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

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Utility Earning Activities

• Operating revenue was $67 million higher primarily due to the following:

• An estimated increase of $160 million related to the timing of finalizing the 2012 CPUC GRC. During the third quarter of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement. In the fourth quarter of 2012, SCE implemented its 2012 GRC which allowed SCE to recover its revenue requirement retroactive to January 1, 2012.

• A decrease in San Onofre-related estimated revenue of $99 million, as discussed below.

• An increase of revenue during the third quarter of 2013 for SCE's return on its investment resulting from rate base growth and operating costs partially offset by a lower CPUC-adopted 2013 return on common equity and EdisonSmartConnect^® revenue (see "Liquidity and Capital Resources—SCE Regulatory Proceedings—2013 Cost of Capital Application" for further information).

• A decrease in operation and maintenance expense of $75 million, which included a San Onofre-related decrease of $68 million as discussed below and $23 million of lower expense in 2013 due to the full deployment of the EdisonSmartConnect^® program in 2012 partially offset by higher liability insurance costs.

• Lower depreciation, decommissioning and amortization expense of $7 million primarily related to a $45 million impact from ceasing depreciation on the San Onofre assets, beginning in June 2013, offset by a $38 million increase in depreciation related to generation, transmission and distribution investments.

• Lower interest income and other primarily due to lower AFUDC equity due to lower rates and construction work in process balances in 2013 and higher other expenses in 2013. See "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses."

• Higher income taxes primarily due to higher pre-tax income partially offset by higher income tax benefits associated with repair deductions (as determined for income tax purposes). See "—Income Taxes" below for more information.

The results of San Onofre were slightly positive during the third quarter of 2013 as compared to the third quarter of 2012 as lower incremental repairs and inspection costs more than offset the lower revenue related to no longer recognizing the return on San Onofre rate base, beginning in June 2013, pending regulatory treatment in the San Onofre OII. Lower revenue and operating costs at San Onofre are due to:

• As described in the Management Overview, authorized revenue related to San Onofre from January 1, 2012 is subject to refund as determined by the CPUC. Beginning in the third quarter of 2013, SCE’s authorized revenue related to San Onofre exceeded its cost of service (determined as actual operation and maintenance and property and other taxes through September 2013; and depreciation and cost of capital through the date SCE decided to permanently retire Units 2 and 3 at San Onofre, pending the outcome of the OII). Accordingly, SCE’s revenue recognition is based on its lower cost of service (as determined above) resulting in a decrease in revenue of $99 million during the third quarter of 2013. Revenue related to San Onofre is expected to continue to be lower in future periods.

• Operation and maintenance expenses were $68 million lower in the third quarter of 2013, primarily from incremental inspection and repair costs of $47 million during the third quarter of 2012 (none in the third quarter of 2013) and cost reductions resulting from the early retirement of Units 2 and 3. In addition, operation and maintenance expense, included severance costs of $32 million and $27 million in the third quarter of 2013 and 2012, respectively.

Utility Cost-Recovery Activities

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

• Higher fuel and purchased power expense of $114 million was primarily driven by higher power and gas prices experienced in 2013 relative to 2012, partially offset by a $43 million credit received from the ISO for SCE’s share of a settlement between the FERC and an ISO participant.

• Higher operation and maintenance expense of $44 million primarily due to costs for the GHG cap-and-trade program related to utility owned generation, and an increase in pension benefit contributions.

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Nine months ended September 30, 2013 versus September 30, 2012

	Nine months ended September 30, 2013								Nine months ended September 30, 2012
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated
Operating revenue	$	5,012		$	4,619	$	9,631		$	4,745		$	4,049		$	8,794
Fuel and purchased power	—			3,818		3,818			—			3,269			3,269
Operation and maintenance	1,739			801		2,540			1,847			775			2,622
Depreciation, decommissioning and amortization	1,223			—		1,223			1,187			—			1,187
Property taxes and other	229			—		229			229			—			229
Asset impairment	575			—		575			—			—			—
Total operating expenses	3,766			4,619		8,385			3,263			4,044			7,307
Operating income	1,246			—		1,246			1,482			5			1,487
Interest income and other	51			—		51			72			—			72
Interest expense	(384		)	—		(384		)	(368		)	(5		)	(373		)
Income before income taxes	913			—		913			1,186			—			1,186
Income tax expense	196			—		196			384			—			384
Net income	717			—		717			802			—			802
Dividends on preferred and preference stock	75			—		75			66			—			66
Net income available for common stock	$	642		$	—	$	642		$	736		$	—		$	736
Core earnings1						1,007									736
Non-core earnings						(365		)							—
Total SCE GAAP earnings						$	642								$	736

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

Utility Earning Activities

• Operating revenue was $267 million higher primarily due to the following:

• An estimated increase of $325 million related to the timing of finalizing the 2012 CPUC GRC. 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. In the fourth quarter of 2012, SCE implemented its 2012 GRC which allowed SCE to recover its revenue requirement retroactive to January 1, 2012.

• A decrease in San Onofre-related estimated revenue of $112 million, as discussed below.

• An increase of revenue during the first nine months of 2013 for SCE's return on its investment resulting from rate base growth and operating costs partially offset by a lower CPUC-adopted 2013 return on common equity and EdisonSmartConnect^® revenue (see "Liquidity and Capital Resources—SCE—Regulatory Proceedings—2013 Cost of Capital Application" for further information).

• A decrease in operation and maintenance expense of $108 million, which included a San Onofre-related decrease of $112 million, as discussed below, and $65 million of lower expense in 2013 due to the full deployment of the EdisonSmartConnect^® program in 2012. These items were partially offset by $25 million of higher accrued severance costs related to planned workforce reductions, $15 million of planned outage costs at Mountainview and repair costs at Four Corners, higher liability insurance and legal costs.

• Higher depreciation, decommissioning and amortization expense primarily related to increased generation, transmission and distribution investments, offset by the impact from ceasing depreciation on the San Onofre assets, beginning in June 2013.

• Lower interest income and other primarily due to lower AFUDC equity due to lower rates and construction work in process balances in 2013 and higher other expenses in 2013. See "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses."

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• Lower income taxes primarily due to the asset impairment partially offset by higher income tax benefits associated with repair deductions (as determined for income tax purposes). See "—Income Taxes" below for more information.

On June 6, 2013, SCE decided to permanently retire San Onofre Units 2 and 3 and recorded an asset impairment charge of $575 million. See "—San Onofre Outage, Inspection and Retirement" above for more information. Excluding the asset impairment, the results of San Onofre were slightly positive during the first nine months of 2013 as compared to 2012 as lower incremental repairs and inspection costs more than offset the lower revenue related to no longer recognizing the return on San Onofre rate base, beginning in June 2013, pending regulatory treatment in the San Onofre OII. Lower revenue and operating costs at San Onofre affects SCE period-to-period results as summarized below:

• Decrease in revenue of $112 million mainly due to lower revenue during the third quarter of 2013 as described above and $40 million of revenue in 2012 related to the scheduled outage of Unit 2.

• Decrease in operating and maintenance expenses of $112 million primarily due to lower incremental inspection and repair costs of $82 million, costs reductions resulting from the early retirement of Units 2 and 3 and $35 million in 2012 related to scheduled outage at Unit 2. These factors were partially offset by severance costs of $80 million and $27 million in the nine months periods of 2013 and 2012, respectively.

Utility Cost-Recovery Activities

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

• Higher fuel and purchased power expense of $549 million was primarily driven by increased load related to warmer weather experienced in 2013 relative to 2012 and higher power and gas prices in 2013, partially offset by a $43 million credit received from the ISO for SCE’s share of a settlement between the FERC and an ISO participant.

• Higher operation and maintenance expense of $26 million primarily due to costs for the GHG cap-and-trade program related to utility owned generation, partially offset by lower employee benefit costs and spending on various public purpose programs.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over-/under-collections) was $3.9 billion and $9.1 billion for the three- and nine-month periods ended September 30, 2013, respectively, compared to $3.7 billion and $8.7 billion for the respective periods in 2012. The increase in revenue reflects a sales volume decrease of $32 million and an increase of $41 million for the three- and nine-month periods, respectively and a rate increase of $245 million and $387 million for the same periods. The rate increase was due to the implementation of the 2012 GRC decision.

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 2012 Form 10-K).

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)	2013			2012			2013			2012
Income from continuing operations before income taxes	$	685		$	564		$	913		$	1,186
Provision for income tax at federal statutory rate of 35%	240			197			319			415
Increase (decrease) in income tax from:
State tax, net of federal benefit	21			10			12			30
Property-related	(57		)	(19		)	(121		)	(39		)
Uncertain tax positions	(6		)	1			11			1
Other	(15		)	(13		)	(25		)	(23		)
Total income tax expense from continuing operations	$	183		$	176		$	196		$	384
Effective tax rate	26.7		%	31.2		%	21.5		%	32.4		%

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The decrease in the effective tax rate for the three- and nine-month periods was primarily due to the recognition of higher income tax benefits from repair deductions (as determined for income tax purposes) and reduction of liabilities for uncertain tax positions related to generation repair deductions resulting from recent IRS guidance. Additional tax benefits recorded from finalizing tax returns during the respective three months ended September 30, 2013 and 2012 was $10 million and $15 million, respectively.

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

Edison International Parent and Other

Results of operations for Edison International Parent and Other includes amounts from other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.

Income from Continuing Operations

The Edison International Parent and Other loss from continuing operations increased $8 million for both the three- and nine-months ended September 30, 2013, respectively, compared to the same periods in 2012, primarily due to higher consolidated state income taxes in prior periods partially offset by Edison Capital's sale of its lease interest in Unit No. 2 of the Beaver Valley Nuclear Plant.

Loss from Discontinued Operations (Net of Tax)

Loss from discontinued operations, net of tax, was $25 million and $1 million for the three- and nine-month periods in 2013 compared to a loss of $167 million and $360 million for the respective periods in 2012. The 2013 loss from discontinued operations reflects a revised estimate of the tax impact of expected future deconsolidation and separation of EME from Edison International (see "Notes to Consolidated Financial Statements—Note 16. Discontinued Operations" for further information). The 2012 loss from discontinued operations was from net losses of EME.

LIQUIDITY AND CAPITAL RESOURCES

SCE

SCE's ability to operate its business, fund capital expenditures, and implement its business strategy is 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 Edison International, and the outcome of tax and regulatory matters.

SCE expects to fund its 2013 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 fund requirements.

Available Liquidity

At September 30, 2013, SCE had a $2.75 billion multi-year revolving credit facility. On July 18, 2013, SCE amended the credit facility to extend the maturity date to July 2018 for $2.6 billion. The remaining $150 million of the credit facility is scheduled to mature in May 2017. The following table summarizes the status of the SCE credit facility at September 30, 2013:

(in millions)
Commitment	$	2,750
Outstanding commercial paper supported by credit facilities	(1,354		)
Outstanding letters of credit	(140		)
Amount available	$	1,256

As discussed in "Management Overview—ERRA Balancing Account," SCE may finance unrecovered power procurement-related costs with commercial paper or other borrowings, subject to availability in the capital markets.

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Financing Subsequent to September 30, 2013

In October 2013, SCE issued $200 million of floating rate due in 2014, $600 million of 3.50% due in 2023, and $800 million of 4.65% first and refunding mortgage bonds due in 2043. The proceeds from these bonds were used to redeem $800 million of outstanding first mortgage bonds in October 2013 (due in March 2014), to repay commercial paper borrowings and to fund SCE's capital program.

Debt Covenant

The debt covenant in SCE's credit facility limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At September 30, 2013, SCE's debt to total capitalization ratio was 0.47 to 1.

Capital Investment Plan

SCE's forecasted capital expenditures for 2013 – 2017 include a capital forecast in the range of $18.2 billion to $20.6 billion. The range is based on a 7% average variability between annual forecast capital expenditures and actual spending in years with an approved general rate case and 15% variability in years without an approved general rate case, or an average variability of 12%. SCE's 2013 – 2017 capital expenditures forecast are set forth in the table below:

(in millions)	2013		2014		2015		2016		2017		2013 – 2017 Total
Transmission	$	1,209	$	914	$	819	$	973	$	962	$	4,877
Distribution	2,238		2,895		3,167		3,154		3,012		14,466
Generation	328		234		252		253		227		1,294
Total estimated capital expenditures	$	3,775	$	4,043	$	4,238	$	4,380	$	4,201	$	20,637
Total estimated capital expenditures for 2013 – 2017 (using variability discussed above)	$	3,667	$	3,598	$	3,603	$	3,722	$	3,571	$	18,161

The 2013 – 2014 planned capital expenditures for projects under CPUC jurisdiction are recovered through the authorized revenue requirement in SCE's 2012 GRC or through other CPUC-authorized mechanisms. Recovery of planned capital expenditures for projects under CPUC jurisdiction beyond 2014 and not already approved through other CPUC-authorized mechanisms, is subject to the outcome of the 2015 GRC or other CPUC approvals. Recovery for 2013 – 2017 planned capital expenditures for projects under FERC jurisdiction will be pursued through FERC-authorized mechanisms.

Transmission Projects

A summary of SCE's large transmission and substation projects during the next five years is presented below:

Project Name	Description	Project Lifecycle Phase	Scheduled in Service Date	Direct Expenditures1(in millions)		2013 – 2017 Forecast (in millions)
Tehachapi 1-11	Transmission lines and substation	In construction	2016	$	2,860	$	917
West of Devers	Transmission lines and structures	In construction	2019 – 2020	1,034		618
Coolwater-Lugo	Transmission lines, substations and telecommunication facilities	In construction	2018	813		540

¹  Direct expenditures include direct labor, land and contract costs incurred for the respective projects and exclude overhead costs that are included in the capital expenditures forecasted for 2013 – 2017.

Tehachapi Project

In response to opposition from the city of Chino Hills, CPUC proceedings to reexamine construction options, including undergrounding lines for a portion of the Tehachapi Project, were initiated. On July 11, 2013, the CPUC ordered SCE to underground a 3.5 mile portion of the line that traverses Chino Hills, setting a cost estimate of $224 million ($231 million in nominal dollars) for the underground portion. The cost estimate that SCE had proposed for the underground portion of the Tehachapi Project was $350 million ($360 million in nominal dollars), which is reflected in the table above. In September 2013, SCE filed a petition with the CPUC to modify the CPUC's orders pertaining to the scope of the underground project and defer the associated cost adjustments. The partial undergrounding of the transmission lines will create additional costs and could potentially delay the completion of the Tehachapi Project. As with all transmission investments, cost recovery for the project is subject to FERC review and approval.

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SCE filed a petition to modify the original decision approving the Tehachapi Project seeking authorization to install aviation marking and lighting in accordance with FAA standards. In October 2011, the CPUC staff notified SCE that the constructed portions of the project should be marked and lighted as required, but instructed SCE to defer completion of remaining project components that may require aviation marking or lighting pending CPUC review of the petition to modify. The modification to install aviation marking and lighting will create additional costs and are not reflected in the tables above.

Regulatory Proceedings

2013 Cost of Capital Application

As discussed in the year-ended 2012 MD&A, in December 2012, the CPUC issued a final decision in the ratemaking capital structure and cost of capital phase of SCE's 2013 cost of capital proceeding. In March 2013, a final decision was issued in the second phase of the proceeding that reauthorized SCE's adjustment mechanism to continue for 2014 and 2015. The mechanism provides for an automatic readjustment to SCE’s capital costs if certain thresholds are reached on an annual basis. As a result, SCE will not adjust its ratemaking capital structure or cost of capital for 2014 and will reevaluate the cost of capital for 2015 in September 2014.

2013 – 2014 Energy Efficiency Incentive Mechanism

In September 2013, the CPUC adopted a new energy efficiency incentive mechanism called the Energy Savings and Performance Incentive Mechanism ("ESPI"). The ESPI will apply starting with the 2013 – 2014 energy efficiency program cycle and continue for subsequent cycles, until further notice. The ESPI is comprised of performance/savings rewards and management fees based on actual energy efficiency expenditures and does not contain any provisions for penalties. The proposed ESPI schedule for earning claims anticipates payments of the incentive rewards occurring between two and three years after the relevant program year.

FERC Refund Settlement

SCE has participated in proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets during the energy crisis in California in 2000 – 2001. In October 2013, the FERC approved a settlement agreement that SCE and other parties entered into with Powerex Corp, the wholly-owned electricity marketing subsidiary of a Canadian utility. SCE is allowed to refund to customers 90% of any refunds actually realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive. SCE will receive distributions of approximately $150 million of which a portion is subject to the shareholder incentive ($10 million). SCE will recognize the settlement in the fourth quarter. SCE cannot predict the timing of the distribution.

FERC Formula Rates

As discussed in the year-ended 2012 MD&A, the FERC has accepted, subject to refund and settlement procedures, SCE's request to implement formula rates effective January 1, 2012 to determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP") revenue requirement that was previously recovered through a separate mechanism. In August 2013, SCE reached a settlement on its formula rates that will determine SCE's FERC transmission revenue requirement, including its CWIP, through December 31, 2017. The settlement provides for a base ROE of 9.30%, the previously authorized 50 basis point incentive for CAISO participation and individual, previously authorized project incentives. This results in a FERC weighted average ROE of approximately 10.45%. The settlement ROE will remain in effect until at least June 30, 2015, when the moratorium, provided for in the settlement, on modifications to the formula rate tariff ends. The transmission revenue requirement and rates that have been in effect and that have been billed to customers since January 1, 2012, were based on a total FERC weighted average ROE of 11.1%. Although the settlement's provisions and adjustments will result in customer refunds of approximately $200 million during 2014, it will not have a material effect on SCE earnings in 2013. SCE filed the settlement with the FERC, requesting approval by November 15, 2013. The FERC has issued an order allowing interim settlement rates to go into effect on October 1, 2013. Under the settlement, these interim rates are expected to be modified on January 1, 2014 through an annual update filing that will be made by SCE in December 2013.

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Dividend Restrictions

The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above 48% on a 13-month weighted average basis. At September 30, 2013, SCE's 13-month weighted-average common equity component of total capitalization was 49.5% and the maximum additional dividend that SCE could pay to Edison International under this limitation was approximately $253 million, resulting in a restriction on net assets of approximately $11.74 billion.

During the first nine months of 2013, SCE made $240 million in dividend payments to Edison International. In September 2013, SCE declared a dividend to Edison International of $120 million which will be paid in October 2013. Future dividend amounts and timing of distributions are dependent upon several factors including the level of capital expenditures, operating cash flows and earnings.

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, 2013, 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.

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, 2013.

(in millions)
Collateral posted as of September 30, 20131	$	177
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade	74
Posted and potential collateral requirements2	$	251

¹  Collateral provided to counterparties and other brokers consisted of $21 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $14 million of cash reflected in "Other current assets" on the consolidated balance sheets and $142 million in letters of credit and surety bonds.

²  SCE does not project a material increase in the total posted and potential collateral requirements based on SCE's forward positions as of September 30, 2013 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level.

In addition to the potential collateral requirements discussed above, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $217 million for its workers compensation self-insurance plan. See "Liquidity and Capital Resources—SCE—Workers Compensation Self-Insurance Fund" in the year-ended 2012 MD&A for further information.

Edison International Parent and Other

Edison International Parent and Other's liquidity and its ability to pay operating expenses and dividends to common shareholders is dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets.

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At September 30, 2013, Edison International Parent had a $1.25 billion multi-year revolving credit facility. On July 18, 2013, Edison International Parent amended the credit facility to extend the maturity date to July 2018 for $1.182 billion. The remaining $68 million of the credit facility is scheduled to mature in May 2017. The following table summarizes the status of the Edison International Parent credit facility at September 30, 2013:

(in millions)	Edison International Parent
Commitment	$	1,250
Outstanding borrowings	(174		)
Outstanding letters of credit	—
Amount available	$	1,076

The debt covenant in Edison International Parent's credit facility requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At September 30, 2013, Edison International Parent's consolidated debt to total capitalization ratio was 0.50 to 1.

Historical Cash Flows

SCE

	Nine months ended September 30,
(in millions)	2013			2012
Net cash provided by operating activities	$	2,346		$	2,656
Net cash provided by financing activities	1,196			636
Net cash used by investing activities	(3,065		)	(3,259		)
Net increase in cash and cash equivalents	$	477		$	33

Net Cash Provided by Operating Activities

Net cash provided by operating activities decreased $310 million during the first nine months of 2013 compared to the same period in 2012 primarily due to the following:

• $330 million decrease from balancing accounts primarily composed of:

• $769 million decrease primarily resulting from ERRA balancing account under-collections for fuel and power procurement-related costs in 2013 compared to over-collections in 2012. The change in the ERRA balancing account decreased operating cash flows by $854 million in 2013 compared to a decrease in operating cash flows of $85 million in 2012;

• $433 million increase related to a rate increase in 2013 as a result of the implementation of the 2012 CPUC GRC decision; and

• $187 million increase from GHG auction revenue during 2013.

• $70 million decrease resulting from security deposits returned related to transmission and distribution projects.

• Timing of cash receipts and disbursements related to working capital items and workforce reduction severance costs paid of $132 million during the first nine months of 2013.

• Higher cash inflow due to higher authorized revenue requirements resulting from the implementation of the 2012 CPUC GRC decision.

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Net Cash Provided by Financing Activities

The following table summarizes cash provided (used) by financing activities for the nine months ended September 30, 2013 and 2012. Issuances of debt and preference stock are discussed in "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "—Note 13. Preferred and Preference Stock."

	Nine months ended  September 30,
(in millions)	2013			2012
Issuances of first and refunding mortgage bonds, net	$	394		$	391
Short-term debt financing, net	1,178			(45		)
Issuances of preference stock, net	387			804
Payments of common stock dividends to Edison International	(240		)	(349		)
Redemptions of preference stock	(400		)	(75		)
Payments of preferred and preference stock dividends	(81		)	(62		)
Other	(42		)	(28		)
Net cash provided by financing activities	$	1,196		$	636

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 $2.76 billion and $3.11 billion for the nine months ended September 30, 2013 and 2012, respectively, primarily related to transmission, distribution and generation investments. Net purchases of nuclear decommissioning trust investments and other were $283 million and $164 million for the nine months ended September 30, 2013 and 2012, respectively.

Edison International Parent and Other

The table below sets forth condensed historical cash flow from continuing operations for Edison International Parent and Other adjusted for the non-cash impact related to the treatment of discontinued operations.

	Nine months ended September 30,
(in millions)	2013			2012
Net cash provided (used) by operating activities	$	(93	)	$	42
Net cash provided by financing activities	79			34
Net cash provided (used) by investing activities	(23		)	104
Net increase (decrease) in cash and cash equivalents	$	(37	)	$	180

Net Cash Used by Continuing Operating Activities

Net cash used by continuing operating activities is related to operating costs and approximately $25 million of payments made for interest and income taxes.

Net Cash Provided by Continuing Financing Activities

Net cash provided by continuing financing activities for the first nine months of 2013 were as follows:

• Paid $330 million of dividends to Edison International common shareholders;

• Received $240 million of dividend payments from SCE; and

• Borrowed $173 million under Edison International's line of credit to fund interim working capital requirements.

Net cash provided by continuing financing activities for the first nine months of 2012 were as follows:

• Paid $318 million of dividends to Edison International common shareholders; and

• Received $349 million of dividend payments from SCE.

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Net Cash (Used) Provided by Investing Activities

Net cash used by continuing investing activities during 2013 relate to Edison International's investment of $18 million in equity interests of competitive energy-related businesses, including the acquisition of SoCore Energy, LLC, a distributed solar developer focused on commercial rooftop installations.

Net cash provided by continuing investing activities during 2012 related to Edison International's sale of its lease interest in Unit No. 2 of the Beaver Valley Nuclear Power Plant to a third party for $108 million.

Contingencies

Edison International has a contingency related to the EME Chapter 11 Bankruptcy Filing and SCE has contingencies related to San Onofre Outage, Inspection and Retirement, SED Investigations, Four Corners New Source Review Litigation, Nuclear Insurance, Wildfire Insurance and Spent Nuclear Fuel which are discussed in "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."

Environmental Remediation

As of September 30, 2013, SCE had identified 19 material sites for remediation and recorded an estimated minimum liability of $129 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies" for further discussion.

MARKET RISK EXPOSURES

Edison International and 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 including market risks of SCE's customers. For a further discussion of market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments" and "—Note 4. Fair Value Measurements."

Commodity Price Risk

The fair value of outstanding derivative instruments used to mitigate exposure to commodity price risk was a net liability of $1.1 billion and $851 million at September 30, 2013 and December 31, 2012, respectively. For further discussion of fair value measurements and the fair value hierarchy, see "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.

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As of September 30, 2013, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

	September 30, 2013
(in millions)	Exposure2		Collateral			Net Exposure
S&P Credit Rating1
A or higher	$	245	$	—		$	245
Not rated3	9		(2		)	7
Total	$	254	$	(2	)	$	252

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 complete discussion on Edison International's and SCE's critical accounting policies, see "Critical Accounting Estimates and Policies" in the year-ended 2012 MD&A.

NEW ACCOUNTING GUIDANCE

New accounting guidance is discussed in "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 Item 3 is included in the MD&A under the heading "Market Risk Exposures" and is incorporated herein by reference.

ITEM 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The management of Edison International and SCE, under the supervision and with the participation of Edison International's Chief Executive Officer and Chief Financial Officer and SCE's President and Chief Financial Officer, have evaluated the effectiveness of Edison International's and 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), respectively, as of the end of the third quarter of 2013. Based on that evaluation, Edison International's Chief Executive Officer and Chief Financial Officer and SCE's President and Chief Financial Officer have each concluded that, as of the end of the period, Edison International's and SCE's disclosure controls and procedures, respectively, were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in Edison International’s or SCE's internal control over financial reporting, respectively, during the third quarter of 2013 that have materially affected, or are reasonably likely to materially affect, Edison International’s or SCE's internal control over financial reporting.

Jointly Owned Utility Plant

Edison International's and SCE's respective scope of evaluation of internal control over financial reporting includes their Jointly Owned Utility Projects as discussed in Note 2. Property, Plant and Equipment in the 2012 Form 10-K.

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PART II.    OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

EME Chapter 11 Bankruptcy Filing

On December 17, 2012, EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. For more information, see "Management Overview—EME Chapter 11 Bankruptcy Filing" in the MD&A and "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies" and "—Note 16. Discontinued Operations."

Catalina South Coast Air Quality Management District Environmental Proceeding

In March 2013, the South Coast Air Quality Management District ("SCAQMD") issued a Notice of Violation ("NOV") alleging that SCE was operating Unit 15, SCE's primary diesel generation unit on Catalina Island, in violation of its air permit because Unit 15 was utilizing a CO catalyst not described in the permit. In September 2013, SCE accepted a SCAQMD Offer of Settlement and paid a $1,000 civil penalty to resolve the NOV.

ITEM 2.    UNREGISTRED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by Edison International and Affiliated Purchasers

The following table contains information about all purchases of Edison International Common Stock made by or on behalf of Edison International in the third quarter of 2013.

Period	(a) Total Number of Shares (or Units) Purchased1	(b) Average Price Paid per Share (or Unit)1			(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1, 2013 to July 31, 2013	227,286		$	48.48	—	—
August 1, 2013 to August 31, 2013	440,090		48.29		—	—
September 1, 2013 to September 30, 2013	124,023		45.75		—	—
Total	791,399		47.95		—	—

¹  The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's: (i) 401(k) Savings Plan; (ii) Dividend Reinvestment and Direct Stock Purchase Plan; and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions.

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ITEM 6.    EXHIBITS

Exhibit Number	Description
31.1	Certifications of the Chief Executive Officer and Chief Financial Officer of Edison International pursuant to Section 302 of the Sarbanes-Oxley Act
31.2	Certifications of the Chief Executive Officer and Chief Financial Officer of Southern California Edison Company pursuant to Section 302 of the Sarbanes-Oxley Act
32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of Edison International required by Section 906 of the Sarbanes-Oxley Act
32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Southern California Edison Company required by Section 906 of the Sarbanes-Oxley Act
101.1	Financial statements from the quarterly report on Form 10-Q of Edison International for the quarter ended September 30, 2013, filed on October 29, 2013, 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
101.2	Financial statements from the quarterly report on Form 10-Q of Southern California Edison Company for the quarter ended September 30, 2013, filed on October 29, 2013, 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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.

	EDISON INTERNATIONAL		SOUTHERN CALIFORNIA EDISON COMPANY
By:	/s/ Mark C. Clarke	By:	/s/ Mark C. Clarke
	Mark C. Clarke Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)		Mark C. Clarke Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)
Date:	October 29, 2013	Date:	October 29, 2013

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