EDISON INTERNATIONAL (Form: 10-Q, Received: 10/28/2014 16:07:44)

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, 2014
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 o Southern California Edison Company Yes o No þ

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 o Southern 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 þ Southern 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 24, 2014:
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			7
	SCE Consolidated Statements of Comprehensive Income			7
	SCE Consolidated Balance Sheets			8
	SCE Consolidated Statements of Cash Flows			10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS				11
	Note 1. Summary of Significant Accounting Policies			11
	Note 2. Consolidated Statements of Changes in Equity			15
	Note 3. Variable Interest Entities			16
	Note 4. Fair Value Measurements			18
	Note 5. Debt and Credit Agreements			22
	Note 6. Derivative Instruments			23
	Note 7. Income Taxes			25
	Note 8. Compensation and Benefit Plans			26
	Note 9. San Onofre Issues			29
	Note 10. Other Investments			32
	Note 11. Regulatory Assets and Liabilities			33
	Note 12. Commitments and Contingencies			34
	Note 13. Preferred and Preference Stock of Utility			37
	Note 14. Accumulated Other Comprehensive Loss			37
	Note 15. Interest and Other Income and Other Expenses			38
	Note 16. Discontinued Operations			39
	Note 17. Supplemental Cash Flows Information			40
ITEM 1A. RISK FACTORS				41
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				41
FORWARD-LOOKING STATEMENTS				41
MANAGEMENT OVERVIEW				43
	Highlights of Operating Results			43
	San Onofre Issues			44
	ERRA Balancing Account			47
	2015 General Rate Case			48
	Capital Program			48
	EME Chapter 11 Bankruptcy			48
RESULTS OF OPERATIONS				50
	Southern California Edison Company			50
		Three months ended September 30, 2014 versus September 30, 2013		50
			Utility Earning Activities	51



			Utility Cost-Recovery Activities	52
		Nine months ended September 30, 2014 versus September 30, 2013		52
			Utility Earning Activities	53
			Utility Cost-Recovery Activities	53
	Supplemental Operating Revenue Information			54
	Income Taxes			54
	Edison International Parent and Other			54
		Income from Continuing Operations		54
	Income (Loss) from Discontinued Operations (Net of Tax)			55
LIQUIDITY AND CAPITAL RESOURCES				55
	Southern California Edison Company			55
		Available Liquidity		55
		Regulatory Proceedings		55
		Dividend Restrictions		56
		Margin and Collateral Deposits		56
	Edison International Parent and Other			56
	Historical Cash Flows			57
		Southern California Edison Company		57
		Edison International Parent and Other		58
	Contingencies			59
		Environmental Remediation		59
MARKET RISK EXPOSURES				59
	Commodity Price Risk			59
	Credit Risk			59
CRITICAL ACCOUNTING ESTIMATES AND POLICIES				60
NEW ACCOUNTING GUIDANCE				60
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				60
ITEM 4. CONTROLS AND PROCEDURES				60
	Disclosure Controls and Procedures			60
	Changes in Internal Control Over Financial Reporting			60
	Jointly Owned Utility Plant			60
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS				61
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS				61
	Purchases of Equity Securities by Edison International and Affiliated Purchasers			61
ITEM 6. EXHIBITS				62
SIGNATURES				63

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.

GLOSSARY

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



2013 Form 10-K		Edison International's and SCE's combined Annual Report on Form 10-K for the year-ended December 31, 2013
APS		Arizona Public Service Company
ARO(s)		asset retirement obligation(s)
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
Competitive Businesses		competitive businesses related to the generation, delivery and use of electricity
CPUC		California Public Utilities Commission
CRRs		congestion revenue rights
DOE		U.S. Department of Energy
EME		Edison Mission Energy
EME Settlement Agreement		Settlement Agreement entered into by Edison International, EME, and the Consenting Noteholders in February 2014
EMG		Edison Mission Group Inc.
EPS		earnings per share
ERRA		energy resource recovery account
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Four Corners		coal fueled electric generating facility located in Farmington, New Mexico in which SCE held 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, Ltd. and related companies
Moody's		Moody's Investors Service
MW		megawatts
MWh		megawatt-hours
NAAQS		national ambient air quality standards
NERC		North American Electric Reliability Corporation
NRC		Nuclear Regulatory Commission
OII		Order Instituting Investigation
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)

iii



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
QF(s)		qualifying facility(ies)
ROE		return on common equity
S&P		Standard & Poor's Ratings Services
San Onofre		retired nuclear generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest
San Onofre OII Settlement Agreement		Settlement Agreement dated March 27, 2014 between SCE, The Utility Reform Network ("TURN"), the CPUC's Office of Ratepayer Advocates ("ORA") and SDG&E, which was later joined by the Coalition of California Utility Employees ("CUE") and Friends of the Earth ("FOE"), which was superseded by the San Onofre OII Amended Settlement Agreement
San Onofre OII Amended Settlement Agreement		Settlement Agreement dated September 23, 2014 between SCE, TURN, ORA, SDG&E, CUE, and FOE, which remains subject to CPUC approval
SCE		Southern California Edison Company
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
US EPA		U.S. Environmental Protection Agency
VIE(s)		variable interest entity(ies)

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



Consolidated Statements of Income	Edison International

	Three months ended September 30,						Nine months ended September 30,
(in millions, except per-share amounts, unaudited)	2014			2013			2014			2013
Operating revenue	$	4,356		$	3,960		$	10,298		$	9,638
Fuel	77			95			219			249
Purchased power	2,105			1,713			4,344			3,569
Operation and maintenance	879			971			2,480			2,809
Depreciation, decommissioning and amortization	424			392			1,248			1,224
Impairment and other charges	(3		)	—			228			575
Total operating expenses	3,482			3,171			8,519			8,426
Operating income	874			789			1,779			1,212
Interest and other income	40			28			109			91
Interest expense	(141		)	(137		)	(422		)	(402		)
Other expenses	(29		)	(15		)	(52		)	(38		)
Income from continuing operations before income taxes	744			665			1,414			863
Income tax expense	220			177			284			173
Income from continuing operations	524			488			1,130			690
Income (loss) from discontinued operations, net of tax	(16		)	(25		)	146			(1		)
Net income	508			463			1,276			689
Preferred and preference stock dividend requirements of utility	28			25			84			75
Net income attributable to Edison International common shareholders	$	480		$	438		$	1,192		$	614
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax	$	496		$	463		$	1,046		$	615
Income (loss) from discontinued operations, net of tax	(16		)	(25		)	146			(1		)
Net income attributable to Edison International common shareholders	$	480		$	438		$	1,192		$	614
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	$	1.52		$	1.42		$	3.21		$	1.88
Discontinued operations	(0.05		)	(0.08		)	0.45			—
Total	$	1.47		$	1.34		$	3.66		$	1.88
Diluted earnings (loss) per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities	329			328			329			329
Continuing operations	$	1.51		$	1.41		$	3.18		$	1.87
Discontinued operations	(0.05		)	(0.07		)	0.44			—
Total	$	1.46		$	1.34		$	3.62		$	1.87
Dividends declared per common share	$	0.355		$	0.3375		$	1.065		$	1.0125

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



Consolidated Statements of Comprehensive Income						Edison International

	Three months ended September 30,					Nine months ended September 30,
(in millions, unaudited)	2014			2013		2014			2013
Net income	$	508		$	463	$	1,276		$	689
Other comprehensive income (loss), net of tax:
Pension and postretirement benefits other than pensions:
Net gain (loss) arising during the period plus amortization included in net income	(9		)	3		(11		)	8
Other	(1		)	—		1			—
Other comprehensive income (loss), net of tax	(10		)	3		(10		)	8
Comprehensive income	498			466		1,266			697
Less: Comprehensive income attributable to noncontrolling interests	28			25		84			75
Comprehensive income attributable to Edison International	$	470		$	441	$	1,182		$	622

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



Consolidated Balance Sheets	Edison International

(in millions, unaudited)	September 30, 2014		December 31, 2013
ASSETS
Cash and cash equivalents	$	142	$	146
Receivables, less allowances of $70 and $66 for uncollectible accounts at respective dates	1,218		838
Accrued unbilled revenue	998		596
Inventory	275		256
Derivative assets	103		122
Regulatory assets	1,170		538
Deferred income taxes	125		421
Other current assets	467		395
Total current assets	4,498		3,312
Nuclear decommissioning trusts	4,741		4,494
Other investments	204		207
Total investments	4,945		4,701
Utility property, plant and equipment, less accumulated depreciation and amortization of $7,997 and $7,493 at respective dates	31,919		30,379
Nonutility property, plant and equipment, less accumulated depreciation of $74 at both dates	102		76
Total property, plant and equipment	32,021		30,455
Derivative assets	245		251
Regulatory assets	7,329		7,241
Other long-term assets	437		686
Total long-term assets	8,011		8,178









Total assets	$	49,475	$	46,646

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



Consolidated Balance Sheets	Edison International

(in millions, except share amounts, unaudited)	September 30, 2014			December 31, 2013
LIABILITIES AND EQUITY
Short-term debt	$	1,349		$	209
Current portion of long-term debt	704			601
Accounts payable	1,455			1,407
Accrued taxes	191			358
Customer deposits	214			201
Derivative liabilities	154			152
Regulatory liabilities	794			767
Other current liabilities	988			1,186
Total current liabilities	5,849			4,881
Long-term debt	10,133			9,825
Deferred income taxes and credits	6,762			7,346
Derivative liabilities	947			1,042
Pensions and benefits	1,454			1,378
Asset retirement obligations	2,960			3,418
Regulatory liabilities	6,387			4,995
Other deferred credits and other long-term liabilities	2,225			2,070
Total deferred credits and other liabilities	20,735			20,249
Total liabilities	36,717			34,955
Commitments and contingencies (Note 12)
Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at respective dates)	2,445			2,403
Accumulated other comprehensive loss	(23		)	(13		)
Retained earnings	8,314			7,548
Total Edison International's common shareholders' equity	10,736			9,938
Preferred and preference stock of utility	2,022			1,753
Total noncontrolling interests	2,022			1,753
Total equity	12,758			11,691



Total liabilities and equity	$	49,475		$	46,646

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



Consolidated Statements of Cash Flows	Edison International

	Nine months ended September 30,
(in millions, unaudited)	2014			2013
Cash flows from operating activities:
Net income	$	1,276		$	689
Less: Income (loss) from discontinued operations	146			(1		)
Income from continuing operations	1,130			690
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,248			1,224
Regulatory impacts of net nuclear decommissioning trust earnings	100			82
Impairment and other charges	228			575
Deferred income taxes and investment tax credits	303			257
Other	70			70
EME settlement payments	(225		)	—
Changes in operating assets and liabilities:
Receivables	(369		)	(406		)
Inventory	(19		)	68
Accounts payable	211			155
Other current assets and liabilities	(497		)	(458		)
Derivative assets and liabilities, net	(68		)	207
Regulatory assets and liabilities, net	41			94
Other noncurrent assets and liabilities	(126		)	(488		)
Net cash provided by operating activities	2,027			2,070
Cash flows from financing activities:
Long-term debt issued, net of premium, discount, and issuance costs of $5 and $6 at respective dates	395			394
Long-term debt matured or repurchased	(405		)	(201		)
Bonds remarketed, net	—			195
Preference stock issued, net	269			387
Preference stock redeemed	—			(400		)
Short-term debt financing, net	1,138			1,352
Settlements of stock-based compensation, net	(57		)	(40		)
Dividends to noncontrolling interests	(88		)	(82		)
Dividends paid	(347		)	(330		)
Net cash provided by financing activities	905			1,275
Cash flows from investing activities:
Capital expenditures	(2,856		)	(2,761		)
Proceeds from sale of nuclear decommissioning trust investments	5,846			4,574
Purchases of nuclear decommissioning trust investments and other	(5,951		)	(4,674		)
Other	25			(44		)
Net cash used by investing activities	(2,936		)	(2,905		)
Net (decrease) increase in cash and cash equivalents	(4		)	440
Cash and cash equivalents at beginning of period	146			170
Cash and cash equivalents at end of period	$	142		$	610

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



Consolidated Statements of Income	Southern California Edison Company

	Three months ended September 30,						Nine months ended September 30,
(in millions, unaudited)	2014			2013			2014			2013
Operating revenue	$	4,338		$	3,957		$	10,276		$	9,631
Fuel	77			95			219			249
Purchased power	2,105			1,713			4,344			3,569
Operation and maintenance	776			875			2,187			2,540
Depreciation, decommissioning and amortization	423			392			1,248			1,223
Property and other taxes	76			78			232			229
Impairment and other charges	—			—			231			575
Total operating expenses	3,457			3,153			8,461			8,385
Operating income	881			804			1,815			1,246
Interest and other income	36			27			105			89
Interest expense	(133		)	(131		)	(402		)	(384		)
Other expenses	(29		)	(15		)	(52		)	(38		)
Income before income taxes	755			685			1,466			913
Income tax expense	224			183			310			196
Net income	531			502			1,156			717
Less: Preferred and preference stock dividend requirements	28			25			84			75
Net income available for common stock	$	503		$	477		$	1,072		$	642



Consolidated Statements of Comprehensive Income
	Three months ended September 30,					Nine months ended September 30,
(in millions, unaudited)	2014			2013		2014		2013
Net income	$	531		$	502	$	1,156	$	717
Other comprehensive income (loss), net of tax:
Pension and postretirement benefits other than pensions:
Net gain arising during the period plus amortization included in net income	1			2		2		1
Other	(1		)	—		1		—
Other comprehensive income, net of tax	—			2		3		1
Comprehensive income	$	531		$	504	$	1,159	$	718

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



Consolidated Balance Sheets	Southern California Edison Company



(in millions, unaudited)	September 30, 2014		December 31, 2013
ASSETS
Cash and cash equivalents	$	49	$	54
Receivables, less allowances of $70 and $66 for uncollectible accounts at respective dates	1,190		813
Accrued unbilled revenue	998		596
Inventory	265		256
Derivative assets	103		122
Regulatory assets	1,170		538
Deferred income taxes	—		303
Other current assets	489		393
Total current assets	4,264		3,075
Nuclear decommissioning trusts	4,741		4,494
Other investments	149		140
Total investments	4,890		4,634
Utility property, plant and equipment, less accumulated depreciation and amortization of $7,997 and $7,493 at respective dates	31,919		30,379
Nonutility property, plant and equipment, less accumulated depreciation of $73 and $70 at respective dates	69		72
Total property, plant and equipment	31,988		30,451
Derivative assets	245		251
Regulatory assets	7,329		7,241
Other long-term assets	387		398
Total long-term assets	7,961		7,890






Total assets	$	49,103	$	46,050

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



Consolidated Balance Sheets	Southern California Edison Company



(in millions, except share amounts, unaudited)	September 30, 2014			December 31, 2013
LIABILITIES AND EQUITY
Short-term debt	$	679		$	175
Current portion of long-term debt	500			600
Accounts payable	1,446			1,373
Customer deposits	214			201
Derivative liabilities	154			152
Regulatory liabilities	794			767
Deferred income taxes	126			39
Other current liabilities	1,117			1,091
Total current liabilities	5,030			4,398
Long-term debt	9,523			9,422
Deferred income taxes and credits	8,182			7,841
Derivative liabilities	947			1,042
Pensions and benefits	1,015			951
Asset retirement obligations	2,960			3,418
Regulatory liabilities	6,387			4,995
Other deferred credits and other long-term liabilities	1,984			1,845
Total deferred credits and other liabilities	21,475			20,092
Total liabilities	36,028			33,912
Commitments and contingencies (Note 12)
Common stock, no par value (560,000,000 shares authorized; 434,888,104 shares issued and outstanding at respective dates)	2,168			2,168
Additional paid-in capital	608			592
Accumulated other comprehensive loss	(8		)	(11		)
Retained earnings	8,237			7,594
Total common shareholder's equity	11,005			10,343
Preferred and preference stock	2,070			1,795
Total equity	13,075			12,138
Total liabilities and equity	$	49,103		$	46,050

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



Consolidated Statements of Cash Flows	Southern California Edison Company



	Nine months ended September 30,
(in millions, unaudited)	2014			2013
Cash flows from operating activities:
Net income	$	1,156		$	717
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization	1,248			1,223
Regulatory impacts of net nuclear decommissioning trust earnings	100			82
Impairment and other charges	231			575
Deferred income taxes and investment tax credits	324			197
Other	61			66
Changes in operating assets and liabilities:
Receivables	(377		)	(371		)
Inventory	(9		)	68
Accounts payable	234			174
Other current assets and liabilities	(577		)	(382		)
Derivative assets and liabilities, net	(68		)	207
Regulatory assets and liabilities, net	41			94
Other noncurrent assets and liabilities	149			(487		)
Net cash provided by operating activities	2,513			2,163
Cash flows from financing activities:
Long-term debt issued, net of premium, discount, and issuance costs of $2 and $6 at respective dates	398			394
Long-term debt matured or repurchased	(405		)	(201		)
Bonds remarketed, net	—			195
Preference stock issued, net	269			387
Preference stock redeemed	—			(400		)
Short-term debt financing, net	502			1,178
Settlements of stock-based compensation, net	(34		)	(36		)
Dividends paid	(340		)	(321		)
Net cash provided by financing activities	390			1,196
Cash flows from investing activities:
Capital expenditures	(2,827		)	(2,761		)
Proceeds from sale of nuclear decommissioning trust investments	5,846			4,574
Purchases of nuclear decommissioning trust investments and other	(5,951		)	(4,674		)
Other	24			(21		)
Net cash used by investing activities	(2,908		)	(2,882		)
Net (decrease) increase in cash and cash equivalents	(5		)	477
Cash and cash equivalents, beginning of period	54			45
Cash and cash equivalents, end of period	$	49		$	522

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

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 and delivering electricity to an approximately 50,000 square mile area of southern California. Edison International is also the parent company of 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 2013 Form 10-K. The same accounting policies are followed for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2014, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2013 Form 10-K.

In the opinion of management, all adjustments, consisting of recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three- and nine-month periods ended September 30, 2014 are not necessarily indicative of the operating results for the full year.

The December 31, 2013 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.

Revision to Consolidated Statements of Cash Flow

The consolidated statements of cash flows of Edison International and Southern California Edison Company were revised to correct an error in the amount of purchases of nuclear decommissioning trust investments and the amount of regulatory impacts of net nuclear decommissioning trust earnings. The revisions had no impact on the consolidated balance sheet, statements of income, comprehensive income, changes in equity or on the net change in cash and cash equivalents. Management believes the revisions do not have a material impact on the prior period financial statements. The following table presents the cash flow statement effects related to the revision for the nine months ended September 30, 2013 and the year ended December 31, 2013:



	Edison International									Southern California Edison
(in millions)	As Reported			Adjustment			As Revised			As Reported			Adjustment			As Revised
Nine months ended September 30, 2013
Cash flows from operating activities:
Adjustments to reconcile to net cash provided by operating activities:
Regulatory impacts of net nuclear decommissioning trust earnings	$	265		$	(183	)	$	82		$	265		$	(183	)	$	82
Total cash provided by operating activities	2,253			(183		)	2,070			2,346			(183		)	2,163

Cash flows from investing activities:
Purchases of nuclear decommissioning trust investments	(4,857		)	183			(4,674		)	(4,857		)	183			(4,674		)
Total cash used by investing activities	(3,088		)	183			(2,905		)	(3,065		)	183			(2,882		)



	Edison International									Southern California Edison
(in millions)	As Reported			Adjustment			As Revised			As Reported			Adjustment			As Revised
Year ended December 31, 2013
Cash flows from operating activities:
Adjustments to reconcile to net cash provided by operating activities:
Regulatory impacts of net nuclear decommissioning trust earnings	$	312		$	(236	)	$	76		$	312		$	(236	)	$	76
Total cash provided by operating activities	3,203			(236		)	2,967			3,284			(236		)	3,048

Cash flows from investing activities:
Purchases of nuclear decommissioning trust investments	(5,951		)	236			(5,715		)	(5,951		)	236			(5,715		)
Total cash used by investing activities	(3,808		)	236			(3,572		)	(3,783		)	236			(3,547		)

For the three months ended March 31, 2014 and the six months ended June 30, 2014, the correction also increases net cash provided by operating activities by $67 million and $5 million , respectively, and increases cash flows used by investing activities by the same amount. There were also errors identified which had an inconsequential impact on the three months ended March 31, 2013 and the six months ended June 30, 2013 as well as the annual periods of 2012 and 2011. Since these errors are inconsequential, management has concluded revision of these periods is not necessary.

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, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Money market funds	$	40	$	68	$	8	$	8

Cash is temporarily invested until required for check clearing. 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, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Book balances reclassified to accounts payable	$	191	$	168	$	190	$	163

Inventory

Inventory is primarily composed of materials, supplies and spare parts, and stated at the lower of cost or market, cost being determined by the average cost method.

Earnings Per Share

Edison International computes earnings per common 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 performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares once the awards are vested. EPS attributable to Edison International common shareholders was computed as follows:



	Three months ended September 30,				Nine months ended September 30,
(in millions, except per-share amounts)	2014		2013		2014		2013
Basic earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	496	$	463	$	1,046	$	615
Weighted average common shares outstanding	326		326		326		326
Basic earnings per share – continuing operations	$	1.52	$	1.42	$	3.21	$	1.88
Diluted earnings per share – continuing operations:
Income from continuing operations available to common shareholders	$	496	$	463	$	1,046	$	615
Income impact of assumed conversions	—		—		1		1
Income from continuing operations available to common shareholders and assumed conversions	$	496	$	463	$	1,047	$	616
Weighted average common shares outstanding	326		326		326		326
Incremental shares from assumed conversions	3		2		3		3
Adjusted weighted average shares – diluted	329		328		329		329
Diluted earnings per share – continuing operations	$	1.51	$	1.41	$	3.18	$	1.87

In addition to the participating securities discussed above, Edison International also may award stock options which are payable in common shares and are included in the diluted earnings per share calculation. Stock option awards to purchase 38,800 and 4,109,363 shares of common stock for the three months ended September 30, 2014 and 2013 , and 62,885 and 4,109,363 shares for the nine months ended September 30, 2014 and 2013 , 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.

Asset Retirement Obligation

The following table summarizes the changes in SCE's ARO liability for the nine month period ended September 30, 2014 and the twelve month period ended December 31, 2013, including San Onofre and Palo Verde:



(in millions)	September 30, 2014			December 31, 2013
Beginning balance	$	3,418		$	2,782
Accretion ¹	150			182
Revisions	(604		)	455
Liabilities settled	(4		)	(1		)
Ending balance	$	2,960		$	3,418


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

During the second quarter of 2014, SCE updated its decommissioning cost estimate based on a site specific assessment. The decommissioning cost estimate in 2014 dollars is $4.4 billion (SCE share – $3.3 billion ) and includes costs from June 7, 2013 through the respective completion dates to decommission San Onofre Units 2 and 3. The decommissioning cost estimate is subject to a number of estimates including the cost of burial of nuclear waste, cost of removal of property, site remediation costs as well as a number of other assumptions and estimates, including when the federal government may remove spent fuel canisters from the San Onofre site, as to which there can be no assurance. The cost estimate is subject to change and such changes may be material. SCE's share of the present value of decommissioning costs after escalation and using current discounts rates was $3.0 billion at September 30, 2014.

The total ARO liability related to San Onofre Units 2 and 3 at September 30, 2014 was $2.2 billion compared to $2.7 billion at December 31, 2013. The ARO liability is lower than the present value of the decommissioning costs set forth above due to different discount rates and expected time period of expenditures. The ARO liability at September 30, 2014 was based on a discount rate of 6.30% established when the ARO liability was originally recorded in 2003. The ARO liability for San Onofre Units 2 and 3 is based on expenditures beginning in 2015 through the respective completion dates. Expenditures from June 7, 2013 through September 30, 2014 are currently recorded as operation and maintenance costs and are treated as recoverable through GRC revenues, with the 2014 recorded costs being subject to customary prudency review (See Note 9). SCE has filed a request with the CPUC to authorize early release of Nuclear Decommissioning Trust funds to recover SCE's share of costs from June 7, 2013 through the end of 2014. As discussed in Note 9, to the extent that costs are recovered from SCE's Nuclear Decommissioning Trust as decommissioning costs, SCE intends to refund such amounts to customers as provided in the San Onofre OII Amended Settlement Agreement (as defined in Note 9).

The change in estimate of the ARO liability related to San Onofre Units 2 and 3 ( $604 million ) was based on the updated decommissioning cost estimate for the retirement of those Units. The work plan developed for the revised estimate accelerated decommissioning activities beginning in 2013 from the prior assumption of 2022. In addition, certain activities that were previously forecasted to be completed at the end of the decommissioning period were accelerated over the next ten years. Although the changes in the decommissioning cost estimate for these activities in current dollars did not change significantly, the changes in timing, as well as revised escalation rates, reduced the present value of future decommissioning costs (using the 6.30% discount rate).

New Accounting Guidance

Accounting Guidance Adopted in 2014

In July 2013, the FASB issued an accounting standards update that requires 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. Edison International and SCE adopted this guidance effective January 1, 2014 and it did not have a material impact on the consolidated financial statements.

Accounting Guidance Not Yet Adopted

On May 28, 2014, the FASB issued an accounting standards update on revenue recognition including enhanced disclosures. Under the new standard, revenue is recognized when (or as) a good or service is transferred to the customer and the customer obtains control of the good or service. Edison International and SCE are currently evaluating this new guidance which is effective January 1, 2017 and cannot determine the impact of this standard at this time.

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, 2014 :



	Equity Attributable to Edison International											Noncontrolling Interests
(in millions, except per-share amounts)	Common Stock		Accumulated Other Comprehensive Loss			Retained Earnings			Subtotal			Preferred and Preference Stock			Total Equity
Balance at December 31, 2013	$	2,403	$	(13	)	$	7,548		$	9,938		$	1,753		$	11,691
Net income	—		—			1,192			1,192			84			1,276
Other comprehensive loss	—		(10		)	—			(10		)	—			(10		)
Common stock dividends declared ($1.065 per share)	—		—			(347		)	(347		)	—			(347		)
Dividends, distributions to noncontrolling interests	—		—			—			—			(84		)	(84		)
Stock-based compensation	22		—			(79		)	(57		)	—			(57		)
Noncash stock-based compensation	20		—			—			20			—			20
Issuance of preference stock	—		—			—			—			269			269
Balance at September 30, 2014	$	2,445	$	(23	)	$	8,314		$	10,736		$	2,022		$	12,758

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, except per-share amounts)	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	5		—			(45		)	(40		)	—			(40		)
Noncash stock-based compensation	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

The following table provides SCE's changes in equity for the nine months ended September 30, 2014 :



	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, 2013	$	2,168	$	592		$	(11	)	$	7,594		$	1,795	$	12,138
Net income	—		—			—			1,156			—		1,156
Other comprehensive income	—		—			3			—			—		3
Dividends declared on common stock	—		—			—			(378		)	—		(378		)
Dividends on preferred and preference stock	—		—			—			(84		)	—		(84		)
Stock-based compensation	—		13			—			(47		)	—		(34		)
Noncash stock-based compensation	—		9			—			(4		)	—		5
Issuance of preference stock	—		(6		)	—			—			275		269
Balance at September 30, 2014	$	2,168	$	608		$	(8	)	$	8,237		$	2,070	$	13,075

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 on preferred and preference stock	—		—			—			(75		)	—			(75		)
Stock-based compensation	—		3			—			(39		)	—			(36		)
Noncash stock-based compensation	—		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

Note 3. Variable Interest Entities

A VIE is defined as a legal entity that meets one of two conditions: (1) the equity owners do not have sufficient equity at risk, or (2) the holders of the equity investment at risk, as a group, lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that most significantly impact the economic performance of such VIEs. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has power purchase agreements ("PPAs") that are classified as variable interests in 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. Since payments for capacity are the primary source of income, the most significant economic activity for these VIEs is the operation and maintenance of the power plants.

As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. Under these contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 12 of the 2013 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 from these VIE projects was 5,341 MW and 5,290 MW at September 30, 2014 and 2013 , respectively, and the amounts that SCE paid to these projects were $319 million and $330 million for the three months ended September 30, 2014 and 2013 , respectively, and $526 million and $527 million for the nine months ended September 30, 2014 and 2013 , respectively. These amounts are recoverable in customer rates, subject to reasonableness review. As of September 30, 2014 , SCE has additional VIE contracts with future aggregate contracted capacity of 251 MW to commence deliveries in 2016.

Unconsolidated Trusts of SCE

SCE Trust I, Trust II and Trust III were formed in 2012, 2013 and 2014, respectively, for the exclusive purpose of issuing the 5.625% , 5.10% and 5.75% 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. SCE Trust I, Trust II and Trust III issued $475 million , $400 million and $275 million , respectively, (cumulative, liquidation amount of $25 per share) to the public and $10,000 of common stock each to SCE. The trusts invested the proceeds of these trust securities in Series F, Series G and Series H Preference Stock issued by SCE in the principal amounts of $475 million , $400 million and $275 million (cumulative, $2,500 per share liquidation value), respectively, which have substantially the same payment terms as the respective trust securities.

The Series F, Series G and Series H Preference Stock and the corresponding trust securities do not have a maturity date. Upon any redemption of any shares of the Series F, Series G or Series H 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, Series G or Series H Preference Stock. The applicable trust will use any dividends it receives on the Series F, Series G or Series H Preference Stock to make its corresponding distributions on the applicable series of trust securities. If SCE does not make a dividend payment to any of these trusts, 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, Series G and Series H Preference Stock.

The Trust I and Trust II balance sheets as of September 30, 2014 and December 31, 2013 , consisted of investments of $475 million and $400 million in the Series F and Series G Preference Stock, respectively, $ 475 million and $400 million of trust securities, respectively, and $10,000 each of common stock. The Trust III balance sheet as of September 30, 2014 consisted of investments of $275 million in the Series H Preference Stock, $275 million of trust securities, and $10,000 of common stock.

The following table provides a summary of the trusts' income statements:



	Three months ended September 30,						Nine months ended September 30,
(in millions)	Trust I		Trust II		Trust III		Trust I		Trust II		Trust III
2014
Dividend income	$	7	$	5	$	4	$	20	$	15	$	9
Dividend distributions	7		5		4		20		15		9
2013
Dividend income	$	7	$	5	*		$	20	$	14	*
Dividend distributions	7		5		*		20		14		*


^*	Not applicable

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, 2014 and December 31, 2013 , 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.

Level 1 – The fair value of Edison International's 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, U.S. treasury securities, mutual funds and money market funds.

Level 2 – SCE's Level 2 assets and liabilities include long-term debt and fixed income securities primarily consisting of U.S. government and agency bonds, municipal bonds and corporate bonds 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.

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. Edison International Parent and Other does not have any Level 3 assets and liabilities.

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.

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, 2014
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral ¹			Total
Assets at fair value
Derivative contracts	$	—	$	5	$	343		$	—		$	348
Other	35		—		—			—			35
Nuclear decommissioning trusts:
Stocks ²	1,970		—		—			—			1,970
Fixed Income ³	744		1,336		—			—			2,080
Short-term investments, primarily cash equivalents	665		21		—			—			686
Subtotal of nuclear decommissioning trusts ⁴	3,379		1,357		—			—			4,736
Total assets	3,414		1,362		343			—			5,119
Liabilities at fair value
Derivative contracts	—		6		1,101			(6		)	1,101
Total liabilities	—		6		1,101			(6		)	1,101
Net assets (liabilities)	$	3,414	$	1,356	$	(758	)	$	6		$	4,018



	December 31, 2013
(in millions)	Level 1		Level 2		Level 3			Netting and Collateral ¹			Total
Assets at fair value
Derivative contracts	$	—	$	11	$	372		$	(10	)	$	373
Other	39		—		—			—			39
Nuclear decommissioning trusts:
Stocks ²	2,208		—		—			—			2,208
Fixed Income ³	841		1,102		—			—			1,943
Short-term investments, primarily cash equivalents	331		—		—			—			331
Subtotal of nuclear decommissioning trusts ⁴	3,380		1,102		—			—			4,482
Total assets	3,419		1,113		372			(10		)	4,894
Liabilities at fair value
Derivative contracts	—		37		1,177			(20		)	1,194
Total liabilities	—		37		1,177			(20		)	1,194
Net assets (liabilities)	$	3,419	$	1,076	$	(805	)	$	10		$	3,700


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 70% of SCE's equity investments were located in the United States at September 30, 2014 and December 31, 2013 , respectively.


³	At September 30, 2014 and December 31, 2013 , SCE's corporate bonds were diversified and included collateralized mortgage obligations and other asset backed securities of $58 million and $47 million , respectively.


⁴	Excludes net receivables of $5 million and net receivables of $12 million at September 30, 2014 and December 31, 2013 , respectively, of interest and dividend receivables as well as receivables and payables related to SCE's pending securities sales and purchases.

Edison International

Edison International Parent and Other assets measured at fair value consisted of money market funds of $40 million and $ 68 million at September 30, 2014 and December 31, 2013 , respectively, classified as Level 1.

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)	2014			2013			2014			2013
Fair value of net liabilities at beginning of period	$	(878	)	$	(967	)	$	(805	)	$	(791	)
Total realized/unrealized gains (losses):
Included in regulatory assets and liabilities ¹	120			(50		)	43			(205		)
Purchases	7			19			22			56
Settlements	(7		)	(33		)	(18		)	(91		)
Fair value of net liabilities at end of period	$	(758	)	$	(1,031	)	$	(758	)	$	(1,031	)
Change during the period in unrealized gains and losses related to assets and liabilities held at the end of the period	$	71		$	(65	)	$	(12	)	$	(198	)


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 2014 and 2013 .

Valuation Techniques Used to Determine Fair Value

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 significant Level 3 assets and liabilities:



	Fair Value (in millions)					Significant	Range
	Assets		Liabilities		Valuation Technique(s)	Unobservable Input	(Weighted Average)
Congestion revenue rights
September 30, 2014	$	339	$	—	Market simulation model	Load forecast	7,630 MW - 25,431 MW
						Power prices ¹	$1.65 - $109.95
						Gas prices ²	$3.65 - $6.53
December 31, 2013	366		—		Market simulation model	Load forecast	7,603 MW - 24,896 MW
						Power prices ¹	$(9.86) - $108.56
						Gas prices ²	$3.50 - $7.10
Tolling
September 30, 2014	—		1,095		Option model	Volatility of gas prices	12% - 40% (19%)
						Volatility of power prices	26% - 45% (31%)
						Power prices	$36.80 - $65.60 ($48.90)
December 31, 2013	5		1,175		Option model	Volatility of gas prices	16% - 35% (21%)
						Volatility of power prices	25% - 45% (30%)
						Power prices	$38.00 - $63.90 ($47.40)


¹	Prices are in dollars per megawattt-hour.


²	Prices are in dollars per million British thermal units.

Level 3 Fair Value Sensitivity

Congestion Revenue Rights

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

Tolling Arrangements

The fair values of SCE's 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 option model for tolling arrangements reflects plant specific information such as operating and start-up costs.

For tolling arrangements 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 tolling arrangements tends to increase. The valuation of tolling arrangements is also impacted by the correlation between gas and power prices. As the correlation increases, the fair value of tolling arrangements tends to decline.

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 Debt Recorded at Carrying Value

The carrying value and fair value of Edison International's and SCE's long-term debt (including current portion of long-term debt) are as follows:



	September 30, 2014				December 31, 2013
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
SCE	$	10,023	$	11,295	$	10,022	$	10,656
Edison International	10,837		12,134		10,426		11,084

The fair value of Edison International's and SCE's long-term debt (including current portion of 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's and SCE's trade receivables and payables, other investments, and short-term debt approximates fair value.

Note 5. Debt and Credit Agreements

Credit Agreements and Short-Term Debt

During the first quarter of 2014, SCE issued $300 million of floating rate first and refunding mortgage bonds due in January 2015 . The proceeds from these bonds were used for working capital to fund the ERRA balancing account undercollections.

In July 2014, SCE and Edison International Parent extended the maturity dates of their respective $2.75 billion and $1.25 billion multi-year revolving credit facilities by one year to July 2019. The credit facility for SCE is generally used to support commercial paper and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working capital requirements to support operations and capital expenditures. Edison International Parent's credit facility is used for general corporate purposes.

At September 30, 2014 , SCE's outstanding commercial paper was $379 million at a weighted-average interest rate of 0.22% . At September 30, 2014 , letters of credit issued under SCE's credit facility aggregated $226 million and are scheduled to expire in twelve months or less. At December 31, 2013 , the outstanding commercial paper was $ 175 million at a weighted-average interest rate of 0.24% .

At September 30, 2014 , Edison International Parent's outstanding commercial paper was $670 million at a weighted-average interest rate of 0.27% . At December 31, 2013 , the outstanding commercial paper was $ 34 million at a weighted-average interest rate of 0.55% .

Long-Term Debt

During the second quarter of 2014, SCE issued $400 million of 1.125% first and refunding mortgage bonds due in May 2017. The proceeds from these bonds were used to repay commercial paper borrowings and to fund SCE's capital program.

In connection with a settlement agreement between Edison International, EME and the Consenting Noteholders, in September 2014, Edison International Parent issued non-interest bearing promissory notes of $204 million due in September 2015 and $214 million due in September 2016 . See Note 16 for further details.

Note 6. Derivative Instruments

Derivative financial instruments are used to manage exposure to commodity price risk. These risks are managed in part by entering into forward commodity transactions, including options, swaps and futures. To mitigate credit risk from counterparties in the event of nonperformance, master netting agreements are used whenever possible and counterparties may be required to pledge collateral depending on the creditworthiness of each counterparty and the risk associated with the transaction.

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 represent 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 allow counterparties subject to the agreement to setoff 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 credit worthiness of each counterparty and the risk associated with the transaction.

Certain power contracts contain a provision that requires SCE to maintain an investment grade 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 $38 million and $49 million as of September 30, 2014 and December 31, 2013 , 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, 2014 , SCE would be required to post collateral in the amount of $26 million .

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, 2014
	Derivative Assets						Derivative Liabilities
(in millions)	Short-Term		Long-Term		Subtotal		Short-Term			Long-Term			Subtotal			Net Liability
Commodity derivative contracts
Gross amounts recognized	$	103	$	245	$	348	$	159		$	948		$	1,107		$	759
Cash collateral posted ¹	—		—		—		(5		)	(1		)	(6		)	(6		)
Net amounts presented in the consolidated balance sheets	$	103	$	245	$	348	$	154		$	947		$	1,101		$	753



	December 31, 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	$	141		$	251	$	392		$	178		$	1,045		$	1,223		$	831
Gross amounts offset in the consolidated balance sheets	(19		)	—		(19		)	(19		)	—			(19		)	—
Cash collateral posted ¹	—			—		—			(7		)	(3		)	(10		)	(10		)
Net amounts presented in the consolidated balance sheets	$	122		$	251	$	373		$	152		$	1,042		$	1,194		$	821


¹	In addition, at September 30, 2014 and December 31, 2013 , SCE had posted $6 million and $19 million , respectively, of collateral that is not offset against 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)	2014			2013			2014			2013
Realized losses	$	(18	)	$	(15	)	$	(59	)	$	(38	)
Unrealized gains (losses)	138			(41		)	80			(159		)

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, 2014	December 31, 2013
Electricity options, swaps and forwards	GWh	2,519	6,274
Natural gas options, swaps and forwards	Bcf	7	12
Congestion revenue rights	GWh	120,075	149,234
Tolling arrangements	GWh	82,333	87,991

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)	2014			2013			2014			2013
Edison International:
Income from continuing operations before income taxes	$	744		$	665		$	1,414		$	863
Provision for income tax at federal statutory rate of 35%	260			233			495			302
Increase (decrease) in income tax from:
State tax, net of federal benefit	28			22			34			5
Property-related	(73		)	(57		)	(179		)	(121		)
Change related to uncertain tax positions	10			(5		)	(4		)	13
San Onofre OII settlement	—			—			(40		)	—
Other	(5		)	(16		)	(22		)	(26		)
Total income tax expense from continuing operations	$	220		$	177		$	284		$	173
Effective tax rate	29.6		%	26.6		%	20.1		%	20.0		%
SCE:
Income from continuing operations before income taxes	$	755		$	685		$	1,466		$	913
Provision for income tax at federal statutory rate of 35%	264			240			513			319
Increase (decrease) in income tax from:
State tax, net of federal benefit	31			21			42			12
Property-related	(73		)	(57		)	(179		)	(121		)
Change related to uncertain tax positions	9			(6		)	(1		)	11
San Onofre OII settlement	—			—			(40		)	—
Other	(7		)	(15		)	(25		)	(25		)
Total income tax expense from continuing operations	$	224		$	183		$	310		$	196
Effective tax rate	29.7		%	26.7		%	21.1		%	21.5		%

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. During the first quarter of 2014, SCE recorded flow through tax benefits related to repair deductions and other tax items under the San Onofre OII settlement. The tax benefits were offset by estimated refunds to customers included as part of the pre-tax charge of $231 million . See Note 9 for further details.

Tax Disputes

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 liability of approximately $212 million , including interest and penalties through September 30, 2014 .


•	A proposed adjustment to disallow a component of SCE's percentage repair allowance deduction, which if sustained, would result in a federal tax liability of approximately $102 million , including interest through September 30, 2014 .

Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011. Edison International anticipates that the IRS will issue a deficiency notice for the tax, interest and possibly penalties at the conclusion of the IRS appeals process. After the receipt of such deficiency notice, Edison International will have 90 days to file a petition in United States Tax Court. If a petition is not timely filed, Edison International anticipates after the expiration of the 90-day period, the IRS will assess the underpayment of tax, interest and penalties, if any, and demand payment. Although Edison International disagrees with the proposed adjustments, it has made a $189 million deposit during the second quarter of 2014 to stop the accrual of interest.

Edison International has tentatively reached an agreement with the IRS regarding SCE's percentage repair allowance deduction, which if finalized, would result in a federal tax liability of approximately $14 million , including interest through September 30, 2014.

It is reasonably possible that Edison International will complete the 2003 – 2006 federal income tax audit cycle during the next twelve months which would effectively settle open tax positions. Edison International estimates tax benefits of approximately $50 million , including interest, may be recognized in income depending on the final outcome of the IRS audit.

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 percentage repair allowance deduction (similar to the 2003 – 2006 tax years). The proposed adjustment to disallow a component of SCE's percentage repair allowance deduction, if sustained, would result in a federal tax liability of approximately $76 million , including interest through September 30, 2014 . Edison International has tentatively reached an agreement with the IRS regarding SCE’s percentage repair allowance deduction, which if finalized, would result in a federal tax liability of approximately $16 million , including interest through September 30, 2014.

During the second quarter of 2014, SCE revised its liability for uncertain tax positions related to percentage repair allowance deduction for 2003-2010 which resulted in income tax benefits of $29 million .

Tax Years 2010 – 2012

A Revenue Agent Report from the IRS is expected to be received from the examination phase of tax years 2010 through 2012 within the next six months. After receipt of the Revenue Agent Report, SCE expects to update its assessment of uncertain tax positions.

Note 8. Compensation and Benefit Plans

Pension Plans

Edison International made contributions of $155 million during the nine months ended September 30, 2014 , which includes contributions of $131 million by SCE. Edison International expects to make contributions of $7 million during the remainder of 2014, which includes $2 million from SCE. SCE's future contributions are expected to decline due to the passage of the Highway Transportation Funding Act of 2014 although such decreases may be offset by higher funding levels in future years. Annual contributions made by SCE 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.

Pension expense components for continuing operations are:



	Three months ended September 30,						Nine months ended September 30,
(in millions)	2014			2013			2014			2013
Edison International:
Service cost	$	30		$	38		$	89		$	114
Interest cost	48			42			141			126
Expected return on plan assets	(61		)	(58		)	(178		)	(172		)
Settlement costs ¹	35			24			35			73
Amortization of prior service cost	1			1			4			3
Amortization of net loss ²	1			15			3			45
Expense under accounting standards	$	54		$	62		$	94		$	189
Regulatory adjustment (deferred)	(2		)	(7		)	59			(21		)
Total expense recognized	$	52		$	55		$	153		$	168
SCE:
Service cost	$	29		$	37		$	87		$	111
Interest cost	44			41			132			123
Expected return on plan assets	(56		)	(57		)	(168		)	(171		)
Settlement costs ¹	33			24			33			72
Amortization of prior service cost	1			1			3			3
Amortization of net loss ²	—			14			1			42
Expense under accounting standards	$	51		$	60		$	88		$	180
Regulatory adjustment (deferred)	(2		)	(7		)	59			(21		)
Total expense recognized	$	49		$	53		$	147		$	159

Relates to lump-sum payments made to employees who retired from the SCE Retirement Plan (primarily due to workforce reductions described below). Includes the amount of net loss reclassified from other comprehensive loss. The amount reclassified for Edison International was $2 million for the three and nine months ended September 30, 2014 and zero and $2 million for the three and nine months ended September 30, 2013, respectively.

Includes the amount of net loss reclassified from other comprehensive loss. The amount reclassified for Edison International and SCE was $2 million and $1 million , respectively, for the three months ended September 30, 2014 , and $5 million and $3 million , respectively, for the nine months ended September 30, 2014 . The amount reclassified for Edison International and SCE was $4 million and $3 million , respectively, for the three months ended September 30, 2013 , and $11 million and $8 million , respectively, for the nine months ended September 30, 2013 .

Under generally accepted accounting principles (“GAAP”), a settlement is recorded when lump-sum payments exceed estimated annual service and interest costs. As of August 31, 2014, lump-sum payments to employees retiring in 2014 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 August 31, 2014 resulted in total actuarial losses of $158 million , including $146 million for SCE. The actuarial losses are primarily due to a decrease in the discount rate (from 4.75% at December 31, 2013 to 4.00% as of August 31, 2014) due to lower interest rates, partially offset by 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.

The projected benefit obligations exceeded the fair value of the SCE Retirement Plan assets by $559 million , including $518 million for SCE, at August 31, 2014 compared to $478 million , including $449 million for SCE, at December 31, 2013.

Postretirement Benefits Other Than Pensions

Edison International made contributions of $11 million during the nine months ended September 30, 2014 and expects to make contributions of $4 million during the remainder of 2014 , substantially 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. Under the terms of the Edison International Health and Welfare Plan ("PBOP Plan") each participating employer (Edison International or its participating subsidiaries) is responsible for the costs and expenses of all PBOP benefits with respect to its employees and former employees. A participating employer may terminate the PBOP benefits with respect to its employees and former employees, as may SCE (as Plan sponsor), and, accordingly, the participants' PBOP benefits are not vested benefits.

PBOP expense components for continuing operations are:



	Three months ended September 30,						Nine months ended September 30,
(in millions)	2014			2013			2014			2013
Edison International:
Service cost	$	10		$	14		$	32		$	42
Interest cost	28			26			82			78
Expected return on plan assets	(28		)	(30		)	(84		)	(90		)
Special termination benefits ¹	—			—			—			10
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	—			7			—			21
Total expense	$	1		$	8		$	3		$	34
SCE:
Service cost	$	10		$	14		$	32		$	41
Interest cost	27			26			81			78
Expected return on plan assets	(28		)	(30		)	(84		)	(90		)
Special termination benefits ¹	—			—			—			10
Amortization of prior service credit	(9		)	(9		)	(27		)	(27		)
Amortization of net loss	—			7			—			21
Total expense	$	—		$	8		$	2		$	33


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

Workforce Reductions

In 2012, SCE commenced multiple efforts to reduce its workforce 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, which resulted in additional workforce reductions. See Note 9 for further information. During the second quarter of 2014, SCE increased the estimated impact for workforce reductions related to transferring certain information technology activities to third parties. Through September 30, 2014 , SCE's share of estimated cash severance for these efforts totaled $ 222 million . The following table provides a summary of changes in the accrued severance liability associated with these reductions:



(in millions)
Balance at January 1, 2014	$	54
Additions	9
Payments	(17		)
Other	(1		)
Balance at September 30, 2014	$	45

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. San Onofre Issues

Replacement steam generators were installed at San Onofre in 2010 and 2011. On January 31, 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. Unit 2 was off-line for a planned outage when areas of unexpected tube to support structure wear were found. Later, evidence of tube to tube wear in Unit 2 was also discovered. On June 6, 2013, SCE decided to permanently retire Units 2 and 3.

CPUC Proceedings and Proposed Settlement

In October 2012, the CPUC issued an Order Instituting Investigation ("OII") that consolidated all San Onofre issues in related CPUC 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, and operation and maintenance costs.

On September 23, 2014, SCE entered into an Amended and Restated Settlement Agreement (the "San Onofre OII Amended Settlement Agreement") with The Utility Reform Network ("TURN"), the CPUC's Office of Ratepayer Advocates ("ORA"), SDG&E, the Coalition of California Utility Employees ("CUE"), and Friends of the Earth ("FOE") (together, the "Settling Parties"). If implemented, the San Onofre OII Amended Settlement Agreement will constitute a complete and final resolution of the CPUC's OII and related proceedings regarding the Steam Generator Replacement Project ("SGRP") at San Onofre and the related outage and subsequent shutdown of San Onofre. The Settling Parties agreed to amend the Settlement Agreement that was originally entered into in March 2014 in response to an Assigned Commissioner's and Administrative Judges’ Ruling that was issued on September 5, 2014. The San Onofre OII Amended Settlement Agreement does not affect proceedings before the NRC or proceedings related to recoveries from third parties described below, but does describe how shareholders and customers will share any potential recoveries. Implementation of the San Onofre OII Amended Settlement Agreement is subject to the approval of the CPUC. The San Onofre OII Amended Settlement Agreement is subject to termination by any of the Settling Parties if the CPUC has not approved it by December 23, 2014. On October 9, 2014, the Administrative Law Judges in the OII issued a Proposed Decision approving the San Onofre OII Amended Settlement Agreement. Under applicable rules, the CPUC cannot render a final decision for at least thirty days following the date of the Proposed Decision, but there can be no certainty of when or what the CPUC will actually decide. The parties to the San Onofre OII Amended Settlement Agreement have agreed to exercise their best efforts to obtain CPUC approval.

Disallowances, Refunds and Rate Recoveries

If the San Onofre OII Amended Settlement Agreement is approved, SCE will not be allowed to recover in rates its capitalized costs for the SGRP as of February 1, 2012 or a return on such investment after such date. As of February 1, 2012, SCE's net book value in the SGRP was approximately $597 million . Additionally, SCE will not be allowed to recover in rates approximately $99 million of incremental inspection and repair costs incurred for the replacement steam generators ("RSGs") in 2012 that exceeded CPUC-authorized operations and maintenance expense. These costs, net of invoices paid by the supplier of the RSGs, were previously expensed in SCE's 2012 financial results, although they remain subject to recovery from the RSG's supplier. Neither will SCE be allowed to recover in rates provisionally authorized operations and maintenance expense in 2013 that exceeds amounts in recorded operations and maintenance expense (including severance and incremental repair and inspection costs); such excess had not been recognized in 2013 earnings. Subject to the foregoing, SCE will be authorized to recover in rates its remaining investment in San Onofre, including base plant, materials and supplies, nuclear fuel inventory and contracts and construction work in progress ("CWIP"), generally over a ten -year period commencing February 1, 2012. Additionally, SCE will be authorized to recover in rates its provisionally authorized operations and maintenance expenses for 2012, recorded costs for the 2012 refueling outage of Unit 2, recorded operations and maintenance expenses for 2013, and recorded operations and maintenance expenses for 2014 subject to customary prudency review. Finally, SCE will also be authorized to recover in rates through its fuel and purchased power balancing account ("ERRA") all costs incurred to purchase electric power in the market related to the outage and shutdown of San Onofre, and to recover by December 31, 2015 any San Onofre-related ERRA undercollections. Estimated market power costs through June 6, 2013 (the date of San Onofre's retirement) were approximately $680 million using the methodology followed in the OII. To the extent that amounts otherwise recoverable in rates under the San Onofre OII Amended Settlement Agreement are recovered from SCE's Decommissioning Trust as a decommissioning cost, the amounts otherwise recoverable in rates will be reduced with no impact on earnings.

The portion of SCE's San Onofre investment in base plant, CWIP and materials and supplies, which SCE is entitled to recover from February 1, 2012, will earn a return equal to the weighted average of SCE's authorized return on debt and 50% of its authorized return on preferred equity, pro-rated to the percentage of the investment that equals SCE's percentage of debt and preferred equity in its authorized capital structure. SCE will not earn a return on common equity on its amortizable San Onofre investment. Accordingly, SCE will be allowed to earn a rate of return of 2.95% in 2012, 2.62% for the period 2013 –2014 and a rate that will float during the amortization period thereafter with changes in SCE's authorized return on debt and preferred equity. SCE's investment in nuclear fuel will earn a return equal to commercial paper rates that SCE pays from time to time.

A 5% incentive is provided for SCE to realize savings for ratepayers by selling materials and supplies and nuclear fuel, as well as reducing its nuclear fuel investment by contract cancellations. This incentive allows SCE to retain 5% of sales proceeds and to recover 5% of the excess of cancelled contract obligations over cancellation costs. The balance of sale proceeds and cancellation benefits is credited to ratepayers.

Accounting and Financial Impact

Due to the decision to early retire San Onofre Units 2 and 3, GAAP required reclassification of the amounts recorded in property, plant and equipment and related tangible operating assets to a regulatory asset to the extent that management concluded it was 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. In accordance with these requirements and as a result of its decision to retire San Onofre Units 2 and 3, SCE reclassified $1,521 million of its total investment in San Onofre at May 31, 2013 to a regulatory asset ("San Onofre Regulatory Asset") and recorded an impairment charge of $575 million ( $365 million after-tax) in the second quarter of 2013. As of December 31, 2013, SCE had recorded a net regulatory asset of approximately $1.3 billion , comprised of $1.56 billion of property, plant and equipment, less $266 million for estimated refunds of authorized revenue recorded in excess of SCE's costs of service.

As a result of the execution of the March 2014 San Onofre OII Settlement Agreement by the Settling Parties, SCE concluded that the outcome of the OII that is more likely than any other outcome is approval and implementation of that Agreement, although approval by the CPUC remains uncertain. As a result, in the first quarter of 2014, SCE recorded an additional pre-tax charge of approximately $231 million (approximately $96 million after-tax). Including the amounts recorded during the first quarter of 2014 and the amounts previously recorded in 2013, the total impact of the San Onofre OII settlement is estimated at $806 million (approximately $461 million after-tax). The total pre-tax charge is due to:


•	the disallowance of the SGRP investment ( $542 million as of May 31, 2013);


•	refund of revenue related to the SGRP previously recognized of $159 million ; and


•	implementation of the other terms of the San Onofre OII Settlement Agreement, including a refund of flow through tax benefits of $71 million and a refund of the authorized return in excess of the return allowed for non-SGRP investments. The refund was offset by recognition of tax benefits in an equal amount.

At September 30, 2014, the San Onofre Regulatory Asset was $1.39 billion and the San Onofre regulatory liability for refunds of revenue was approximately $677 million . Such amounts do not reflect any recoveries from third parties by SCE.

Under the San Onofre OII Amended Settlement Agreement, the unamortized portion of SCE's investment other than nuclear fuel may, at SCE's option, be excluded from SCE's capital structure for purposes of determining regulatory capital requirements and to allow SCE to finance those assets solely with debt. Had such exclusion applied as of September 30, 2014, SCE estimates that its common equity requirement would be reduced by more than $300 million . The terms of San Onofre OII Amended Settlement Agreement provide that if SCE selects the debt financing option and finances these regulatory assets at a cost lower than the return authorized by the March 2014 San Onofre OII Settlement Agreement, the savings will be shared equally between ratepayers and SCE.

As discussed above, the Proposed Decision approves the San Onofre OII Amended Settlement Agreement, which includes a requirement for SCE to make a contribution of $4 million per year, for a five -year period, to a University of California research, development and demonstration program to reduce greenhouse gases. If the CPUC approves the San Onofre Amended Settlement Agreement consistent with the Proposed Decision, SCE will accrue the contribution obligation and record a pre-tax charge.

San Onofre OII Settlement Agreement Procedure

On October 9, 2014, the Administrative Law Judges in the San Onofre OII issued a Proposed Decision approving the San Onofre OII Amended Settlement Agreement. Under its rules, the CPUC may not render a final decision for at least thirty days following the issuance of the Proposed Decision, but the rules do not otherwise provide for any fixed time period for the CPUC to act on the San Onofre OII Amended Settlement Agreement. Pursuant to the CPUC's rules, no settlement becomes binding on the parties to it unless the CPUC approves the settlement based on a finding that it is reasonable in light of the whole record, consistent with law, and in the public interest. The CPUC has discretion to approve or disapprove a settlement, or to condition its approval on changes to the settlement, which the parties may accept or reject.

Accordingly, there can be no assurance regarding the timing of any CPUC decision or that the CPUC will approve the San Onofre OII Amended Settlement Agreement or refrain from making changes to it that are not acceptable to all the Settling Parties. Thus, there can be no assurance that the OII proceeding will provide for recoveries as currently estimated by SCE in accordance with the San Onofre OII Amended Settlement Agreement, including the recovery of costs recorded as a regulatory asset, or that the CPUC does not order refunds to customers above those contemplated by the San Onofre OII Amended Settlement Agreement. Therefore, the amount recorded for the San Onofre Regulatory Asset is subject to further change based upon future developments and the application of SCE's judgment to those events.

Third-Party Recoveries

San Onofre carries accidental property damage and carried 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 NEIL may assert reduce or eliminate coverage, and SCE may choose to challenge NEIL's application of any such exclusions and limitations. The estimated total claims under the accidental outage insurance through June 28, 2014 are approximately $427 million (SCE's share of which is approximately $334 million .) Accidental outage policy benefits may be subject to reduction by up to 90% for the periods following announcement of the permanent retirement of the Units. The accidental outage insurance at San Onofre has been canceled prospectively as a result of the permanent retirement. SCE has not submitted a proof of loss under the accidental property damage insurance but reserves the right to do so. It is possible that the NEIL Board of Directors will make a coverage determination by the end of 2014, but it may take longer. SCE may challenge any reduction or denial of coverage. No amounts have been recognized in SCE's financial statements, pending NEIL's response. The San Onofre OII Amended Settlement Agreement allocates to ratepayers 95% of SCE recoveries from NEIL under the accidental outage insurance policy, and 82.5% of other SCE recoveries against NEIL, in each case net of costs of recovery.

SCE is also pursuing claims against Mitsubishi Heavy Industries, Ltd. and related companies (together, "MHI"), which designed and supplied the RSGs. MHI warranted the RSGs for an initial period of 20 years from acceptance and 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 that 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 contract and tort claims and seeks at least $4 billion in damages on behalf of itself and its ratepayers and in its capacity as Operating Agent for San Onofre. MHI has denied any liability and has asserted counterclaims for $41 million , for which SCE has denied any liability. Each of the other co-owners sued MHI, alleging claims arising from MHI's supplying the faulty steam generators, which have been stayed pending the arbitration. The other co-owners (SDG&E and Riverside) have been added as additional claimants in the arbitration, with party status. The San Onofre OII Amended Settlement Agreement allocates recoveries from MHI net of recovery costs equally between SCE and its ratepayers as set forth in the agreement.

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 December 2013, the NRC finalized 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 identified a "white" finding (low to moderate safety significance) for failing to ensure that MHI's modeling and analysis were adequate. SCE stated disagreements with the NRC's Report but chose not to challenge the "white" finding. The NRC also 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 addition, the NRC's Office of Investigations conducted

an investigation of the accuracy and completeness of information SCE provided to the Augmented Inspection Team, and concluded that allegations against SCE regarding the accuracy and completeness of such information were not substantiated. On October 2, 2014, the NRC's Office of Inspector General ("OIG") published a report on the NRC's oversight of SCE's evaluation process for the RSGs, which was used to determine whether changes in the design of a component would require an amendment to the operating license of a nuclear power plant. The OIG determined that the NRC "missed opportunities" in connection with its 2009 inspection of SCE's evaluation process, and concluded that without further review of information concerning SCE's evaluation conclusions, there is no assurance that the NRC reached the correct conclusion in its 2009 inspection that San Onofre did not need a license amended for its steam generator replacement. The OIG Report also indicated that additional ongoing review of SCE's license amendment compliance by an NRC Staff Petition Review Board had been further deferred to February 2015. 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 for 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 proceedings by the NRC will be completed or whether inquiries by other government agencies will be initiated.

Note 10. Other Investments

Nuclear Decommissioning Trusts

Future decommissioning costs related to SCE's nuclear assets are expected to be funded from independent decommissioning trusts, which received $6 million in 2014 through SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC.

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



	Longest Maturity Dates	Amortized Cost				Fair Value
(in millions)	Longest Maturity Dates	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Stocks	—	$	500	$	656	$	1,970	$	2,208
Municipal bonds	2051	663		675		807		756
U.S. government and agency securities	2045	826		902		888		947
Corporate bonds	2057	333		208		385		241
Short-term investments and receivables/payables	One-year	657		329		691		342
Total		$	2,979	$	2,770	$	4,741	$	4,494

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 $2.1 billion and $2.6 billion for the three months ended September 30, 2014 and 2013 , and $5.8 billion and $4.6 billion for the nine months ended September 30, 2014 and 2013, respectively. Unrealized holding gains, net of losses, were $1.8 billion and $ 1.7 billion at September 30, 2014 and December 31, 2013 , respectively.

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



	Three months ended September 30,						Nine months ended September 30,
(in millions)	2014			2013			2014			2013
Balance at beginning of period	$	4,740		$	4,182		$	4,494		$	4,048
Gross realized gains	149			119			187			261
Gross realized losses	—			(17		)	—			(18		)
Unrealized gains (losses), net	(131		)	55			38			46
Other-than-temporary impairments	(4		)	(15		)	(10		)	(44		)
Interest, dividends, contributions and other	(13		)	8			32			39
Balance at end of period	$	4,741		$	4,332		$	4,741		$	4,332

Trust assets are used to pay income taxes as the Trust files separate income taxes returns from SCE. Deferred income taxes related to unrealized gains at September 30, 2014 were $431 million . Accordingly, the fair value of Trust assets available to pay future decommissioning costs, net of deferred income taxes, totaled $4.3 billion at September 30, 2014. Due to regulatory mechanisms, changes in assets of the trusts from income items have no impact on operating revenue or earnings.

Note 11. Regulatory Assets and Liabilities

Regulatory Assets

SCE's regulatory assets included on the consolidated balance sheets are:



(in millions)	September 30, 2014		December 31, 2013
Current:
Regulatory balancing accounts	$	1,101	$	484
Energy derivatives	64		54
Other	5		—
Total current	1,170		538
Long-term:
Deferred income taxes, net	3,361		2,957
Pensions and other postretirement benefits	506		369
Energy derivatives	721		816
Unamortized investments, net	275		332
San Onofre	1,386		1,325
Unamortized loss on reacquired debt	206		222
Regulatory balancing accounts	545		818
Other	329		402
Total long-term	7,329		7,241
Total regulatory assets	$	8,499	$	7,779

Regulatory Liabilities

SCE's regulatory liabilities included on the consolidated balance sheets are:



(in millions)	September 30, 2014		December 31, 2013
Current:
Regulatory balancing accounts	$	750	$	724
Other	44		43
Total current	794		767
Long-term:
Costs of removal	2,833		2,780
Asset retirement obligations	1,769		1,071
Regulatory balancing accounts	1,085		1,132
San Onofre	677		—
Other	23		12
Total long-term	6,387		4,995
Total regulatory liabilities	$	7,181	$	5,762

Net Regulatory Balancing Accounts

The following table summarizes the significant components of regulatory balancing accounts included in the above tables of regulatory assets and liabilities:



(in millions)	September 30, 2014			December 31, 2013
Asset (liability)
Energy resource recovery account	$	1,570		$	1,005
Four Corners memorandum account	6			145
New system generation balancing account	117			132
Public purpose programs and energy efficiency programs	(832		)	(1,037		)
Base rate recovery balancing account	(243		)	(247		)
Greenhouse gas auction revenue	(300		)	(385		)
FERC formula rates and FERC balancing accounts	(89		)	(59		)
FERC energy settlements	(195		)	—
Other	(223		)	(108		)
Net liability	$	(189	)	$	(554	)

Note 12. Commitments and Contingencies

Indemnities

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

Edison International and SCE have provided 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.

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.

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 has argued in related CPUC regulatory proceedings that its operating, capital, and market power costs should be recoverable through base rates and the ERRA balancing account (as reduced by the charges recorded in 2013 and 2014). SCE, however, 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. In March 2014, SCE, in recognition of these risks, entered into the

San Onofre OII Settlement Agreement with San Diego Gas & Electric Company, ORA, TURN, FOE and CUE that, if approved by the CPUC, would resolve the disallowance and regulatory recovery issues in accordance with the terms of the Agreement. This Agreement was subsequently amended and restated in September 2014. SCE will pursue recoveries from the manufacturer of the replacement steam generators and under San Onofre's insurance, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements. See Note 9 for further details.

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 in January 2013 that asserted, among other things, 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. In February 2014, SCE entered into agreements with the SED to settle this matter and another, unrelated matter involving SCE's system that occurred in San Bernardino for $24.5 million , including penalties totaling $15 million , which were approved by the CPUC without modification.

Four Corners Environmental Matters

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 Prevention of Significant Deterioration 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 December 2013, SCE sold its ownership interest in generating units 4 and 5 to APS. Under the sale agreement SCE remains responsible for its pro-rata share of certain environmental liabilities, including penalties in the event they arise from environmental violations prior to the sale. In addition, under the terms of the sale agreement, SCE retains the liability for its proportionate share of expenses occurring as a result of new environmental regulations applicable to the coal ash and combustion residuals deposited at the landfill at Four Corners during the period that SCE held its ownership interest in Four Corners if such new regulations are adopted. SCE is unable to estimate a possible loss or range of loss associated with these matters.

Environmental Remediation

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

At September 30, 2014 , SCE's recorded estimated minimum liability to remediate its 20 identified material sites (sites in which the upper end of the range of the costs is at least $1 million ) was $110 million , including $72 million related to San Onofre. In addition to these sites, SCE also has 38 immaterial sites for which the total minimum recorded liability was $3 million . Of the $113 million total environmental remediation liability for SCE, $109 million has been recorded as a regulatory asset. SCE expects to recover $37 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 $72 million through a mechanism that allows SCE to recover 100% of the costs incurred at certain sites through customer rates. SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs at the identified material sites and immaterial sites could exceed its recorded liability by up to $159 million and $7 million , respectively. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.

SCE expects to clean up and mitigate its identified sites over a period of up to 30 years. Remediation costs for each of the next four years are expected to range from $4.8 million to $31.1 million . Costs incurred for the nine months ended September 30, 2014 and 2013 were $3 million and $5 million , respectively.

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

Nuclear Insurance

Federal law limits public offsite liability claims for bodily injury and property damage 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 ) through a Facility Form issued by American Nuclear Insurers ("ANI"). 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.

The ANI Facility Form coverage includes broad liability protection for bodily injury or offsite property damage caused by nuclear material at San Onofre, or while in transit to or from San Onofre. The Facility Form, however, includes several exclusions. First, it excludes onsite property damage to the nuclear facility itself and onsite cleanup costs, but as discussed below SCE maintains separate NEIL property damage coverage for such events. Second, tort claims of onsite workers are excluded, but SCE also maintains separate $375 million ANI Facility Workers Form coverage for non-licensee workers. Third, offsite environmental costs arising out of government orders or directives, including those issued under the Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA, are excluded, with minor exceptions from clearly identifiable accidents.

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 nuclear property damage and accidental outage insurance policies. The amount of nuclear property insurance purchased for San Onofre and Palo Verde exceeds the minimum federal requirement of approximately $1.06 billion . These policies include coverage for decontamination liability. 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. The accidental outage insurance at San Onofre has been canceled as a result of the permanent retirement, but that insurance continues to be in effect at Palo Verde.

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. Prolonged drought conditions in California have also increased the risk of severe wildfire events. On June 1, 2014, Edison International renewed its liability insurance coverage, which included coverage for SCE's wildfire liabilities up to a $547.5 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 (June 1, 2014 to May 31, 2015). SCE also has additional coverage for certain wildfire liabilities of $450 million , which applies when total covered wildfire claims exceed $550 million , through June 14, 2015. 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 (SCE share $112 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 shares of the damage award paid. In December 2013, the CPUC approved SCE's proposal to return the SCE share of the award to customers based on the amount that customers actually contributed for fuel storage costs, resulting in approximately $94 million of the SCE share being returned to customers and the remaining $18 million being returned to shareholders. 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. In September 2014, SCE added damages incurred for the period from January 1, 2011 to December 31, 2013 in the approximate amount of $84 million to its December 2011 lawsuit. Additional legal action would be necessary to recover damages incurred after December 31, 2013. 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 2014, SCE issued 110,004 shares of 5.75% Series H preference stock (cumulative, $2,500 liquidation value) to SCE Trust III, a special purpose entity formed to issue trust securities as discussed in Note 3. The Series H preference stock may be redeemed at par, in whole, but not in part, at any time prior to March 15, 2024 if certain changes in tax or investment company laws occur. After March 15, 2024 , SCE may redeem the Series H shares at par, in whole or in part. After March 15, 2024 , distributions will accrue and be payable at a floating rate. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares were used to repay commercial paper borrowings and for general corporate purposes.

Note 14. Accumulated Other Comprehensive Loss

Edison International's accumulated other comprehensive loss, net of tax consist of:



	Three months ended September 30,						Nine months ended September 30,
(in millions)	2014			2013			2014			2013
Beginning balance	$	(13	)	$	(82	)	$	(13	)	$	(87	)
Pension and PBOP – net gain (loss):
Other comprehensive loss before reclassifications	(12		)	—			(17		)	(2		)
Reclassified from accumulated other comprehensive loss ¹	3			3			6			10
Other	(1		)	—			1			—
Change	(10		)	3			(10		)	8
Ending Balance	$	(23	)	$	(79	)	$	(23	)	$	(79	)


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

SCE's accumulated other comprehensive loss, net of tax consist of:



	Three months ended September 30,						Nine months ended September 30,
(in millions)	2014			2013			2014			2013
Beginning balance	$	(8	)	$	(30	)	$	(11	)	$	(29	)
Pension and PBOP – net gain (loss):
Other comprehensive loss before reclassifications	—			—			—			(4		)
Reclassified from accumulated other comprehensive loss ¹	1			2			2			5
Other	(1		)	—			1			—
Change	—			2			3			1
Ending Balance	$	(8	)	$	(28	)	$	(8	)	$	(28	)


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

Note 15. Interest and Other Income and Other Expenses

Interest and other income and other expenses are as follows:



	Three months ended September 30,				Nine months ended September 30,
(in millions)	2014		2013		2014		2013
SCE interest and other income:
FERC energy settlements	$	1	$	—	$	15	$	—
Equity allowance for funds used during construction	19		14		50		54
Increase in cash surrender value of life insurance policies and life insurance benefits	10		10		28		24
Interest income	1		2		6		8
Other	5		1		6		3
Total SCE interest and other income	36		27		105		89
Edison International Parent and Other other income	4		1		4		2
Total Edison International interest and other income	$	40	$	28	$	109	$	91
SCE other expenses:
Penalties	$	15	$	—	$	15	$	—
Civic, political and related activities and donations	8		9		22		24
Other	6		6		15		14
Total SCE other expenses	29		15		52		38
Edison International Parent and Other other expenses	—		—		—		—
Total Edison International other expenses	$	29	$	15	$	52	$	38

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. SCE is authorized to refund to customers any refunds actually realized by SCE, net of litigation costs and amounts retained by SCE as a shareholder incentive pursuant to an established sharing arrangement. During the nine months ended September 30, 2014, eight FERC-approved settlement agreements were finalized providing SCE with total refunds of $216 million of which $15 million is subject to the shareholder incentive.

In August 2014, the CPUC approved two settlement agreements between SCE and the SED related to 2011 events in San Bernardino and San Gabriel, California. The settlement agreements resulted in SCE paying a $15 million penalty to the State General Fund. See Note 12 for further details.

Note 16. Discontinued Operations

EME Chapter 11 Bankruptcy

In December 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.

In February 2014, Edison International, EME and the Consenting Noteholders entered into a settlement agreement (the "EME Settlement Agreement") pursuant to which EME amended its Plan of Reorganization to incorporate the terms of the EME Settlement Agreement, including extinguishing all existing claims between EME and Edison International. The Amended Plan of Reorganization, including the EME Settlement Agreement, was completed on April 1, 2014 with the sale of substantially all of EME's assets to NRG Energy, Inc. and the transactions called for in the EME Settlement Agreement.

Under the Amended Plan of Reorganization, EME emerged from bankruptcy free of liabilities but remained an indirect wholly-owned subsidiary of Edison International, which will continue to be consolidated with Edison International for income tax purposes. On April 1, 2014, all of the assets and liabilities of EME that were not otherwise discharged in the bankruptcy or transferred to NRG Energy were transferred to a newly formed trust under the control of EME's existing creditors (the "Reorganization Trust"), except for (a) EME's income tax attributes, which are retained by the Edison International consolidated income tax group; (b) certain tax and pension related liabilities in the approximate amount of $342 million , which have been assumed by Edison International and for substantially all of which Edison International had joint and several responsibility; and (c) EME's indirect interest in Capistrano Wind Partners (the indirect investment in Capistrano Wind project is accounted for at fair value) and a small hydroelectric project.

Edison International has agreed to pay to the Reorganization Trust an amount equal to 50% of EME's federal and California income tax benefits, which were not previously paid to EME under a tax allocation agreement between Edison International and EME that expired on December 31, 2013 ("EME Tax Attributes") and which were initially estimated to be approximately $1.191 billion , subject to an estimate updating procedure set forth in the EME Settlement Agreement. As called for in the EME Settlement Agreement, Edison International made an initial cash payment to the Reorganization Trust of $225 million in April 2014. In August 2014, Edison International entered into an amendment of the Settlement Agreement to finalize the remaining matters related to the EME Settlement including setting the EME Tax Attributes at $1.206 billion and the amount of the two installment payments, including interest, at $204 million due on September 30, 2015 and $214 million due on September 30, 2016.

As a result of the EME Settlement Agreement, Edison International recorded, as part of discontinued operations, losses of $16 million and income of $168 million during the three and nine months ended September 30, 2014, respectively.

Assuming continuation of existing tax law and tax rates, Edison International also anticipates realization of the tax benefits over a period similar to the period for which it pays for them. Extension of bonus depreciation would defer realization of the benefits, and reduction of federal income tax rates could permanently reduce them. Pending the realization of the tax benefits, Edison International will finance the settlement from existing credit lines.

Note 17. Supplemental Cash Flows Information

Supplemental cash flows information for continuing operations is:



	Edison International				SCE
	Nine months ended September 30,
(in millions)	2014		2013		2014		2013
Cash payments for interest and taxes:
Interest, net of amounts capitalized	$	412	$	431	$	411	$	415
Tax payments, net	190		27		15		18
Non-cash financing and investing activities:
Dividends declared but not paid:
Common stock	$	116	$	110	$	126	$	120
Preferred and preference stock	4		4		4		4
Notes issued under EME Settlement Agreement	410		—		—		—

SCE's accrued capital expenditures at September 30, 2014 and 2013 were $505 million and $401 million , respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.

ITEM 1A. RISK FACTORS

Prolonged drought conditions in California increase the risk of severe wildfire events and could create local transmission constraints that could materially affect SCE .

The entire state of California has been declared to be in a state of severe drought, with many areas of the state (including some within SCE's service territory) in even more worse conditions, from extreme to exceptional. These drought conditions increase the risk of severe wildfire events in SCE's territory that could damage the electric infrastructure necessary to deliver power to SCE's customers and affect reliability. These events can lead to lost revenues and increased expenses, including higher maintenance and repair costs. They can also result in regulatory penalties and disallowances, particularly if SCE encounters difficulties in restoring power to its customers. The drought conditions may also affect the amount of power available from SCE's hydroelectric generation facilities, which could create local transmission constraints and affect reliability in certain areas.

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 the:


•	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 undercollection 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;


•	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, federal and state subsidies, 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, failure, availability, efficiency, and output of equipment and availability and cost of spare parts;


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


•	physical security of SCE's critical assets and personnel and the cyber security of SCE's 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 in the event of power plant 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 San Onofre may not be recoverable from SCE's supplier or insurance coverage;


•	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;


•	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;


•	extent of technological change in the generation, storage, transmission, distribution and use of electricity;


•	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 2013 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 2013 Form 10-K, and carefully consider the risks, uncertainties and other factors that affect Edison International's and SCE's businesses. Forward-looking statements speak 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, 2014 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International and SCE since December 31, 2013, and as compared to the nine months ended September 30, 2013. This discussion presumes that the reader has read or has access to Edison International's and SCE's MD&A for the calendar year 2013 (the "year-ended 2013 MD&A"), which was included in the 2013 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 consolidated non-utility subsidiaries.

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 and delivering electricity. Edison International is also the parent company of subsidiaries that are engaged in competitive businesses related to the generation or use of electricity. Such competitive business activities are currently not material to report as a separate business segment. 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)	2014			2013			Change		2014			2013			Change
Net income (loss) attributable to Edison International
Continuing operations
SCE	$	503		$	477		$	26	$	1,072		$	642		$	430
Edison International Parent and Other	(7		)	(14		)	7		(26		)	(27		)	1
Discontinued operations	(16		)	(25		)	9		146			(1		)	147
Edison International	480			438			42		1,192			614			578
Less: Non-core items
SCE	—			—			—		(96		)	(365		)	269
Edison International Parent and Other	—			—			—		—			7			(7		)
Discontinued operations	(16		)	(25		)	9		146			(1		)	147
Total non-core items	(16		)	(25		)	9		50			(359		)	409
Core earnings (losses)
SCE	503			477			26		1,168			1,007			161
Edison International Parent and Other	(7		)	(14		)	7		(26		)	(34		)	8
Edison International	$	496		$	463		$	33	$	1,142		$	973		$	169

Edison International's earnings are prepared in accordance with GAAP 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.

SCE's third quarter 2014 core earnings increased $26 million from the third quarter of 2013 primarily due to higher authorized revenues from rate base growth partially offset by lower income tax benefits.

Edison International Parent and Other's third quarter core losses decreased $7 million primarily due to higher income from Edison Capital's investments in affordable housing projects and higher income tax benefits, partially offset by higher corporate and new business expenses.

SCE's core earnings for the nine months ended September 30, 2014 increased $161 million from the nine months ended September 30, 2013 primarily due to higher authorized revenues from rate base growth, higher income tax benefits and lower severance costs. In addition, during the nine months ended September 30, 2014, SCE recorded $19 million ($11 million after-tax) from a change in estimate of revenues under its FERC formula rate and $15 million ($9 million after-tax) of benefits related to FERC energy settlements. See "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses." During the nine months ended September 30, 2014 and 2013, SCE incurred severance costs (after-tax) related to workforce reductions of $4 million and $26 million, respectively.

Edison International Parent and Other's core losses for the nine months ended September 30, 2014 decreased $8 million from the nine months ended September 30, 2013 primarily due to higher income tax benefits and higher income from Edison Capital's investments in affordable housing projects, partially offset by new business expenses.

Consolidated non-core items for 2014 and 2013 for SCE and Edison International included:

•

Impairment and other charges of $231 million ($96 million after-tax) in the first quarter of 2014 related to the San Onofre OII Settlement Agreement (as discussed below) and $575 million ( $365 million after-tax) in the second quarter of 2013 related to the permanent retirement of San Onofre Units 2 and 3. These charges result in a total impact of the San Onofre OII settlement estimated to be $806 million (approximately $461 million after-tax). Such amounts do not reflect any recoveries from third parties by SCE. For further information, see "—San Onofre Issues" and "Notes to Consolidated Financial Statements—Note 9. San Onofre Issues—Accounting and Financial Impact."

•

A loss of $16 million during the third quarter of 2014 and income of $168 million during the nine months ended September 30, 2014 related to the impact of completing the transactions called for in the EME Settlement Agreement (as defined below). In August 2014, Edison International entered into an amendment of the Settlement Agreement to finalize the remaining matters related to the EME Settlement as discussed further below. In addition, Edison International recorded an income tax loss of $22 million for the first quarter of 2014 compared to a loss of $25 million and $1 million for the three- and nine-month periods in 2013 from revised estimates of the tax impact of a tax deconsolidation of EME from Edison International. Edison International continues to consolidate EME for federal and certain combined state tax returns. For further information, see "—EME Chapter 11 Bankruptcy."

•

An income tax benefit of $7 million in the first quarter of 2013 from reduction in state income taxes related to the sale of Edison Capital's interest in Unit No. 2 of the Beaver Valley Power plant. The sale of Edison Capital's lease interest was completed in 2012, however, the final determination of state income taxes paid was not completed until the first quarter of 2013 which resulted in a change in the estimate of state income taxes due.

San Onofre Issues

As discussed in the 2013 Form 10-K, replacement steam generators were installed at San Onofre in 2010 and 2011. On January 31, 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. Unit 2 was off-line for a planned outage when areas of unexpected tube to support structure wear were found. Later, evidence of tube to tube wear in Unit 2 was also discovered. On June 6, 2013, SCE decided to permanently retire Units 2 and 3.

CPUC Proceedings and Proposed Settlement

On September 23, 2014, SCE entered into an Amended and Restated Settlement Agreement (the "San Onofre OII Amended Settlement Agreement") with The Utility Reform Network ("TURN"), the CPUC's Office of Ratepayer Advocates ("ORA"), SDG&E, the Coalition of California Utility Employees ("CUE"), and Friends of the Earth ("FOE") (together, the "Settling Parties"). If implemented, the San Onofre OII Amended Settlement Agreement will constitute a complete and final resolution of the CPUC's OII and related proceedings regarding the Steam Generator Replacement Project ("SGRP") at San Onofre and the related outage and subsequent shutdown of San Onofre. The Settling Parties agreed to amend the Settlement Agreement that was originally entered into in March 2014 in response to an Assigned Commissioner's and Administrative Judges’ Ruling that was issued on September 5, 2014. The San Onofre OII Amended Settlement Agreement does not affect proceedings before the NRC or proceedings related to recoveries from third parties described below, but does describe how shareholders and customers will share any potential recoveries. Implementation of the San Onofre OII Amended Settlement Agreement is subject to the approval of the CPUC. The San Onofre OII Amended Settlement Agreement is subject to termination by any of the Settling Parties if the CPUC has not approved it by December 23, 2014, but there can be no certainty of when or what the CPUC will actually decide. On October 9, 2014, the Administrative Law Judges in the OII issued a Proposed Decision approving the San Onofre OII Amended Settlement Agreement. Under applicable rules, the CPUC cannot render a final decision for at least thirty days following the date of the Proposed Decision, but there can be no certainty of when or what the CPUC will actually decide. The parties to the San Onofre OII Amended Settlement Agreement have agreed to exercise their best efforts to obtain CPUC approval. For further information regarding the San Onofre OII Amended Settlement Agreement's treatment of disallowances, refunds and rate recoveries, the accounting impact thereof, and the current status of

CPUC proceedings related to the San Onofre OII Amended Settlement Agreement, see "Notes to Consolidated Financial Statements—Note 9. San Onofre Issues" and "—Highlights of Operating Results." As indicated in Note 9 and "—Highlights of Operating Results," SCE has recorded the effects of the San Onofre OII Amended Settlement Agreement assuming it is approved. Accordingly, if the San Onofre OII Amended Settlement Agreement is approved, SCE does not expect implementation of rate recoveries and rate refunds contemplated by the San Onofre OII Amended Settlement Agreement will have a material impact on future net income. Such amounts do not reflect any recoveries from third parties by SCE.

Third-Party Recoveries

As discussed in the 2013 Form 10-K, San Onofre carries accidental property damage and carried 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 NEIL may assert reduce or eliminate coverage, and SCE may choose to challenge NEIL's application of any such exclusions and limitations. The estimated total claims under the accidental outage insurance through June 28, 2014 are approximately $427 million (SCE's share of which is approximately $334 million). Accidental outage policy benefits may be subject to reduction by up to 90% for the periods following announcement of the permanent retirement of the Units. The accidental outage insurance at San Onofre has been canceled prospectively as a result of the permanent retirement. SCE has not submitted a proof of loss under the accidental property damage insurance but reserves the right to do so. It is possible that the NEIL Board of Directors will make a coverage determination by the end of 2014, but it may take longer. SCE may challenge any reduction or denial of coverage. No amounts have been recognized in SCE's financial statements, pending NEIL's response.

Under the San Onofre OII Amended Settlement Agreement, recoveries from NEIL, if any, will first be applied on and after December 31, 2014 to reimburse costs incurred in pursuing such recoveries, including litigation costs. To the extent SCE's share of recoveries from NEIL exceeds such costs, recoveries under the accidental outage insurance will be allocated 95% to ratepayers and 5% to SCE and all other NEIL recoveries will be allocated 82.5% to ratepayers and 17.5% to SCE. SCE ratepayers' portion of amounts recovered from NEIL would be distributed to SCE ratepayers via a credit to SCE's ERRA account.

SCE is also pursuing claims against Mitsubishi Heavy Industries, Ltd. and related companies ("MHI"), which designed and supplied the RSGs. MHI warranted the RSGs for an initial period of 20 years from acceptance and 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 that 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 contract and tort claims and seeks at least $4 billion in damages on behalf of itself and its ratepayers and in its capacity as Operating Agent for San Onofre. MHI has denied any liability and has asserted counterclaims for $41 million, for which SCE has denied any liability. Each of the other co-owners sued MHI, alleging claims arising from MHI's supplying the faulty steam generators, which have been stayed pending the arbitration. The other co-owners (SDG&E and Riverside) have been added as additional claimants in the arbitration, with party status.

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 it and subsequently rejected a portion of the first invoice and has not paid further invoices, claiming further documentation is required, which SCE disputes. SCE recorded its share of the invoice paid (approximately $35 million) as a reduction of repair and inspection costs in 2012.

Under the San Onofre OII Amended Settlement Agreement, recoveries from MHI (including amounts paid by MHI under the first invoice), if any, will first be applied on and after December 31, 2014 to reimburse costs incurred in pursuing such recoveries, including litigation costs. To the extent SCE's share of recoveries from MHI exceed such costs, they will be allocated 50% to ratepayers and 50% to SCE.

The first $282 million of SCE's ratepayers' portion of such recoveries from MHI will be distributed to ratepayers via a credit to a sub-account of SCE's Base Revenue Requirement Balancing Account ("BRRBA"), reducing revenue requirements from ratepayers. Amounts in excess of the first $282 million distributable to SCE ratepayers will reduce SCE's regulatory asset represented by the unamortized balance of investment in San Onofre base plant, reducing the revenue requirement needed to amortize such investment. The amortization period, however, will be unaffected. Any additional amounts received after the regulatory asset is recovered will be applied to the BRRBA.

The San Onofre OII Amended Settlement Agreement provides the utilities with the discretion to resolve the NEIL and MHI disputes without CPUC approval or review, but the utilities are obligated to use their best efforts to inform the CPUC of any settlement or other resolution of these disputes to the extent this is possible without compromising any aspect of the resolution. SCE and SDG&E have also agreed to allow the CPUC to review the documentation of any final resolution of the NEIL and MHI disputes and the litigation costs incurred in pursuing claims against MHI and NEIL to ensure they are not exorbitant in relation to the recovery obtained. There is no assurance that there will be any recoveries from NEIL or MHI or that if there are recoveries, that they will exceed the costs incurred to pursue them. Were there to be recoveries, SCE cannot speculate when they would be received.

Rate Impacts

To the extent that SCE collects in rates amounts that are in excess of the amounts recoverable under the San Onofre OII Amended Settlement Agreement, such amounts will be credited to SCE's ERRA account, thereby reducing the undercollected balance that would otherwise be subject to rate recovery. SCE estimates that if the settlement had been implemented on September 30, 2014, the refund of revenue related to the SGRP, the refund of the difference between authorized and recorded operation and maintenance expenses for 2013 and the first nine months of 2014, the refund from the reduction of returns on the balance of its San Onofre investment and the other elements of the settlement would have resulted in a refund to ratepayers of approximately $677 million . SCE's ERRA undercollection at September 30, 2014 was $1.57 billion . See "—ERRA Balancing Account" below for more information.

As a result of the disallowances, refunds and reduced returns contemplated by the San Onofre OII Amended Settlement Agreement, SCE ratepayers will also have a reduction from the current level of authorized revenue set forth in SCE's 2012 General Rate Case. Calculation of the reduction of revenue requirement over any meaningful period of time is subject to a number of estimates and assumptions which may prove to be inaccurate. Subject to such uncertainty, SCE estimates that the present value of the revenue requirement that will be collected in rates under the San Onofre OII Settlement Agreement will be more than $1 billion below the present value (using a 10% discount rate) of the revenue requirement that SCE had been seeking in the OII before the settlement.

NRC Proceedings

For information on the NRC proceedings, see "Notes to Consolidated Financial Statements—Note 9. San Onofre Issues—Continuing NRC Proceedings."

Decommissioning

As discussed in the 2013 Form 10-K, 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. In June 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 in June and July 2013 for Units 3 and 2, respectively. On September 23, 2014, SCE submitted its Post-Shutdown Decommissioning Activities Report (“PSDAR”), Irradiated Fuel Management Plan and Decommissioning Cost Estimate for SONGS, Units 2 and 3 to the NRC. These submittals are now subject to a ninety day period for NRC review and acceptance. Major radiological decommissioning activities may only start 90 days after the NRC receipt of the PSDAR.

During the second quarter of 2014, SCE updated its decommissioning cost estimate based on a site specific assessment. The decommissioning cost estimate in 2014 dollars is $4.4 billion (SCE share – $3.3 billion) and includes costs from June 7, 2013 through to the respective completion dates to decommission San Onofre Units 2 and 3. The decommissioning cost estimate is subject to a number of estimates including the cost of burial of nuclear waste, cost of removal of property, site remediation costs as well as a number of other assumptions and estimates, including when the federal government may remove spent fuel canisters from the San Onofre site, as to which there can be no assurance. The cost estimate is subject to change and such changes may be material. SCE's share of the present value of decommissioning costs after escalation and using current discounts rates was $3.0 billion at September 30, 2014. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Asset Retirement Obligation."

SCE has nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $3.36 billion as of September 30, 2014, which is comprised of annual contributions made through rates and earnings on the trust funds' balances. If the decommissioning cost estimate and assumptions regarding trust performance do not change, SCE believes that future contributions to the trust funds will not be necessary. 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. SCE has filed a request with the CPUC to authorize early release of trust funds for costs up to a specified cost cap of $214 million to cover SCE's share of 2013 decommissioning costs. The request also seeks CPUC approval for a process by which SCE will be able to seek the release of trust funds to cover decommissioning costs incurred in 2014 and future periods until the CPUC approves a permanent San Onofre decommissioning plan and cost recovery mechanism.

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 either greater or less than the forecast are tracked in the ERRA balancing account and collected from or refunded to customers in subsequent periods depending upon whether the balancing account is under collected or over collected. Until November 2013, SCE continued to recover in rates amounts that had been authorized in the 2012 ERRA proceeding and which were significantly below the costs actually incurred, resulting in a significant undercollection in the balancing account. In October 2013, the CPUC issued a decision on SCE's 2013 ERRA forecast that approved a portion of SCE's 2013 ERRA forecast and allowed SCE to increase rates by approximately $160 million. Under this decision, SCE was required to defer collection of its San Onofre-related replacement power costs that exceeded those estimated in the 2013 ERRA forecast filing pending the review of such costs in the San Onofre OII proceeding.

In May 2014, the CPUC issued a final decision in the 2014 ERRA forecast proceeding that adopted SCE's requested increase of $1.12 billion and deferred collection of $467 million of San Onofre-related replacement power costs incurred in 2013 until resolution of such costs in the San Onofre OII proceeding consistent with the CPUC decision in the 2013 ERRA forecast proceeding. SCE implemented a rate increase from the 2014 forecast proceeding consistent with the final decision, effective June 1, 2014.

In June 2014, SCE filed its 2015 ERRA forecast application, requesting an annual revenue requirement, beginning on January 1, 2015, of $5.62 billion (assuming the San Onofre OII Settlement Agreement is approved by the CPUC in 2014) or, alternatively, $6.41 billion (assuming the San Onofre OII Settlement Agreement is not approved by the CPUC or delayed beyond 2014).

As of September 30, 2014, SCE's fuel and power procurement-related costs were undercollected by $1.57 billion . With the 2014 ERRA rate increase implemented on June 1, 2014, SCE does not expect material increases in undercollections by year-end from fuel and power procurement costs. The ERRA undercollection balance is expected to decrease during 2015, assuming:


•	approval of the application of refunds provided for in the San Onofre OII Amended Settlement Agreement, including refunds related to the SGRP and authorized revenue in excess of SCE cost of service during 2013 and 2014 as discussed above under the heading "—San Onofre Issues;"


•	approval of SCE's request to classify the majority of costs incurred at San Onofre since June 7, 2013 as decommissioning costs and reimbursement from SCE's nuclear decommissioning trust; and


•	approval of SCE's 2015 ERRA forecast application, with implementation of revised rates occurring during the first quarter of 2015.

These decreases may be partially offset by higher than forecasted natural gas and power prices. 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 undercollection of fuel and purchase power costs would adversely impact SCE's liquidity.

2015 General Rate Case

In November 2013, SCE filed its 2015 GRC application requesting a 2015 base rate revenue requirement of $6.462 billion, which was subsequently reduced in April 2014 to $5.860 billion to remove costs related to Four Corners and San Onofre, as directed by the ALJs assigned to the case. SCE's revised request would be a $227 million increase over currently authorized base rate revenue. The application also proposed post-test year increases in 2016 and 2017 of $321 million and $330 million, respectively. On July 3, 2014, SCE submitted supplemental testimony, as requested by an Assigned Commissioner Ruling, that provided specific information on how mitigation of safety- and reliability-related risks were taken into account in SCE's 2015 GRC application. In September 2014, in its rebuttal testimony, SCE further revised its requested base rate revenue requirement to $5.775 billion, which would be a $142 million increase over currently authorized base rate revenue. The rebuttal testimony also proposed post-test year increases in 2016 and 2017 of $301 million and $315 million, respectively.

The CPUC's Office of Ratepayer Advocates ("ORA"), recommended that SCE's requested 2015 base revenue requirements be decreased by approximately $607 million, comprised of approximately $302 million in operations and maintenance expense reductions and approximately $305 million in capital-related revenue requirement reductions. TURN recommended that SCE's requested 2015 base revenue requirements be decreased by approximately $412 million, comprised of approximately $131 million in operations and maintenance expense reductions and approximately $281 million in capital-related revenue requirement reductions. TURN's recommendation also included a reduction in revenue requirement related to repair deductions that originated during the period 2012 – 2014.

Evidentiary hearings on SCE's 2015 GRC began in late September 2014 and are expected to be completed in October 2014. The request for supplemental testimony discussed above is expected to delay a final 2015 GRC decision until beyond 2014, although consistent with historical CPUC practice, SCE expects that a final decision will be retroactively effective as of January 1, 2015. 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 2014, 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 $2.6 billion and $2.4 billion for the first nine months of 2014 and 2013, respectively.

SCE currently projects that 2014 capital expenditures will be in the range of $3.6 billion to $4.1 billion. SCE forecasts capital expenditures in the range of $15.4 billion to $17.4 billion for 2014 – 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.

EME Chapter 11 Bankruptcy

As discussed in the 2013 Form 10-K, in December 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.

Under the Amended Plan of Reorganization, EME emerged from bankruptcy free of liabilities but remained an indirect wholly-owned subsidiary of Edison International, which will continue to be consolidated with Edison International for income tax purposes. On April 1, 2014, all of the assets and liabilities of EME that were not otherwise discharged in the bankruptcy or transferred to NRG Energy were transferred to a newly formed trust under the control of EME's existing creditors (the "Reorganization Trust"), except for (a) EME's income tax attributes ("EME Tax Attributes"), which are retained by the Edison International consolidated income tax group; (b) certain tax and pension related liabilities in the approximate amount of $342 million, which have been assumed by Edison International and for substantially all of which Edison International had joint and several responsibility; and (c) EME's indirect interest in Capistrano Wind Partners and a small hydroelectric project.

As called for in the EME Settlement Agreement, Edison International made an initial cash payment to the Reorganization Trust of $225 million in April 2014. In August 2014, Edison International entered into an amendment of the Settlement Agreement to finalize the remaining matters related to the EME Settlement including setting the EME Tax Attributes at $1.206 billion and the amount of the two installment payments, including interest, at $204 million due on September 30, 2015 and $214 million due on September 30, 2016.

RESULTS OF OPERATIONS

Southern California Edison Company

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 revenue 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 is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities.

Three months ended September 30, 2014 versus September 30, 2013



	Three months ended September 30, 2014									Three months ended September 30, 2013
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated
Operating revenue	$	1,884		$	2,454		$	4,338		$	1,845		$	2,112		$	3,957
Fuel and purchased power	—			2,182			2,182			—			1,808			1,808
Operation and maintenance	506			270			776			572			303			875
Depreciation, decommissioning and amortization	423			—			423			392			—			392
Property and other taxes	76			—			76			78			—			78
Total operating expenses	1,005			2,452			3,457			1,042			2,111			3,153
Operating income	879			2			881			803			1			804
Interest income and other	8			(1		)	7			12			—			12
Interest expense	(132		)	(1		)	(133		)	(130		)	(1		)	(131		)
Income before income taxes	755			—			755			685			—			685
Income tax expense	224			—			224			183			—			183
Net income	531			—			531			502			—			502
Preferred and preference stock dividend requirements	28			—			28			25			—			25
Net income available for common stock	$	503		$	—		$	503		$	477		$	—		$	477
Core earnings ¹							$	503								$	477
Non-core earnings							—									—
Total SCE GAAP earnings							$	503								$	477


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

Utility Earning Activities

Utility earning activities were primarily affected by the following:


•	Higher operating revenue of $39 million primarily due to the following:


•	An increase in CPUC-related revenue of $100 million primarily related to the increase in authorized revenue to support rate base growth.


•	An increase in FERC-related revenue of $30 million primarily related to rate base growth and higher operating costs.


•	A decrease in San Onofre-related estimated revenue of $69 million, as discussed below.


•	A decrease in Four Corners-related revenue of $25 million due to the sale of SCE's ownership interest in the Four Corners Generating Station in December 2013 (primarily offset in operation and maintenance and depreciation expense below).


•	Lower operation and maintenance expense of $66 million primarily due to a decrease in San Onofre-related expense of $53 million discussed below as well as Four Corners-related expense of $12 million.


•	Higher depreciation, decommissioning and amortization expense of $31 million primarily due to an increase in depreciation primarily related to transmission and distribution investments.

•

Lower interest income and other of $4 million primarily due to a $15 million penalty that resulted from the San Bernardino and San Gabriel settlement, partially offset by $7 million in sales tax refund related to San Onofre as discussed below and higher AFUDC equity income resulting from an implementation of a 2013 rate change. See "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses."


•	Higher income taxes of $41 million primarily due to higher pre-tax income. See "—Income Taxes" below for more information.

On June 6, 2013, SCE decided to permanently retire San Onofre Units 2 and 3. On March 27, 2014, SCE entered into the San Onofre OII Settlement Agreement to resolve CPUC regulatory issues associated with San Onofre and the failure of its replacement steam generators. See "Management Overview—San Onofre Issues" above for more information. The following table summarizes the results of operations attributable to the San Onofre plant for the three and nine months ended September 30, 2014 and 2013, respectively:



	Three months ended September 30,								Nine months ended September 30,
(in millions)	2014				2013				2014				2013
Revenue	$	29			$	98			$	79			$	348
Operating expenses
Operation and maintenance	23				76				64			¹	260			¹
Depreciation and amortization	—				(11		)	⁴	—				58
Property and other taxes	(2		)	³	6				4			^{2, 3}	18
Impairment and other charges	—				—				231				575
AFUDC	—				—				—				(6		)
Total operating expenses	21				71				299				905
Income (loss) before taxes	$	8			$	27			$	(220	)		$	(557	)


¹	Includes severance costs of $1 million and $79 million for the nine months ended September 30, 2014 and 2013, respectively.


²	Includes a property tax refund of $5 million related to replacement steam generators reflected in the nine months ended September 30, 2014.


³	Includes a sales tax refund of $7 million related to replacement steam generators for the three and nine months ended September 30, 2014. The sales tax refund is included in "Interest and other income" on the consolidated income statements.


⁴	Includes a revision to year-to-date depreciation and amortization expense during 2013.

Utility Cost-Recovery Activities

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

•

Higher fuel and purchased power expense of $374 million was primarily driven by an increased load related to warmer weather and higher power and gas prices experienced in 2014 relative to 2013 and higher realized losses on economic hedging activities ( $18 million in 2014 compared to $15 million in 2013), partially offset by lower fuel expense in 2014 due to the sale of Four Corners in December 2013.


•	Lower operation and maintenance expense of $33 million primarily due to lower costs for the GHG cap-and-trade program related to utility owned generation and lower transmission access charges.

Nine months ended September 30, 2014 versus September 30, 2013



	Nine months ended September 30, 2014									Nine months ended September 30, 2013
(in millions)	Utility Earning Activities			Utility Cost- Recovery Activities			Total Consolidated			Utility Earning Activities			Utility Cost- Recovery Activities		Total Consolidated
Operating revenue	$	5,023		$	5,253		$	10,276		$	5,012		$	4,619	$	9,631
Fuel and purchased power	—			4,563			4,563			—			3,818		3,818
Operation and maintenance	1,501			686			2,187			1,739			801		2,540
Depreciation, decommissioning and amortization	1,248			—			1,248			1,223			—		1,223
Property and other taxes	232			—			232			229			—		229
Impairment and other charges	231			—			231			575			—		575
Total operating expenses	3,212			5,249			8,461			3,766			4,619		8,385
Operating income	1,811			4			1,815			1,246			—		1,246
Interest income and other	53			—			53			51			—		51
Interest expense	(398		)	(4		)	(402		)	(384		)	—		(384		)
Income before income taxes	1,466			—			1,466			913			—		913
Income tax expense	310			—			310			196			—		196
Net income	1,156			—			1,156			717			—		717
Preferred and preference stock dividend requirements	84			—			84			75			—		75
Net income available for common stock	$	1,072		$	—		$	1,072		$	642		$	—	$	642
Core earnings ¹							$	1,168							$	1,007
Non-core earnings							(96		)						(365		)
Total SCE GAAP earnings							$	1,072							$	642


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

Utility Earning Activities

Utility earning activities were primarily affected by the following:


•	Higher operating revenue of $11 million primarily due to the following:


•	An increase in CPUC-related revenue of $260 million primarily related to the increase in authorized revenue to support rate base growth.


•	An increase in FERC-related revenue of $105 million primarily related to rate base growth and higher operating costs, including $19 million of additional revenue from a change in estimate under the FERC formula rate mechanism.


•	A decrease in San Onofre-related estimated revenue of $269 million, as discussed above.


•	A decrease in Four Corners-related revenue of $80 million due to the sale of SCE's ownership interest in the Four Corners Generating Station in December 2013 (primarily offset in operation and maintenance and depreciation expense below).


•	Lower operation and maintenance expense of $238 million primarily due to:


•	A decrease in San Onofre-related expense of $196 million discussed above as well as Four Corners-related expense of $42 million.


•	A decrease in severance costs of $23 million (excluding San Onofre) and lower planned outage costs of $11 million at Mountainview.


•	An increase of $35 million of higher operating costs primarily related to transmission and distribution, legal and safety.


•	Higher depreciation, decommissioning and amortization expense of $25 million primarily due to a $127 million increase in depreciation mainly related to transmission and distribution investments, partially offset by a decrease in San Onofre-related expense of $58 million discussed above and lower Four Corners-related expense of $32 million.

•

Higher interest income and other of $2 million primarily due to $15 million in FERC energy settlements, $7 million in sales tax refund related to San Onofre discussed above and $6 million in insurance benefits, partially offset by lower AFUDC equity income related to lower AFUDC rates and lower construction work in progress balances in 2014, including SCE no longer accruing AFUDC on construction work in progress balances for San Onofre, pending the outcome of the San Onofre OII, and lower interest income. In addition, in 2014, SCE incurred a $15 million penalty resulting from the San Bernardino and San Gabriel settlements. See "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses."


•	Higher interest expense of $14 million primarily due to lower capitalized interest (AFUDC debt) and higher balances on long-term debt to support rate base growth.


•	Higher income taxes of $114 million primarily due to higher pre-tax income. See "—Income Taxes" below for more information.


•	Higher preferred and preference stock dividends of $9 million related to a new issuance in 2014.

Utility Cost-Recovery Activities

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

•

Higher fuel and purchased power expense of $745 million was primarily driven by an increased load related to warmer weather and higher power and gas prices experienced in 2014 relative to 2013 and higher realized losses on economic hedging activities ( $59 million in 2014 compared to $38 million in 2013), partially offset by lower fuel expense in 2014 due to the sale of Four Corners in December 2013 and FERC energy settlements refunded to customers (see "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses" for more information). In addition, during the second quarter of 2014, the CAISO issued invoices implementing a FERC order which revised FERC tariffs for costs associated with scheduling coordinator activities. The order and revised invoices reflect a shift in responsibility from transmission activities charged to all ISO participating transmission customers to generation activities charged to load customers. The impact of implementing the order and revised invoices resulted in a transmission refund of $106 million reflected in operation and maintenance expense and a generation surcharge of $83 million reflected in purchased power expense. These transactions did not impact earnings as the net refund was provided to ratepayers through a FERC balancing account mechanism.


•	Lower operation and maintenance of $115 million primarily due to the CAISO refund of $106 million mentioned above and lower costs for the GHG cap-and-trade program related to utility owned generation, partially offset by higher transmission access charges.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account overcollections/undercollections) was $4.5 billion and $9.7 billion for the three and nine months ended September 30, 2014, respectively, compared to $3.9 billion and $9.1 billion for the respective periods in 2013. The revenue reflects:


•	Retail billed and unbilled revenue reflects a sales volume increase of $136 million and $144 million for the three and nine months ended September 30, 2014, respectively, due to higher load requirements related to warmer weather experienced in 2014 compared to the same period last year.


•	A rate increase of $423 million and $373 million for the three and nine months ended September 30, 2014, respectively, due to the implementation of the 2014 ERRA rate increase in June 2014. The year-to-date increase was partially offset by the greenhouse gas auction revenue and base rate differences refunded to customers in April 2014.

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 2013 Form 10-K).

Income Taxes

SCE's income tax provision increased by $41 million and $114 million for the three and nine months ended September 30, 2014, respectively, compared to same periods in 2013 primarily due to increases in pre-tax income.

The effective tax rates were 29.7% and 26.7% for the three months ended September 30, 2014 and 2013, respectively. The effective tax rates were 21.1% and 21.5% for the nine months ended September 30, 2014 and 2013, respectively. See "Item 1. Notes to Consolidated Financial Statements—Note 7. Income Taxes" for a reconciliation of the federal statutory rate of 35% to the effective income tax rates and "Management Overview—San Onofre Issues" above for more information.

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.

SCE's income tax provision included the following change of estimates:


•	During the second quarter of 2014, SCE revised its liability for uncertain tax positions related to repair deductions for 2003 – 2010 which resulted in income tax benefits of $29 million.


•	During the third quarter of 2013, SCE revised its liability for uncertain tax positions related to generation repair deductions based on new IRS guidance that resulted in income tax benefits of $21 million.

Edison International Parent and Other

Results of operations for Edison International Parent and Other include 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 decreased by $7 million and $1 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The three and nine month results include Edison International Parent, Edison Mission Group and subsidiaries and new businesses conducted through Edison Energy. Corporate expenses of Edison International Parent and costs of new businesses conducted through Edison Energy were $4 million and $7 million higher during the three and nine months ended September 30, 2014 than 2013, respectively, in comparison to the same periods in 2013. The earnings of Edison Mission Group and subsidiaries for the three and nine months ended September 30, 2014 were $13 million and $20 million, respectively, compared to zero and $3 million during the three and nine months ended September 30, 2013. Earnings from Edison Mission Group and subsidiaries were higher in 2014 due to higher income from affordable housing projects and income tax benefits.

Income (Loss) from Discontinued Operations (Net of Tax)

Loss from discontinued operations, net of tax, was $16 million for the three months ended September 30, 2014, compared to a loss of $25 million for the same period in 2013. Income from discontinued operations, net of tax, was $146 million for the nine months ended September 30, 2014, compared to a loss of $1 million for the respective period in 2013. The 2014 loss and income were primarily due to the completion of the Amended Plan of Reorganization, including transactions recorded in the first nine months of 2014 associated with the sale of substantially all of EME's assets to NRG Energy, Inc. and other transactions called for in the EME Settlement Agreement. The 2013 loss from discontinued operations resulted from revised estimates 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).

LIQUIDITY AND CAPITAL RESOURCES

Southern California Edison Company

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 obligations and dividend payments to Edison International, and the outcome of tax and regulatory matters.

SCE expects to fund its 2014 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, 2014, SCE had a $ 2.75 billion multi-year revolving credit facility. For further details see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

SCE's cash flows are affected by regulatory balancing accounts overcollections or undercollections. As of September 30, 2014 and December 31, 2013, SCE had net regulatory balancing account overcollections of $ 189 million and $ 554 million , respectively. The change was primarily due to higher undercollections related to fuel and procurement-related costs. See "Management Overview—ERRA Balancing Account" for further information. SCE may finance unrecovered power procurement-related costs as well as other balancing account undercollections and working capital requirements to support operations and capital expenditures with commercial paper or other borrowings, subject to availability in the capital markets.

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, 2014, SCE's debt to total capitalization ratio was 0.45 to 1.

Regulatory Proceedings

FERC Formula Rates

In July 2014, SCE provided its preliminary 2015 annual transmission revenue requirement update to interested parties. The update provided support for an increase in SCE's transmission revenue requirement of $95 million or 11.6% over amounts currently authorized in rates. The primary reason for the increase is the inclusion of costs associated with several large transmission projects that were completed in 2013, including Devers-Colorado River, Eldorado-Ivanpah, and the Red Bluff substation. SCE expects to file its 2015 annual update with the FERC by December 1, 2014 and the proposed rates would be effective from January 1, 2015 to December 31, 2015. In August 2014, the FERC granted SCE's requested recovery of $14.5 million in abandoned plant costs incurred as a result of the CPUC's order directing SCE to underground the Chino Hills segment of the Tehachapi transmission project in the 2016 formula rate update.

Energy Efficiency Incentive Mechanism

In September 2014 SCE requested $35 million in energy efficiency incentives for performance pertaining to program years 2011, 2012 and 2013. For program year 2013, SCE requested an initial incentive payment of $14 million. The 2013 request is subject to potential refund pending the completion of the CPUC's financial and management audits for the 2013 program period. For program year 2012, SCE requested $16 million in incentives based on the results of the CPUC financial and management audit report. For program year 2011, SCE requested $5 million in incentives based on the results of the CPUC audit. The 2011 program year request was the follow-up to an opportunity provided by the CPUC in December 2013 for SCE to earn an additional $5 million based on the results of a subsequent audit of 2011 energy efficiency programs performed in 2014. There is no assurance that the CPUC will make an award for any year.

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, 2014 , SCE's 13-month weighted-average common equity component of total capitalization was 48.3% and the maximum additional dividend, taking into account declared but unpaid dividends, that SCE could pay to Edison International under this limitation was approximately $78 million, resulting in a restriction on net assets of approximately $13.01 billion.

SCE paid the $126 million dividend declared in June 2014 to Edison International during the third quarter. In August 2014, SCE declared another $126 million dividend to Edison International which will be paid in the fourth quarter of 2014. 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, 2014 , 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, 2014 .



(in millions)
Collateral posted as of September 30, 2014 ¹	$	240
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade	69
Posted and potential collateral requirements ²	$	309


¹	Net collateral provided to counterparties and other brokers consisted of $6 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $6 million of cash reflected in "Other current assets" on the consolidated balance sheets and $228 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, 2014 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level.

Edison International Parent and Other

Edison International Parent and Other's liquidity and its ability to pay operating expenses and dividends to common shareholders are dependent on dividends from SCE and access to bank and capital markets.

At September 30, 2014, Edison International Parent had a $580 million available under its $ 1.25 billion multi-year revolving credit facility. For further details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

Edison International may finance working capital requirements to support operations and capital expenditures with commercial paper or other borrowings, subject to availability in the capital markets.

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, 2014, Edison International Parent's consolidated debt to total capitalization ratio was 0.49 to 1.

As discussed in "Management Overview—EME Chapter 11 Bankruptcy," Edison International made an initial cash payment to the Reorganization Trust of $225 million in April 2014. In August 2014, Edison International entered into an amendment of the Settlement Agreement to finalize the remaining matters related to the EME Settlement including setting the EME Tax Attributes at $1.206 billion and the amount of the two installment payments, including interest, at $204 million due on September 30, 2015 and $214 million due on September 30, 2016. Assuming continuation of existing law and tax rates, Edison International also anticipates realization of the tax benefits over a period similar to the period for which it pays for them. Extension of bonus depreciation would defer realization of the benefits, and reduction of federal income tax rates could permanently reduce them. Pending the realization of the tax benefits, Edison International will finance the settlement from existing credit lines.

During the third quarter of 2014, indirect subsidiaries of Edison International entered into three non-recourse debt and tax equity financings designed to fund significantly all of their capital requirements for approximately 35 megawatts solar rooftop projects. The projects are expected to sell their output to third parties under long-term power purchase agreements with terms ranging from 15 to 20 years. Completion of the construction phase of these projects is expected by mid-2015.

Historical Cash Flows

Southern California Edison Company



	Nine months ended September 30,
(in millions)	2014			2013
Net cash provided by operating activities	$	2,513		$	2,163
Net cash provided by financing activities	390			1,196
Net cash used by investing activities	(2,908		)	(2,882		)
Net decrease in cash and cash equivalents	$	(5	)	$	477

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $350 million during the first nine months of 2014 compared to the same period in 2013 primarily due to the following:


•	$190 million decrease in balancing accounts primarily composed of:


•	$289 million increase resulting from lower ERRA balancing account undercollections for fuel and power procurement-related costs in 2014 compared to 2013. The change in the ERRA balancing account decreased operating cash flows by $565 million in 2014 compared to a decrease in operating cash flows of $854 million in 2013.


•	$216 million increase related to refunds from sellers of electricity and natural gas during the energy crisis in California in 2000 – 2001, see "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses."


•	$321 million decrease due to increased spending and lower funding of public purpose and energy efficiency programs.


•	$342 million decrease primarily due to refunding customers for a climate credit off set by greenhouse gas auction revenue.


•	$40 million decrease related to transmission revenue and access accounts.


•	higher cash inflow of approximately $380 million due to cash collected in excess of cost of service for San Onofre.


•	higher cash inflow of approximately $234 million due to the increase in pre-tax income, before depreciation and impairment and other charges, primarily driven by the increase in authorized revenue.


•	timing of cash receipts and disbursements related to working capital items. In addition, SCE had workforce reduction severance costs paid of $17 million and $132 million during the first nine months of 2014 and 2013, respectively.

Net Cash Provided by Financing Activities

The following table summarizes cash provided by financing activities for the nine months ended September 30, 2014 and 2013 . 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)	2014			2013
Issuances of first and refunding mortgage bonds, net	$	398		$	394
Long-term debt matured or repurchased	(405		)	(201		)
Issuances of preference stock, net	269			387
Redemptions of preference stock	—			(400		)
Short-term debt financing, net	502			1,178
Payments of common stock dividends to Edison International	(252		)	(240		)
Payments of preferred and preference stock dividends	(88		)	(81		)
Other	(34		)	159
Net cash provided by financing activities	$	390		$	1,196

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 $ 2.8 billion for both the nine months ended September 30, 2014 and 2013 , respectively, primarily related to transmission, distribution and generation investments. Net purchases of nuclear decommissioning trust investments and other was $105 million and $100 million for the nine months ended September 30, 2014 and 2013 , respectively.

Edison International Parent and Other

The table below sets forth condensed historical cash flow from operations for Edison International Parent and Other.



	Nine months ended September 30,
(in millions)	2014			2013
Net cash used by operating activities	$	(486	)	$	(93	)
Net cash provided by financing activities	515			79
Net cash used by investing activities	(28		)	(23		)
Net increase (decrease) in cash and cash equivalents	$	1		$	(37	)

Net Cash Used by Operating Activities

Net cash used by operating activities decreased $486 million for the first nine months of 2014 compared to 2013 due to:


•	$225 million initial cash payment to the Reorganization Trust in April 2014, see "Management Overview—EME Chapter 11 Bankruptcy" for further information;


•	Net payments of $175 million to the IRS, which included a $189 million deposit related to open tax years 2003 through 2006, see "Notes to Consolidated Financial Statements—Note 7. Income Taxes—Tax Disputes" for further information; and


•	the timing of payments and receipts relating to interest, operating costs and income taxes.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the first nine months of 2014 were as follows:


•	Paid $347 million of dividends to Edison International common shareholders;


•	Received $252 million of dividend payments from SCE; and


•	Borrowed $636 million of short-term debt (net) to fund $225 million initial cash payment to the Reorganization Trust in April 2014, fund the $189 million tax deposit made with the IRS and for investments and interim working capital requirements.

Net cash provided by 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.

Contingencies

SCE has contingencies related to San Onofre, San Gabriel Valley Windstorm Investigation, Four Corners Environmental Matters, 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, 2014, SCE had identified 20 material sites for remediation and recorded an estimated minimum liability of $110 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's 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 $753 million and $821 million at September 30, 2014 and December 31, 2013 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.

As of September 30, 2014, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:



	September 30, 2014
(in millions)	Exposure ²		Collateral			Net Exposure
S&P Credit Rating ¹
A or higher	$	339	$	—		$	339
A-	6		—			6
Not rated ³	2		(2		)	—
Total	$	347	$	(2	)	$	345


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 2013 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 2014. 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 2014 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 2013 Form 10-K.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Shaver Lake Dam Project Administrative Civil Liability Complaint

On October 2, 2014, SCE received a pre-issuance draft of an Administrative Civil Liability Complaint from the Central Valley Regional Water Quality Control Board alleging violations of certain permit conditions related to the installation of a dam liner to prevent water seepage at the Shaver Lake dam in 2011. The complaint alleges that during the draining of Shaver Lake in preparation for the installation of the liner, SCE failed to prevent the discharge of sediment into an adjoining creek, causing the death of fish in the lake and the creek. The Water Quality Control Board’s complaint seeks civil monetary sanctions. SCE disputes the allegations.

ITEM 2. UNREGISTERED 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 2014.



Period	(a) Total Number of Shares (or Units) Purchased ¹	(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, 2014 to July 31, 2014	131,027		$	56.59	—	—
August 1, 2014 to August 31, 2014	536,720		56.80		—	—
September 1, 2014 to September 30, 2014	730,271		63.95		—	—
Total	1,398,018		60.52		—	—

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

ITEM 6. EXHIBITS



Exhibit Number		Description

10.1		Amended and Restated Settlement Agreement between Southern California Edison Company, San Diego Gas & Electric Company, the Office of Ratepayer Advocates, The Utility Reform Network, Friends of the Earth, and the Coalition of California Utility Employees, dated September 23, 2014

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, 2014, filed on October 28, 2014, 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, 2014, filed on October 28, 2014, 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

________________________________________

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/ Connie J. Erickson

	Mark C. Clarke Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)		Connie J. Erickson Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

Date:	October 28, 2014	Date:	October 28, 2014

Exhibit 10.1

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA



Order Instituting Investigation on the Commission’s Own Motion into the Rates, Operations, Practices, Services and Facilities of Southern California Edison Company and San Diego Gas & Electric Company Associated with the San Onofre Nuclear Generating Station Units 2 and 3.	Investigation 12-10-013 (Filed October 25, 2012)
And Related Matters.	Application 13-01-016 Application 13-03-005 Application 13-03-013 Application 13-03-014

SONGS OII AMENDED AND RESTATED SETTLEMENT AGREEMENT BETWEEN SOUTHERN CALIFORNIA EDISON COMPANY, SAN DIEGO GAS & ELECTRIC COMPANY, THE OFFICE OF RATEPAYER ADVOCATES, THE UTILITY REFORM NETWORK, FRIENDS OF THE EARTH, AND THE COALITION OF CALIFORNIA UTILITY EMPLOYEES

Dated: September 23, 2014

Southern California Edison Company (“SCE”), San Diego Gas & Electric Company (“SDG&E”), the Office of Ratepayer Advocates (“ORA”), The Utility Reform Network(“TURN”), Friends of the Earth (“FOE”), and the Coalition of California Utility Employees(“CUE”) (hereinafter collectively referred to as the “Settling Parties”) agree to settle all claims, allegations, and liabilities in the Order Instituting Investigation Regarding San Onofre Nuclear Generating Station Units 2 and 3 , I.12-10-013, and all proceedings that have been consolidated therewith (including A. 13-01-016, A. 13-03-005, A. 13-03-013, and A. 13-03-014) (the “OII”),on the following terms and conditions, which shall only become effective on the Effective Date(as defined below).

This amended and restated settlement agreement (“Agreement”) is entered into as a compromise of disputed claims in order to minimize the time, expense, and uncertainty of further regulatory proceedings. ORA, TURN, FOE, and CUE agree to the following terms and conditions as a complete and final resolution of all claims against SCE and SDG&E in the OII, and SCE and SDG&E agree to these terms and conditions as a complete and final resolution of the OII. This Agreement constitutes the sole agreement between the Settling Parties concerning the subject matter of this Agreement.

As explained herein, the Settling Parties shall jointly submit this Agreement to the California Public Utilities Commission (“Commission” or “CPUC”) for approval. If the Effective Date does not occur within 90 days following the date of submission to the Commission, the Agreement shall be subject to termination by any of the Settling Parties upon written notice to the other Settling Parties. This document amends and restates the original settlement agreement submitted to the Commission on April 3, 2014.

THE PARTIES


1.1.	The parties to this Agreement are SCE, SDG&E, TURN, ORA, FOE and CUE.


1.2.	SCE is an investor owned public utility in the State of California and is subject to the jurisdiction of the Commission with respect to providing electric service to its customers.


1.3.	SDG&E is an investor owned public utility in the State of California and is subject to the jurisdiction of the Commission with respect to providing electric service to its customers.


1.4.	ORA is an independent division of the Commission whose statutory mission is to obtain the lowest possible rate for service consistent with reliable and safe service levels. In fulfilling this goal, ORA also advocates for customer and environmental protections.


1.5.	TURN is an independent, non-profit consumer advocacy organization that represents the interests of residential and small commercial utility customers.


1.6.	FOE is an advocacy organization whose mission is to protect the environment and promote the sustainable use of the planet’s resources.


1.7.	CUE is a coalition of unions whose members are employed at California electric utilities.

1.8.

The following entities have filed motions seeking party status in the OII, but are not parties to this Agreement: Women’s Energy Matters, the Alliance for Nuclear Responsibility, the Coalition to Decommission San Onofre, Ruth Henricks, the World Business Academy, the National Asian American Coalition, the Latino Business Chamber of Greater Los Angeles, the Ecumenical Center for Black Church Studies, the Chinese American Institute for Empowerment, the Nevada Hydro Company, Inc., City of Riverside, the Clean Coalition, the Western Power Trading Forum, the Direct Access Customer Coalition, the Alliance for Retail Energy Markets, Southern California Gas Company, Distributed Energy Consumer Advocates, the Utility Consumers’ Action Network, the Independent Energy Producers Association, the California Cogeneration Council, Noble Americas Energy Solutions LLC, Amerinet, Inc., Public Agency Coalition, and the State of California.

II.
DEFINITIONS


2.1.	AFUDC: Allowance for Funds Used During Construction.


2.2.	Agreement: This document and any appendices.


2.3.	ALJ: Administrative Law Judge.


2.4.	Authorized Cost of Debt: The rate of return on debt authorized by the CPUC for a given utility from time to time. This rate of return may change during any of the amortization periods set forth in this Agreement.


2.5.	Authorized Cost of Preferred Stock: The rate of return on preferred stock authorized by the CPUC for a given utility from time to time. This rate may change during any of the amortization periods set forth in this Agreement.


2.6.	Base Plant: The Net Book Value of all SONGS-related capital investments, except the SGRP, in the Utilities’ rate bases.


(a)	Base Plant includes the Net Book Value for all SONGS-related marine mitigation investments that the Utilities made in response to the California Coastal Commission’s directives to mitigate environmental impacts of SONGS, except the $22 million disallowed by the Commission in Decision No. 06-05-016.


(b)	Base Plant includes the Net Book Value for all SONGS-related NDBD&DD investments.


(c)	Base Plant does not include an adjustment for cash working capital.


(d)	Base Plant does not include the M&S Investment.


(e)	Base Plant does not include the Nuclear Fuel Investment.


2.7.	BRRBA: The generation sub-account of the Base Revenue Requirement Balancing Account, or its successor account.


2.8.	Original Cost: The initial outlay for an investment, equal to the gross sum of all recorded direct and indirect expenditures associated with the capital investment.

2.9.

Capital-Related Revenue Requirement: The total amount of revenue required by a utility to recover its capital investments and associated income and property taxes (including the effect of deferred taxes), including a return on those investments calculated in accordance with the utility’s authorized cost of capital and associated depreciation expenses computed in accordance with depreciation schedules authorized by the Commission.


2.10.	Commission or CPUC: The California Public Utilities Commission.


2.11.	Commission Approval: A decision of the Commission approving the Agreement in the form submitted without modification that has become final and is no longer subject to appeal.


2.12.	Consolidated Proceedings : All proceedings that have been consolidated with the OII, including A. 13-01-016, A. 13-03-005, A. 13-03-013, and A. 13-03-014.


2.13.	CWIP: CWIP means Construction Work In Progress or replacement projects (retirement work in progress or net salvage) recorded directly in accumulated depreciation.


(a)	Cancelled CWIP: The total Original Cost of CWIP associated with SONGS-related projects that began prior to the Effective Date but that will not enter service at any time after February 1, 2012.


(b)	Completed CWIP: The total Original Cost of CWIP associated with SONGS-related projects that began prior to the Effective Date and will enter service at any point after February 1, 2012, including all CWIP that will enter service after the Effective Date.


2.14.	Effective Date: The day of the Commission’s decision adopting the ratemaking proposal set forth in this Agreement.


2.15.	ERRA: Energy Resource Recovery Account, or its successor account.


2.16.	FERC: Federal Energy Regulatory Commission.


2.17.	Fuel Cancellation Costs: The total recorded costs (other than those costs that the Utilities are able to recover from the Nuclear Decommissioning Trusts) associated with cancelling SCE’s contracts entered into by SCE as the SONGS Operating Agent on behalf of itself and SDG&E to purchase nuclear fuel, including but not limited to the following costs:


(a)	Termination fees and other amounts paid to obtain a release of any obligations under fuel procurement contracts.


(b)	Amounts paid by SCE as Operating Agent for itself and on behalf of SDG&E to fuel procurement vendors pursuant to settlements, judgments, or arbitration awards related to disputes arising from SCE’s termination of alleged contractual obligations to purchase nuclear fuel.


(c)	Attorney’s fees and other litigation costs incurred on and after January 1, 2013 by SCE as Operating Agent for itself and on behalf of SDG&E in seeking to minimize its obligations under fuel procurement contracts through arbitrations, negotiations, and/or judicial or administrative proceedings.


2.18.	Fuel Net Proceeds: The total proceeds of all sales of nuclear fuel, net of costs incurred by SCE as Operating Agent for itself and on behalf of SDG&E in order to sell such nuclear fuel, including but not limited to:


(a)	Costs incurred in order to store the nuclear fuel inventory pending the sale; and


(b)	Costs incurred in order to render the nuclear fuel saleable.


2.19.	Incremental Inspection and Repair Costs: Those costs recorded by the Utilities as incremental expenses associated with SCE’s efforts to inspect and repair the damage at SONGS. This amount also includes the $11 million (100% share) in costs for inspection and repair of SONGS that SCE originally recorded as base O&M and subsequently re-classified as incremental O&M.


2.20.	Mitsubishi: Mitsubishi Heavy Industries, Ltd., related entities such as Mitsubishi Nuclear Energy Systems and Mitsubishi Heavy Industries America Inc., and any third party who has insured or indemnified any of these entities for any amounts owed to the Utilities in respect of the replacement steam generators.


2.21.	M&S Investment: The total Original Cost of materials and supplies investments associated with SONGS.


2.22.	M&S Net Proceeds: The total proceeds of all sales of materials and supplies, net of costs incurred by SCE in order to sell such materials and supplies.


2.23.	NDBD&DD: Nuclear Design Basis Documentation and Deferred Debits. NDBD costs are associated with SCE’s efforts to comply with the NRC’s mandate that SCE establish a nuclear design documentation system. DD costs are plant-related regulatory assets that


	resolve accounting differences in capitalization policies between CPUC and FERC jurisdictions regarding the commercial operation of SONGS.


2.24.	Net Book Value: Original Cost less the accumulated amortization and depreciation expenses, if any, associated with an investment.


2.25.	NEIL: Nuclear Energy Insurance Limited.


2.26.	NGBA: Non-fuel Generation Balancing Account, or its successor account.


2.27.	Non-O&M Balancing Account Expenses: All SONGS-related expenses for pensions, post-retirement benefits other than pensions, and short-term incentive compensation that are not recorded in FERC accounts 517-532.


2.28.	Non-O&M Expenses: All SONGS-related expenses recorded in FERC accounts 408, 924, 925, and 926 that are not :


(a)	Non-O&M Balancing Account Expenses;


(b)	Capitalized overhead; or


(c)	Recorded in FERC accounts 517-532.


2.29.	Nuclear Decommissioning Trusts: The trusts established by the Utilities and approved by the CPUC pursuant to the Nuclear Facilities Decommissioning Act of 1985, Cal. Pub. Util. Code Sec. 8321 et seq., for the purpose of covering costs associated with decommissioning SONGS.

2.30.

Nuclear Fuel Investment: The Net Book Value of all nuclear fuel (including in-core fuel and pre-core fuel), plus all Fuel Cancellation Costs. To the extent that SCE, as Operating Agent on behalf of itself and on behalf of SDG&E, incurs additional Fuel Cancellation Costs after the date of execution of this Agreement, those costs will be added to the Nuclear Fuel Investment at the time they are incurred.


2.31.	NRC: Nuclear Regulatory Commission.


2.32.	O&M: Operations and Maintenance.


2.33.	OII: Order Instituting Investigation. As used in this Agreement, the term “OII” shall refer to the proceeding initiated by the Commission in I. 12-10-013, and all Consolidated Proceedings.


2.34.	Operating Agent: SCE is the Operating Agent responsible for the performance of the operation and maintenance of SONGS.


2.35.	ORA: The Office of Ratepayer Advocates or its successor division.


2.36.	SCE: Southern California Edison Company.


2.37.	SDG&E: San Diego Gas & Electric Company.


2.38.	Settling Parties/Settling Party: SCE, SDG&E, ORA, TURN, FOE, and CUE, or any of them.


2.39.	SGRP: Steam Generator Replacement Project.


2.40.	SONGS: San Onofre Nuclear Generating Station.


2.41.	SONGSBA: SDG&E’s San Onofre Nuclear Generating Station O&M Balancing Account.


2.42.	SONGS Litigation Balance: The total SONGS Litigation Recoveries, net of SONGS Litigation Costs.


2.43.	SONGS Litigation Costs: All litigation costs recorded since January 31, 2012, including but not limited to fees paid to outside attorneys and experts, associated with pursuing and preparing to pursue SONGS Litigation Recoveries.

2.44.

SONGS Litigation Recoveries: Any amounts received (whether by settlement, judicial order, arbitration award, or any other recovery) by the Utilities from NEIL and/or Mitsubishi or their respective affiliates in connection with the Utilities’ efforts to pursue recovery of amounts in respect of the failure of the steam generators and subsequent permanent shut down of SONGS. Any amounts obtained by the City of Riverside are not subject to this Agreement.


2.45.	SONGSMA: SCE’s San Onofre Nuclear Generating Station Memorandum Account.


2.46.	SONGSOMA: Either Utility’s San Onofre Nuclear Generating Station Outage Memorandum Account, including SDG&E’s SONGS OMA.


2.47.	TURN: The Utility Reform Network.


2.48.	U2C17 RFO: The refueling and maintenance outage for SONGS Unit 2 that was intended to last from January 10, 2012, until March 5, 2012.


2.49.	Utility/Utilities: SCE and SDG&E, or either of them.

III.
GENERAL RECITALS


3.1.	SCE owns a 78.21% share of SONGS. SDG&E owns a 20% share of SONGS. The City of Riverside owns a 1.79% share of SONGS.


3.2.	In Decision No. 05-12-040, the Commission approved SCE’s application to replace the steam generators in SONGS Units 2 and 3.


3.3.	In Decision No. 06-11-026, the Commission found that SDG&E’s participation in the SGRP was reasonable and approved an unopposed settlement agreement, including

SDG&E’s ownership share of the maximum allowable 100%, 2004$, level of the SGRP cost plus SDG&E’s internal costs.


3.4.	In January 2010, SCE replaced the steam generators in SONGS Unit 2. In January 2011, SCE replaced the steam generators in SONGS Unit 3.


3.5.	The replacement steam generators in Units 2 and 3 were designed and manufactured by Mitsubishi.


3.6.	On January 10, 2012, SONGS Unit 2 was removed from service for a scheduled refueling and maintenance outage that was expected to end on March 5, 2012.


3.7.	On January 31, 2012, SONGS Unit 3 was taken offline because station operators at SONGS detected a leak in a steam generator tube.


3.8.	In early February, 2012, inspections of Unit 2 steam generators showed accelerated tube wear. This tube wear caused unexpected and extensive property damage to Unit 2’s steam generators


3.9.	In February and March, 2012, inspections in Unit 3 revealed extensive wear on the Unit’s steam generator tubes. Some of this wear was caused by the steam generator tubes rubbing against each other (“tube-to-tube wear”). This tube-to-tube wear caused unexpected and extensive property damage to Unit 3’s steam generators.


3.10.	On March 27, 2012, the NRC issued a Confirmatory Action Letter confirming SCE’s commitment not to restart either Unit 2 or Unit 3 until the source of the tube wear was understood and SCE had confidence that the units could be safely restarted.


3.11.	Further inspections of the Unit 2 steam generators revealed more property damage in the form of early indications of tube-to-tube wear. SCE formally notified the NRC of SCE’s finding of tube-to-tube wear in Unit 2 on April 20, 2012.

3.12.

On November 1, 2012, the Commission issued an Order Instituting Investigation Regarding San Onofre Nuclear Generating Station Units 2 and 3. (I. 12-10-013.) The Order stated that the Commission intended to examine “the causes of the outages, the utilities’ responses, the future of the SONGS units, and the resulting effects on the provision of safe and reliable electric service at just and reasonable rates.” The Order also set SONGS-related rates subject to refund as of January 1, 2012, and directed that the Utilities establish a memorandum account (the SONGSOMA) for the purpose of tracking those costs.

3.13.

On December 10, 2012, the Commission issued Decision No. 12-11-051, which resolved SCE’s 2012 General Rate Case. Decision No. 12-11-051 directed SCE to establish a memorandum account (the “SONGSMA”), effective January 1, 2012, to track certain SONGS-related costs. The Commission further ordered SCE to file a reasonableness review application for post-2011 expenses recorded in the SONGSMA by January 31, 2013. In accordance with this directive, SCE filed A. 13-01-016 on January 31, 2013. A. 13-01-016 has been consolidated with this OII.

3.14.

In D.12-11-051, the Commission also made SDG&E subject to the same conditional refund of SDG&E’s share of the SONGS-related O&M and capital costs. (See D.12-11-051 at 40-41, Finding of Fact 36, Conclusions of Law 21 and 22, Ordering Paragraphs 10 and 11.) On March 19, 2013, SDG&E filed A.13-03-005 requesting a reasonableness determination of SDG&E’s internal SONGS costs incurred during 2012 and capital expenses (excluding the SGRP) that were invoiced by SCE to SDG&E, including SCE’s overheads, and tracked in SDG&E’s SONGSOMA. A.13-03-014 has been consolidated with this OII.


3.15.	On January 28, 2013, the Assigned Commissioner and ALJ issued a Scoping Memo and Ruling. The Scoping Memo divided the OII into phases and provided that the OII would examine the following issues:


(a)	In Phase 1, the Commission would examine:


(i)	“Nature and effects of the steam generator failures in order to assess the reasonableness of SCE’s consequential actions and expenditures (e.g., was it reasonable to remove fuel from unit #3).”


(ii)	“Whether 2012 SONGS-related expenses recorded in the SONGSMA are reasonable and necessary, including,


(A)	100% of O&M, including segregated safety-related costs;


(B)	100% of cost-savings from personnel reductions and other avoided costs;


(C)	100% of maintenance and refueling outage expenses; and


(D)	100% of capital expenditures.”


(iii)	“A review of the reasonableness and effectiveness of SCE’s actions and expenditures for community outreach and emergency preparedness related to the SONGS outages.”


(iv)	“Other issues as necessary to determine whether SCE should refund any rates preliminarily authorized in the 2012 GRC, in light of the changed facts and circumstances of the unit outages; and if so, when the refunds should occur.”


(b)	In Phase 2, the Commission would examine “whether any reductions to SCE’s rate base and SCE’s 2012 revenue requirement are warranted or required due to the extended SONGS outages.”


(c)	In Phase 3, the Commission would examine “causes of the [steam generator] damage and allocation of responsibility, whether claimed SGRP expenses are reasonable, including review of utility-proposed repair and/or replacement cost proposals using cost-effectiveness analysis and other factors.”


(d)	In Phase 4, if necessary, the Commission would examine “whether SCE’s 2013 revenue requirement should be adjusted to reflect lower-than forecast O&M, Capex, replacement power costs, and other SONGS expenses.”


3.16.	From December, 2012, through April, 2013, the Settling Parties exchanged testimony regarding Phase 1 issues.

3.17.

On March 15, 2013, SCE filed A. 13-03-005, seeking Commission approval to include the recorded capital costs of the SGRP permanently in rates. SCE’s testimony in support of this application established that the total recorded cost of the SGRP was $768.5 million in nominal dollars (100% share). SCE’s testimony in support of this application also established that the total recorded cost of the SGRP, adjusted for inflation using the Handy-Whitman index for fabrication and construction costs and the Commission-approved nuclear decommissioning burial escalation rates for burial costs, was $612.1 million in 2004 dollars (100% share). A. 13-03-005 has been consolidated with this OII.


3.18.	On March 18, 2013, SDG&E filed A. 13-03-014, seeking Commission approval to include SGD&E’s share of recorded capital costs of the SGRP permanently in rates. A. 13-03-014 has been consolidated with this OII.


3.19.	On April 2, 2013, SCE served testimony addressing the energy-market related impact of the SONGS outages in its ERRA compliance review proceeding (A. 13-04-001). On May 1, 2003, SDG&E served testimony addressing the energy-market related impact of the SONGS outages in I. 12-10-013.


3.20.	On April 19, 2013, ALJs Darling and Dudney issued an Order clarifying that the topics identified in the January 28, 2013, Scoping Memo applied equally to SCE and SDG&E.


3.21.	On May 6, 2013, by e-mail ruling, ALJ Dudney ruled that the OII would consider the issue of “what replacement power was purchased by the utilities in 2012 as a consequence of the SONGS outages.” ALJ Dudney scheduled separate evidentiary hearings to address this “replacement power” issue. The phase of the OII addressing this issue came to be known as Phase 1A.


3.22.	ALJ Darling held an evidentiary hearing on Phase 1 issues from May 13, 2013, until May 17, 2013. The Settling Parties each submitted Opening and Reply Briefs on Phase 1 issues.

3.23.

On June 7, 2013, SCE permanently retired SONGS Units 2 and 3. SCE had determined that Mitsubishi made errors in designing and manufacturing the replacement steam generators for Units 2 and 3. SCE determined that these errors caused deficiencies in design, manufacturing, and workmanship that prevented SCE from safely operating Units 2 or 3 as intended and contracted for. SCE determined that, because Mitsubishi had not proposed a viable plan to repair or replace the replacement steam generators in a timely manner, and because of the significant uncertainty as to whether or when Unit 2 would be permitted to restart even at partial power for a reduced operating period, it was no longer prudent to continue to pursue restart or repair.


3.24.	On July 1, 2013, ALJs Darling and Dudney issued a Ruling on Miscellaneous Scheduling and Procedural Issues and Notice of Phase 2 Prehearing Conference. The ruling provided the following “statement” of the scope of Phase 2:


(a)	What are the values of SONGS assets in rate base, and which of these assets should be removed from rate base pursuant to Public Utilities Code § 455.5, as of November 1, 2012, or a later date if any such asset became not “used and useful” after November 1, 2012?


(b)	What are the related Operations and Maintenance costs associated with the assets removed from rate base according to [the issue] above?


(c)	Any other issues relevant to the application of § 455.5 to the SONGS outage.


3.25.	In July, 2013, the Settling Parties exchanged testimony on Phase 1A issues.


3.26.	On July 22, 2013, ALJs Darling and Dudney further specified that Phase 1A would address “the method for calculating the cost of replacement power during 2012 due to the SONGS outage. This scope includes developing a formula/method for the calculation of costs (capacity, energy, foregone sales, and congestion) and establishing what values should be entered in to that formula.”


3.27.	From July, 2013, until September, 2013, the Settling Parties exchanged testimony on Phase 2 issues.


3.28.	ALJ Dudney held an evidentiary hearing on Phase 1A from August 5, 2013, until August 6, 2013. The Settling Parties each filed Opening and Reply Briefs on Phase 1A issues.


3.29.	ALJs Dudney and Darling held an evidentiary hearing on Phase 2 issues from October 7, 2013, until October 11, 2013. The Settling Parties each filed Opening and Reply Briefs on Phase 2 issues.


3.30.	Throughout the proceeding, SCE responded to 928 data request questions propounded by the parties to the OII. SDG&E similarly responded to data request questions propounded to it by the parties to the OII.


3.31.	On October 16, 2013, SCE as the Operating Agent and Edison Material Supply LLC (“EMS”) filed a Request for Arbitration against Mitsubishi pursuant to the arbitration clause in the contract between EMS and Mitsubishi. Through this arbitration, which is ongoing as of the date of this Agreement, SCE and EMS are seeking recovery from Mitsubishi based on the non-operation of SONGS Units 2 and 3.

3.32.

On July 18, 2013, SDG&E filed a complaint in California Superior Court against Mitsubishi seeking to recover damages SDG&E has incurred and will incur related to the defects in the steam generators. This action was later removed to Federal District Court. On August 8, 2013, Mitsubishi filed a motion to stay the action pending arbitration and on March 14, 2014, the Court issued an order granting Mitsubishi’s motion on the

condition that SDG&E must be able to fully assert its own claims in an arbitration proceeding.


3.33.	The Utilities have also submitted claims to NEIL based on their assessments that both SONGS units sustained accidental property damage. SCE has submitted proofs of loss under insurance policies covering SONGS and is continuing to pursue recovery as of the date of this Agreement.


3.34.	On November 19, 2013, ALJs Darling and Dudney issued a Proposed Decision on Phase 1 and Phase 1A issues. Each of the Settling Parties submitted Opening Comments on the Proposed Decision on December 9, 2013. Each of the Settling Parties submitted Reply Comments on the Proposed Decision on December 16, 2013.


3.35.	On January 15, 2014, the Commission held an all-party meeting to discuss the Proposed Decision on Phase 1 and Phase 1A issues.


3.36.	SCE’s share of the Net Book Value of the SGRP was $597 million as of February 1, 2012, including CWIP. SDG&E’s share of the Net Book Value of the SGRP was $160.4 million as of February 1, 2012, including CWIP.


3.37.	SCE’s share of Base Plant was $622 million as of February 1, 2012, excluding CWIP. SDG&E’s share of Base Plant was $165.6 million as of February 1, 2012, excluding CWIP.


3.38.	SCE’s share of the Nuclear Fuel Investment was $477 million as of December 31, 2013, exclusive of any paid or accrued Fuel Cancellation Costs. SDG&E’s share of the Nuclear Fuel Investment was $115.8 million as of December 31, 2013, exclusive of any paid or accrued Fuel Cancellation Costs.


3.39.	SCE’s share of the M&S Investment was $99 million as of December 31, 2013. SDG&E’s share of the M&S Investment was $10.4 million as of December 31, 2013.


3.40.	SCE’s share of Cancelled CWIP is estimated at $153 million as of December 31, 2013. Subject to an additional reconciliation with SCE, SDG&E’s Cancelled CWIP amounts will be provided pursuant to section 6.1 hereof, subject to ORA’s and TURN’s prerogative stated in the last sentence thereof.


3.41.	SCE’s share of Completed CWIP is estimated at $302 million as of December 31, 2013. Subject to an additional reconciliation with SCE, SDG&E’s Completed CWIP amounts will be provided pursuant to section 6.1 hereof, subject to ORA’s and TURN’s prerogative stated in the last sentence thereof.


3.42.	SCE’s share of O&M costs recorded in connection with the U2C17 RFO is $41.1 million, which consists of $4.9 million recorded in 2011, $35.3 million recorded in 2012, and $0.9 million recorded in 2013. SDG&E’s share of O&M costs recorded in connection with the U2C17 RFO as calculated by SCE is $9.3 million.


3.43.	Decision No. 12-11-051 provisionally authorized $387.4 million (100% share) in base O&M costs for the year 2012 and $397.6 million (100% share) in base O&M costs for the year 2013.

3.44.

In 2012, SCE recorded $99 million (SCE share) in Incremental Inspection and Repair Costs in excess of the amount of base O&M provisionally authorized in Decision No. 12-11-051. In 2012, SCE estimated that SDG&E paid $27.0 million in total Incremental Inspection and Repair Costs, including SCE overheads and portions allocated to Base and Incremental O&M. SDG&E’s base O&M provisionally authorized in Decision No. 12-11-051 and D.13-05-010 was greater than the total amount of recorded costs including overheads, as applicable to SDG&E.


3.45.	SDG&E recorded $141.6 million, including overheads paid to SCE, to its SONGSBA in 2012; $27.0 million, including overheads paid to SCE, was defined by SCE as Incremental Inspection and Repair Costs in Base and Incremental O&M.


3.46.	In 2013, SCE’s share of recorded base O&M costs was $241 million and SCE’s share of recorded Incremental Inspection and Repair Costs was $12 million.


3.47.	SDG&E recorded $105.0 million, including overheads paid to SCE, to its SONGSBA in 2013.


3.48.	SCE’s total amount of deferred taxes on SONGS investment (excluding investment in the SGRP) as of Feb 1, 2012, was $152 million. SDG&E’s total amount of deferred taxes on SONGS investment (excluding investment in the SGRP) as of February 1, 2012 is estimated at $4.5 million.


3.49.	On March 27, 2014, the Settling Parties held a settlement conference in accordance with Rule 12.1(b) of the Commission’s Rules of Practice and Procedure.


3.50.	On April 3, 2014, the Settling Parties filed and served a Joint Motion for Adoption of Settlement Agreement.


3.51.	In a ruling issued on September 5, 2014, Commissioner Florio and ALJs Darling and Dudney proposed several modifications to the settlement agreement filed on April 3, 2014.


3.52.	The Settling Parties have voluntarily agreed to adopt the proposed modifications, and those modifications are reflected in this Agreement.


3.53.	The General Recitals described in Sections 3.1 through 3.52 provide factual background for this Agreement, and the Commission is not asked to confirm the General Recitals as true.

IV.

AMENDED AND RESTATED SETTLEMENT AGREEMENT TERMS AND CONDITIONS

4.1.

In consideration of the mutual obligations, promises, covenants and conditions contained herein, the Settling Parties agree to support approval by the Commission of this Agreement, as further described herein, and to support this Agreement in its entirety before any regulatory agency or court of law where this Agreement, its meaning or effect is an issue, and no Settling Party shall take or advocate for, either directly, or indirectly through another entity, any action that would have the effect of modifying or abrogating the terms of this Agreement.


4.2.	Capital-Related Revenue Requirement for the SGRP


(a)	The Capital-Related Revenue Requirement for the SGRP will be terminated as of February 1, 2012.


(b)	The Utilities shall refund to ratepayers all amounts collected in rates as the Capital-Related Revenue Requirement for the SGRP for all periods on and after February 1, 2012. These amounts shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.


(c)	The Utilities will retain all amounts collected in rates as the Capital-Related Revenue Requirements for the SGRP for periods prior to February 1, 2012.


(d)	The Utilities shall not recover in rates the Net Book Value of the SGRP as of February 1, 2012.


4.3.	Base Plant


(a)	The Utilities’ respective shares of Base Plant will be removed from each Utility’s respective rate base as of February 1, 2012. The Utilities will retain all amounts collected in rates in respect of Capital-Related Revenue Requirements for Base Plant for periods prior to February 1, 2012.


(b)	As of February 1, 2012, the Utilities will amortize Base Plant in rates as a regulatory asset ratably over 10 years.


(i)	This amortization period will begin on February 1, 2012, and will end on February 1, 2022.

(ii)

The Utilities have already collected amounts in rates in respect of Capital-Related Revenue Requirements for Base Plant for periods on and after February 1, 2012. To the extent that these amounts collected exceed the amounts permitted by this Agreement for periods on and after February 1, 2012, the Utilities shall refund the excess to ratepayers. These excess amounts shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.

(c)

During the amortization period set forth in Section 4.3(b)(i) of this Agreement, each Utility shall earn a return on its respective share of unrecovered Base Plant, adjusted for deferred taxes. Each Utility’s rate of return on unrecovered Base Plant shall be calculated as the Utility’s Authorized Cost of Debt plus 50% of the Utility’s Authorized Cost of Preferred Stock, weighted by the amount of debt and preferred stock in the Utility’s authorized ratemaking capital structure. For the avoidance of doubt, the rate of return on common equity shall not be considered.


(i)	The methodology for computing Base Plant to adjust for deferred taxes is illustrated in Appendix A to this Agreement.


(d)	The Settling Parties agree that the Authorized Cost of Debt and the Authorized Cost of Preferred Stock described in Section 4.3(c) of this Agreement are floating rates that shall vary based on the rates authorized by the Commission at any given time.


(e)	Pursuant to the method of calculating the return on Base Plant set forth in Section 4.3(c) of this Agreement, SCE will earn a rate of return of 2.95% on unrecovered Base Plant for the period February 1, 2012, through December 31, 2012. This rate of return is equal to:


(i)	6.22% weighted by the amount of debt in SCE’s authorized ratemaking capital structure; plus


(ii)	50% of 6.01% weighted by the amount of preferred stock in SCE’s authorized ratemaking capital structure.


(f)	Pursuant to the method of calculating the return on Base Plant set forth in Section 4.3(c) of this Agreement, SCE will earn a rate of return of 2.62% on unrecovered Base Plant for the years 2013 and 2014. This rate of return is equal to:


(i)	5.49% weighted by the amount of debt in SCE’s authorized ratemaking capital structure; plus


(ii)	50% of 5.79% weighted by the amount of preferred stock in SCE’s authorized ratemaking capital structure.


(g)	Pursuant to the method of calculating the return on Base Plant set forth in Section 4.3(c) of this Agreement, SDG&E will earn a rate of return of 2.75% on unrecovered Base Plant for the period February 1, 2012, through December 31, 2012. This rate of return is equal to:


(i)	5.62% weighted by the amount of debt in SDG&E’s authorized ratemaking capital structure; plus


(ii)	50% of 7.25% weighted by the amount of preferred stock in SDG&E’s authorized ratemaking capital structure.


(h)	Pursuant to the method of calculating the return on Base Plant set forth in Section 4.3(c) of this Agreement, SDG&E will earn a rate of return of 2.35% on unrecovered Base Plant for the years 2013 and 2014. This rate of return is equal to:


(i)	5.00% weighted by the amount of debt in SDG&E’s authorized ratemaking capital structure; plus


(ii)	50% of 6.22% weighted by the amount of preferred stock in SDG&E’s authorized ratemaking capital structure.

(i)

The Settling Parties agree that the rates of return set forth in Section 4.3(e)-(h) of this Agreement do not reflect income taxes associated with the Utilities’ preferred equity return. Notwithstanding that fact, the Utilities will recover all income tax expenses associated with each Utility’s preferred equity return. Each Utility will therefore factor in a gross-up for this income tax when calculating its revenue requirement. This gross-up would be calculated in compliance with the Commission’s customary practices according to decisions rendered in OII 24, which was closed by Decision No. 84-05-036 (1984). In addition, the revenue requirement shall include franchise fees and uncollectibles.


(j)	Notwithstanding Section 4.3(a) of this Agreement, the Utilities shall recover in rates all property taxes paid with respect to Base Plant, including amounts paid after February 1, 2012. To the extent rates include a forecast for these property taxes, the recovery shall be trued up to recorded amounts.


4.4.	Financing

(a)

At its option, each Utility may select to exclude the regulatory assets to be amortized pursuant to this Agreement when measuring each Utility’s ratemaking capital structure for any purpose. In other words, the regulatory assets may be financed solely with debt, and the capital supporting these assets will not be recognized in determining each Utility’s ratemaking capital structure, if the Utility so chooses. If a Utility selects this option and elects to finance the regulatory assets with debt:


(i)	Except as provided in Section 4.4(a)(ii), the financing of the regulatory assets with debt will not affect the rates of return calculated as set forth in Section 4.3 and will not be used to establish the Utility’s cost of capital; and

(ii)

The Utility will credit ratepayers 50% of the savings reflected in the difference between the actual cost of financing the regulatory assets and the amount yielded by applying the rate of return calculated pursuant to 4.3(c), as the same may be updated from time to time. The Utility will establish one or more balancing accounts to track this difference. Fifty percent of any balance in the account shall be credited to BRRBA (for SCE) or NGBA (for SDG&E) annually.


(b)	In addition, if a Utility selects this option, the Settling Parties will support exclusion, prospectively from the date of financing the regulatory assets, of the capital financing of these regulatory assets in determining the Utility’s overall AFUDC rate calculation at both the CPUC and FERC.


4.5.	M&S Investment

(a)

Each Utility’s respective share of the M&S Investment as of the last day of the month prior to the Effective Date shall be amortized as a regulatory asset ratably over the amortization period set forth for Base Plant in Section 4.3(b)(i) of this Agreement, and shall earn a rate of return during that amortization period equal to the rate set forth for Base Plant in Section 4.3(c) of this Agreement.


(b)	To the extent that the Utilities are able to sell assets associated with the M&S Investment, and in order to incentivize the Utilities to do so, the following incentive mechanism shall be adopted notwithstanding the terms set forth in Section 4.5(a) of this Agreement:


(i)	The Utilities shall retain their respective shares of 5% of all M&S Net Proceeds; and


(ii)	The Utilities shall credit to their ratepayers their respective shares of the remaining 95% of all M&S Net Proceeds.


(c)	On a monthly basis, the Utilities shall distribute the ratepayers’ portion of the proceeds of all sales of materials and supplies by providing credits to SCE’s BRRBA and SDG&E’s NGBA.

(d)

The Settling Parties agree that the Utilities will, to the extent permitted by applicable tax laws without penalty and CPUC action, seek reimbursement of the M&S Investment from the Nuclear Decommissioning Trusts rather than recovering this investment through rates. The Utilities will not amortize in rates any portion of the M&S Investment that has been paid for by the Nuclear Decommissioning Trusts. To the extent the Utilities are unable to obtain full reimbursement of the M&S Investment from the trusts, the unreimbursed investments shall be added to the regulatory asset described in Section 4.5(a) of this Agreement (i.e., the M&S Investment) regardless of whether the inventory associated with that asset is used by the Utilities.


4.6.	Nuclear Fuel Investment


(a)	The Nuclear Fuel Investment as of the last day of the month prior to the Effective Date shall be amortized as a regulatory asset ratably over the amortization period set forth for Base Plant in Section 4.3(b)(i) of this Agreement.

(b)

During the amortization period set forth in Section 4.6(a) of this Agreement, the Utilities shall earn a rate of return on their respective shares of the unrecovered balance of the Nuclear Fuel Investment. This rate of return shall be equal to the cost of commercial paper (as defined in Section ZZ, 2. j of the preliminary statement of SCE’s CPUC tariffs [or its successor] and in Section I.E.3 of the preliminary statement of SDG&E’s CPUC tariffs [or its successor]) throughout the amortization period. The Settling Parties agree that the cost of commercial paper may change during the amortization period. The Settling Parties further agree that the rate that each Utility shall earn on the unrecovered balance of the Nuclear Fuel Investment will float with the commercial paper rate throughout the amortization period, such that each Utility will recover its actual costs of financing the Nuclear Fuel Investment with commercial paper, as those costs are incurred.

(c)

The Settling Parties agree that, as of the date of execution of this Agreement, SCE still has outstanding alleged contractual obligations to purchase nuclear fuel. The Settling Parties further agree that Fuel Cancellation Costs incurred after the last day of the month prior to the Effective Date will be added to the regulatory asset described in Section 4.6(a) of this Agreement (i.e., the Nuclear Fuel Investment) as those costs are incurred.


4.7.	Incentive Mechanisms For Mitigation Of Nuclear Fuel Costs


(a)	To the extent that SCE is able to sell any portion of its current nuclear fuel inventory, and in order to incentivize SCE to do so, the following incentive mechanism shall be adopted notwithstanding the terms set forth in Section 4.6 of this Agreement:


(i)	The Utilities shall retain their respective shares of 5% of all Fuel Net Proceeds; and


(ii)	The Utilities shall credit to their ratepayers their respective shares of the remaining 95% of all Fuel Net Proceeds.

(b)

Upon each sale of nuclear fuel, the Utilities shall distribute the ratepayers’ portion of the Fuel Net Proceeds by reducing the amount of the regulatory asset described in Section 4.6(a) of this Agreement (i.e., the Nuclear Fuel Investment). The effect of this reduction to the Nuclear Fuel Investment shall be to decrease the yearly amount of the revenue requirement for Nuclear Fuel Investment. This reduction to the regulatory asset shall not affect the amortization period for Base Plant described in Section 4.3(b)(i) of this Agreement.


(c)	To the extent that SCE, as Operating Agent on its own behalf and on behalf of SDG&E, is able to minimize the Fuel Cancellation Costs incurred after the date of execution of this Agreement, and in order to incentivize SCE to do so, the following incentive mechanism applicable to the Utilities shall be adopted notwithstanding the terms set forth in Section 4.6 of this Agreement:


(i)	The regulatory asset described in Section 4.6(a) of this Agreement (i.e., the Nuclear Fuel Investment) shall be increased by 5% of the difference between:


(A)	The sum of all amounts stated as SCE’s purchase obligations (as Operating Agent on its own behalf and on behalf of SDG&E) in outstanding nuclear fuel contracts, on the one hand; and


(B)	SCE’s total recorded Fuel Cancellation Costs (as Operating Agent on its own behalf and on behalf of SDG&E), on the other hand.

(ii)

The Utilities shall each establish a memorandum account to determine the yearly amount of the incentive described in Section 4.7(c)(i). In order to account for all recorded costs and cancelled obligations since January 31, 2012, each Utility shall establish this memorandum account as of January 31, 2012. Every time SCE cancels a nuclear fuel contract (or is otherwise relieved from its obligations thereunder), the Utilities shall record a positive value in this memorandum account equal to the amount stated in the contract as SCE’s purchase obligation. The Utilities shall also record all Fuel Cancellation Costs, as they are incurred, as negative values in this account. If there is a negative balance in either Utility’s account at the end of a given year, the negative balance will be carried over to the next year. If there is a positive balance in either Utility’s account at the end of a given year, the Utility shall increase the regulatory asset described in Section 4.6(a) of this Agreement (i.e., the Nuclear Fuel Investment) by 5% of this balance. The effect of any increase to the regulatory asset pursuant to this incentive mechanism shall be to increase the yearly amount of the revenue requirement for Nuclear Fuel Investment. This increase to the regulatory asset shall not affect the amortization period for Base Plant described in Section 4.3(b)(i) of this Agreement. Positive balances shall not carry over from one year to the next; instead, the account balance shall be reset to zero on the first of the year following any increase to the regulatory asset pursuant to this Section of the Agreement.


4.8.	CWIP


(a)	The Utilities will recover in rates the full amounts recorded as SONGS-related CWIP, including the full amounts of both Cancelled CWIP and Completed CWIP. The CWIP balance shall be recovered as follows:


(i)	For Cancelled CWIP:


(A)	An AFUDC amount for the Cancelled CWIP balance will be applied from the date of the first recorded amount of Cancelled CWIP until January 31, 2012. The AFUDC rate shall be equal to the authorized AFUDC rate in effect at the time.


(B)	The AFUDC amount, as calculated in Section 4.8(a)(i)(A) of this Agreement, shall be added to the balance for Cancelled CWIP.


(C)	The Cancelled CWIP balance (including the AFUDC amount) as of the last day of the month prior to the Effective Date shall be amortized as a regulatory asset ratably over the amortization period set forth for Base Plant in Section 4.3(b)(i) of this Agreement.


(D)	During the amortization period set forth in Section 4.8(a)(i)(C) of this Agreement, the Cancelled CWIP balance (plus all accumulated AFUDC), adjusted for deferred taxes if applicable, shall earn a rate of return equal to the rate set forth for Base Plant in Section 4.3(c) of this Agreement.


(ii)	For Completed CWIP:


(A)	An AFUDC amount for the Completed CWIP balance will be applied from the date of the first recorded amount of Completed CWIP until the last day of the month prior to the Effective Date. The AFUDC rate will be as follows:


(1)	For the period from the date of the first recorded amount of Completed CWIP until January 31, 2012, the AFUDC rate shall be equal to the authorized AFUDC rate in effect at the time.


(2)	For the period from February 1, 2012, until the date on which the associated asset was placed into service or the Effective Date (whichever is earlier) , the AFUDC rate shall be equal to the rate set forth for Base Plant in Section 4.3(c) of this Agreement.


(B)	The AFUDC amount, as calculated in Section 4.8(a)(ii)(A) of this Agreement, shall be added to the balance for Completed CWIP.


(C)	The Completed CWIP balance (including all accumulated AFUDC) as of the last day of the month prior to the Effective Date shall be amortized as a regulatory asset ratably starting on the date on which the associated asset was placed into service or the Effective Date (whichever is earlier) and ending on February 1, 2022.


(D)	During the amortization period set forth in Section 4.8(a)(ii)(C) of this Agreement, the Completed CWIP balance (plus all accumulated AFUDC), adjusted for deferred taxes if applicable, shall earn a rate of return equal to the rate set forth for Base Plant in Section 4.3(c) of this Agreement

(b)

The Settling Parties agree that the Utilities will, to the extent permitted by applicable tax laws without penalty and CPUC action, seek reimbursement of Completed CWIP that enters service after June 7, 2013, as expenses from the Nuclear Decommissioning Trusts rather than recovering this investment through rates. The Utilities will not amortize in rates any portion of the Completed CWIP balance that has been paid for by the Nuclear Decommissioning Trusts.


4.9.	O&M and other costs


(a)	The Utilities will retain all rate revenue collected for 2012 pursuant to the revenue requirement for SONGS base O&M (100% share) provisionally authorized in Decision No. 12-11-051, which adopted SCE’s Test Year 2012 General Rate Case application, and in Decision No. 13-05-010, which adopted SDG&E’s Test Year 2012 General Rate Case application.


(i)	The Utilities may apply 2012 revenues to defray base O&M costs recorded in their respective SONGSOMA for 2012, as well as costs recorded in their respective SONGSOMA for 2012 associated with severance of employees at SONGS or resulting from the permanent shut down at SONGS.

(ii)

The Utilities may also apply 2012 revenues to defray Incremental Inspection and Repair Costs recorded in their respective SONGSOMA for 2012, except that the Utilities shall not be allowed to recover in rates any Incremental Inspection and Repair Costs incurred in 2012 in excess of the revenue requirement for base O&M costs (100% share) provisionally authorized in Decision No. 12-11-051 and Decision No. 13-05-010.


(iii)	Provided however, if applicable, SDG&E will refund any amount of provisionally authorized O&M in excess of total recorded O&M costs incurred in 2012 invoiced by SCE.

(b)

Subject to the following two sentences, SCE will retain all SONGS-related rate revenue collected pursuant to the revenue requirement for Non-O&M Expenses provisionally authorized in Decision No. 12-11-051 for calendar year 2012. Notwithstanding the foregoing, SCE will refund to ratepayers any such SONGS-related rate revenues collected in 2012 pursuant to Decision No. 12-11-051 that exceed 2012 recorded Non-O&M Expenses by more than $10 million. Any amount to be refunded pursuant to this Section of the Agreement shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.


(c)	For calendar year 2012, SDG&E will retain rate revenue sufficient to defray all recorded Non-O&M Expenses.


(d)	For calendar year 2012, the Utilities will retain rate revenue sufficient to defray all recorded Non-O&M Balancing Account Expenses.


(e)	Provided that the sum of the amounts listed in Sections 4.9(e)(i)-(iii) of this Agreement does not exceed the revenue requirement for each Utility’s respective share of SONGS base O&M costs provisionally authorized for the year 2013 pursuant to Decision Nos. 12-11-051 and 13-05-010, the Utilities will retain rate revenue sufficient to defray:


(i)	All base O&M costs recorded in 2013;


(ii)	All costs associated with severance of employees at SONGS or resulting from the permanent shut down at SONGS recorded in 2013; and


(iii)	All Incremental Inspection and Repair Costs recorded in 2013.

(f)

If the revenue requirement for each Utility’s respective share of SONGS base O&M costs provisionally authorized for the year 2013 pursuant to Decision Nos. 12-11-051 and 13-05-010 exceeds the sum of the amounts set forth in Sections 4.9(e)(i)-(iii) of this Agreement, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the sum of the recorded amounts in Sections 4.9(e)(i)-(iii). Likewise, if the Utilities recover any portion of the recorded amounts in Sections 4.9(e)(i)-(iii) through the Nuclear Decommissioning Trusts, those portions shall also be refunded to ratepayers. These amounts shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.

(g)

For calendar year 2013, the Utilities will retain rate revenue sufficient to defray all recorded SONGS-related non-O&M expenses (including both Non-O&M Expenses and Non-O&M Balancing Account Expenses). The Utilities shall also seek recovery of these recorded amounts through the Nuclear Decommissioning Trusts to the extent permitted by applicable tax laws without penalty and CPUC action. If the revenue requirement for each Utility’s respective share of SONGS-related non-O&M expenses provisionally authorized for the year 2013 pursuant to Decision Nos. 12-11-051 and 13-05-010 exceeds the amount of each Utility’s respective recorded SONGS-related non-O&M expenses in 2013, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the amounts recorded. Likewise, if the Utilities recover any portion of their SONGS-related non-O&M expenses recorded in 2013 through the Nuclear Decommissioning Trusts, those portions shall also be refunded to ratepayers. Any amount to be refunded pursuant to this Section of the Agreement shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.


(h)	Each Utility shall file one or more applications for the Commission to conduct a reasonableness review of recorded 2014 SONGS-related O&M or non-O&M expenses (including both Non-O&M Expenses and Non-O&M Balancing Account Expenses), whether recovered in general rates or from the Nuclear Decommissioning Trusts.

(i)

If the revenue requirement for each Utility’s respective share of SONGS-related O&M and non-O&M expenses provisionally authorized for the year 2014 pursuant to Decision Nos. 12-11-051 and 13-05-010 exceeds the amount of each Utility’s respective recorded SONGS-related O&M and non-O&M expenses in 2014, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the amounts recorded. Likewise, if the Utilities recover any portion of their SONGS-related O&M or non-O&M expenses recorded in 2014 through the Nuclear Decommissioning Trusts, and/or if the CPUC disallows any such expenses, those portions shall also be refunded to ratepayers. Section 4.9(j) of this Agreement sets forth the procedure that each Utility shall use to determine the amount of any refunds pursuant to this Section of the Agreement.


(j)	In order to determine the amount of any refunds based on the difference between recorded and provisionally authorized expenses under Section 4.9(i) of this Agreement, each Utility shall use the following procedure:

(i)

On the last day of the month prior to the Effective Date, each Utility shall calculate the difference between recorded and provisionally authorized amounts of SONGS-related O&M and non-O&M expenses during the time period from January 1, 2014, until the last day of available recorded cost data in 2014. If the provisionally authorized revenue requirement for such costs during this time period exceeds the recorded amount of such costs during this time period, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the amounts recorded, with such refund to be effectuated per the refund mechanism set forth in Section 4.12 of this Agreement.

(ii)

On the last day of the month prior to the Effective Date, each Utility shall also calculate a forecast of SONGS-related O&M and non-O&M expenses for the time period from the last day of available recorded cost data in 2014 until December 31, 2014. If the provisionally authorized revenue requirement for such costs during this time period exceeds the forecasted amounts of such costs during this time period, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the amounts forecasted as the excess revenue is received, with such refund to be effectuated as a credit to SCE’s ERRA account and SDG&E’s NGBA.

(iii)

In the first quarter of 2015, each Utility shall calculate the difference between recorded and forecasted amounts of SONGS-related O&M and non-O&M expenses during the time period set forth in Section 4.9(j)(ii) of this Agreement. If the forecasted revenue requirement for such costs during this time period exceeds the recorded amounts of such costs during this time period, the Utilities shall refund to ratepayers the difference between the amounts forecasted and the amounts recorded, with such refund to be effectuated as a credit to SCE’s ERRA and SDG&E’s NGBA.

If, on the other hand, the recorded amounts exceed the forecasted revenue requirement, the Utilities shall recover the difference between the amounts forecasted and the amounts recorded from ratepayers via a debit to SCE’s ERRA account and SDG&E’s NGBA.


(iv)	On the last day of the month following a CPUC decision authorizing the Utilities to recover any portion of their SONGS-related O&M or non-O&M expenses recorded in 2014 through the Nuclear Decommissioning Trusts, and/or of a decision disallowing any such costs, the Utilities shall effectuate a refund of such amounts per the refund mechanism set forth in Section 4.12 of this Agreement.


(k)	In determining the provisionally authorized revenue requirement for Non-O&M Expenses pursuant to Sections 4.9(b), 4.9(g), 4.9(i), and 4.9(j) of this Agreement, the Utilities shall utilize a formula agreeable to all Settling Parties for allocating company-wide expenses to SONGS, which will be described in the Utilities’ Tier 2 Advice Letters filed pursuant to Section 6.1.


(l)	The Utilities will recover all recorded O&M costs incurred in connection with the U2C17 RFO.


(m)	Except as expressly provided in this Agreement, the O&M and other costs that the Utilities are entitled to retain pursuant to Section 4.9 of this Agreement shall not be subject to any disallowance, refund, or any form of reasonableness review by the Commission.


4.10.	Market Power Purchases


(a)	The Utilities will recover in rates the full amount of any costs designated as SONGS “replacement power costs,” SONGS “replacement energy costs,” or “net SONGS costs” incurred to purchase power in the market from January 1, 2012, until the last day of the month prior to the Effective Date.

(b)

The Utilities will recover in rates the entire SONGS-related portion of the under-collected balance in each Utility’s respective ERRA account as of the last day of the month prior to the Effective Date, subject to normal CPUC compliance review in the ERRA docket (i.e., review of the Utilities’ Quarterly Compliance Reports and compliance with the Least-Cost Dispatch Standard). Subject to such review, the SONGS-related under-collected balances in each Utility’s respective ERRA accounts shall be amortized over a period beginning on the first day of the month (or the nearest date practicable) following the Effective Date and ending no later than December 31, 2015. Although nothing in this Agreement shall limit TURN, ORA, FOE, or CUE’s ability to challenge the eligibility of the non-SONGS-related portion of either Utility’s under-collected ERRA balance for cost recovery, neither TURN, ORA, FOE, or CUE shall oppose either Utility’s request to amortize by December 31, 2015 any portion of the under-collected balance found by the CPUC to be eligible for recovery.

(c)

The Commission shall not impose any disallowance, on either of the Utilities, of any of the Utilities’ costs incurred to purchase power in the market as a result of the non-operation of SONGS. None of the Settling Parties will advocate before the Commission or any other judicial, legislative, or administrative body for any disallowance of past or future costs incurred by the Utilities to purchase power in the market as a result of the non-operation of SONGS.

(d)

No future adjustments or disallowances to the Utilities’ ERRA accounts shall be made as a result of the non-operation of SONGS. This limitation includes foregone revenues; there will be no future adjustments or disallowances to the Utilities’ ERRA accounts as a result of foregone sales of SONGS output. No Settling Party shall object in an ERRA or other Commission proceeding to the Utilities’ showing on the grounds that the applied-for purchased power-related expenses were related to the non-operational status of SONGS.


4.11.	SONGS Litigation Balance

(a)

The SONGS Litigation Balance shall be determined by netting SONGS Litigation Costs from SONGS Litigation Recoveries. The mechanism for netting SONGS Litigation Costs from SONGS Litigation Recoveries shall be to establish memorandum accounts. In order to account for all recorded costs booked since January 31, 2012, each Utility shall establish memorandum accounts as of January 31, 2012. Each Utility shall establish the following memorandum accounts (or sub-accounts):


(i)	Each Utility shall establish one memorandum account for netting costs and recoveries related to NEIL (the “NEIL Memorandum Account”). Every year, the Utilities shall record all SONGS Litigation Costs related to pursuing recovery and planning to pursue recovery from NEIL and all SONGS Litigation Recoveries received from NEIL in this memorandum account.


(ii)	Each Utility shall establish one memorandum subaccount to record the SONGS Litigation Balance attributable to the NEIL Outage Policy (the “NEIL Outage Memorandum Subaccount”).


(iii)	Each Utility shall establish one memorandum subaccount to record the SONGS Litigation Balance attributable to all other recoveries from NEIL (the “NEIL Other Recoveries Memorandum Subaccount”).


(iv)	Each Utility shall establish one memorandum account for netting costs and recoveries related to Mitsubishi (the “Mitsubishi Memorandum Account”). Every year, the Utilities shall record all SONGS Litigation Costs related to pursuing recovery and planning to pursue recovery from Mitsubishi and all SONGS Litigation Recoveries received from Mitsubishi in this memorandum account.

(b)

If there is a positive balance (i.e., SONGS Litigation Costs in excess of SONGS Litigation Recoveries) in any memorandum account at the end of a given year, the positive balance will be carried over to the next year. If there is a negative balance (i.e., SONGS Litigation Costs are less than SONGS Litigation Recoveries) in any memorandum account as of December 31, 2014, or at the end of any subsequent year, each Utility shall distribute to ratepayers their portion of the SONGS Litigation Recoveries as determined by the sharing formula in Section 4.11(c) of this Agreement. These amounts shall be distributed to ratepayers pursuant to the distribution method set forth in Section 4.11(d) of this Agreement. The Utilities’ portion of the SONGS Litigation Recoveries, as determined by the sharing formula in Section 4.11(c) of this Agreement, shall be retained by the Utilities at the time the ratepayers’ portions are distributed. Negative balances shall not carry over from one year to the next; instead, the account balance shall be reset to zero on the first of the year following any distribution of SONGS Litigation Recoveries pursuant to this Section of the Agreement.


(c)	The SONGS Litigation Balance shall be shared between the Utilities and the ratepayers according to the following formulas:


(i)	The negative balance in the NEIL Memorandum Account will be transferred to the NEIL Outage Memorandum Subaccount and the NEIL Other Recoveries Memorandum Subaccount, reflecting the allocation of SONGS Litigation Recoveries between the NEIL Outage Policy and other recoveries from NEIL.


(ii)	The negative balance in the NEIL Outage Memorandum Subaccount shall be shared as follows:


(A)	The Utilities shall retain 5% of the balance


(B)	The Utilities shall distribute to ratepayers 95% of the balance


(iii)	The negative balance in the NEIL Other Recoveries Memorandum Subaccount shall be shared as follows:


(A)	The Utilities shall retain 17.5% of the balance


(B)	The Utilities shall distribute to ratepayers 82.5% of the balance


(iv)	The negative balance in the Mitsubishi Memorandum Account shall be shared as follows:


(A)	The Utilities shall retain 50% of the balance


(B)	The Utilities shall distribute to ratepayers 50% of the balance


(d)	Any amounts to be distributed to ratepayers pursuant to Section 4.11(b) of this Agreement shall be distributed pursuant to the following distribution mechanism:


(i)	The ratepayers’ portion of the SONGS Litigation Balance recovered from NEIL shall be distributed to ratepayers via a credit to each Utility’s respective ERRA account.


(ii)	The first $282 million of SONGS Litigation Balance recovered from Mitsubishi that is distributed to SCE ratepayers pursuant to Section 4.11(b) of this Agreement shall be distributed via a credit to SCE’s BRRBA.


(iii)	The first $71 million of SONGS Litigation Balance recovered from Mitsubishi that is distributed to SDG&E ratepayers pursuant to Section 4.11(b) of this Agreement shall be distributed via a credit to SDG&E’s NGBA.


(iv)	The ratepayers’ portion of any further SONGS Litigation Balance recovered from Mitsubishi shall be distributed to ratepayers as follows:

(A)

First, by reducing the regulatory assets described in Sections 4.3(b), 4.8(a), 4.5(a), and 4.6(a) of this Agreement, in the order listed. The effect of the reduction to these regulatory assets shall be to decrease the yearly amount of the revenue requirement for each regulatory asset. This reduction to regulatory assets shall not affect the amortization period for the regulatory assets described in Sections 4.3(b), 4.8(a), 4.5(a), and 4.6(a) of this Agreement.


(B)	Second, any remaining amounts shall be distributed via a credit to SCE’s BRRBA and SDG&E’s NGBA.

(e)

In consideration of the Utilities retaining SONGS Litigation Recoveries to the extent of the SONGS Litigation Costs, the Utilities shall remove all SONGS Litigation Costs booked in the memorandum accounts described in Section 4.11(a) of this Agreement from the recorded costs used to develop future general rate case forecasts. Nothing in this Agreement shall preclude the Settling Parties from making any arguments in either Utility’s general rate cases regarding costs used to develop general rate case forecasts.

(f)

In consideration of the sharing of net SONGS Litigation Recoveries, the Utilities shall have complete discretion to settle, compromise, or otherwise resolve claims against NEIL and/or Mitsubishi in any manner and whenever the Utilities determine, in the exercise of their business judgment, without prior or subsequent review or approval, disapproval, or disallowance by the CPUC or any parties to this OII, except as provided in 4.11(g)(ii)(y).


(g)	The Utilities shall promptly notify the CPUC of any such settlement, compromise, or other resolution of their claims against NEIL or MHI, provided, however, that:


(i)	The Utilities may provide such notification in a manner that preserves the confidentiality thereof insofar as may be reasonably necessary to further the Utilities’ flexibility to settle, compromise, or otherwise resolve such claims; and


(ii)	The CPUC shall not review the reasonableness or prudence of the Utilities’ litigation, settlement, compromise, or other resolution of such claims and shall not impose any ratemaking adjustment in respect of such claims except (x) as expressly provided in this Agreement, and (y) the CPUC may review SONGS Litigation Costs to ensure they are not exorbitant in relation to the recovery obtained.


(h)	The Utilities shall each use their best efforts to provide all Settling Parties with advance notice of any such settlement, compromise, or other resolution of their claims against NEIL or MHI, to the extent possible under the circumstances and the terms of any agreement with NEIL or MHI, before the Utilities notify the CPUC or otherwise make public the agreement.

(i)

The Utilities shall submit to the CPUC documentation of any final resolution of third-party litigation and documentation of SONGS Litigation Costs. The Utilities may submit such documentation subject to Public Utilities Code §583. Further, the Utilities are not required to submit privileged documents. The CPUC may review such documents to ensure that ratepayer credits are accurately calculated, and to ensure that the SONGS Litigation Costs are not exorbitant in relation to the recovery obtained.

4.12.

Any amounts that the Utilities may be required to refund to ratepayers pursuant to Sections 4.2(b), 4.3(b)(ii), 4.9(b), 4.9(f), 4.9(g), 4.9(j)(i), and 4.9(j)(iv) of this Agreement shall be refunded via a reduction to each Utility’s respective under-collected ERRA balance as of the last day of the month prior to the Effective Date. This refund mechanism shall not change the amortization period set forth in Section 4.10(b) of this Agreement.

4.13.

For the period from the first day of the month of the Effective Date to December 31, 2014, the difference between the Capital-Related Revenue Requirement for SONGS assets provisionally authorized in Decision No. 12-11-051 and the revenue requirement for Base Plant, CWIP, M&S and Nuclear Fuel Investment shall be credited to each Utility’s respective ERRA account. To the extent the difference referenced in the prior sentence is calculated based on a forecast, a true-up will be recorded in ERRA in the first quarter of 2015 to reflect the actual difference. For the period from January 1, 2015 to the date of Utility implements new base rates pursuant to its next GRC decision, such difference will be credited to ERRA (for SCE) and NGBA (for SDG&E).


4.14.	Except as expressly provided in this Agreement, all costs recorded in SCE’s SONGSMA, SDG&E’s SONGSBA, and both Utilities’ SONGSOMA shall be recovered in rates and shall not be subject to any disallowance, refund, or any form of reasonableness review by the Commission.


4.15.	Because this Agreement provides a ratemaking disposition for all costs recorded in SCE’s SONGSMA, SDG&E’s SONGSBA, and both Utilities’ SONGSOMA, these memorandum accounts will not be necessary after the last day of the month prior to the Effective Date and will be terminated by the Utilities as of that day.


4.16.	Greenhouse Gas (GHG) Research : Subject to the Commission’s approval of the Agreement,

(a)

As part of their philanthropic programs, each of SCE and SDG&E agree to work with the University of California Energy Institute (or other existing UC entity, on one or more campuses, engaged in energy technology development) to create a Research, Development, and Demonstration (RD&D) program, whose goal would be to deploy new technologies, methodologies, and/or design modifications to reduce GHG emissions, particularly at current and future generating plants in California.


(b)	The RD&D program will operate for up to five years following the Commission’s approval of the Tier 2 Advice Letter described in section 4.16(e).


(c)	SCE will pledge and donate $4 million annually for five years, and SDG&E will pledge and donate $1 million annually for five years, so that the total amounts donated will be $5 million annually for five years. All such donations will be from shareholder funds.


(d)	Within 60 days of the Effective Date, the Utilities commit to host a meeting with UC representatives and other interested parties with the goal of crafting a Program Implementation Plan (PIP). The Commission’s Energy Division shall provide support in coordinating the meeting.


(e)	Within 30 days thereafter, the Utilities shall jointly file, and serve, a PIP via a Tier 2 Advice Letter that describes the process for implementation, a proposed schedule and budget, and expected results, applications, and demonstrations.


(f)	The Utilities will file, and serve, an annual report to the Energy Division to apprise the Commission of the program’s progress towards beta testing of developed technologies, methodologies, and/or design changes.


4.17.	Resolution of Consolidated Proceedings


(a)	The Settling Parties intend for this Agreement to resolve the OII and all Consolidated Proceedings in their entirety. The Settling Parties agree that the Consolidated Proceedings should be resolved as follows in this section of the Agreement


(b)	A. 13-03-005


(i)	The Settling Parties agree that SCE’s testimony in support of A. 13-03-005 conclusively established that the total cost of the SGRP was $612.1


	million in 2004 dollars (100% share). The Settling Parties shall not take the position, in any proceeding whatsoever, that SCE spent more than $612.1 million (100% share, 2004$) on the SGRP.

(ii)

The Settling Parties agree that SCE’s testimony in support of A. 13-03-005 utilized appropriate inflation indexes to deflate the total cost of the SGRP from nominal dollars to 2004 dollars. This includes the use of the Handy-Whitman index for fabrication and construction costs and the Commission-approved nuclear decommissioning burial escalation rates for burial costs. The Settling Parties shall not take the position, in any proceeding whatsoever, that SCE used inappropriate inflation indexes in its testimony in support of A. 13-03-005.


(iii)	Because this Agreement provides a ratemaking disposition for all costs described in A. 13-03-005, no further reasonableness review is required. The Settling Parties shall jointly request that the Commission allow SCE to retain all rate revenues collected from customers for the SGRP prior to February 1, 2012, as a resolution of A. 13-03-005.


(c)	A. 13-03-014


(i)	The provisions set forth in Section 4.16(b)(i)-(ii) are incorporated herein as though set forth in their entirety.


(ii)	Because this Agreement provides a ratemaking disposition for all costs described in A. 13-03-014, no further reasonableness review is required. The Settling Parties shall jointly request that the Commission allow SDG&E to retain all rate revenues collected from customers for the SGRP prior to February 1, 2012, as a resolution of A. 13-03-014.


(d)	A. 13-01-016


(i)	The Settling Parties agree that the costs recorded in SCE’s SONGSMA during the year 2012 were reasonable and prudent to the extent this Agreement provides that SCE shall recover such costs.


(ii)	None of the Settling Parties will take the position, in any proceeding whatsoever, that any of the costs recorded in SCE’s SONGSMA during 2012 were unreasonable, or should be disallowed, except to the extent that this Agreement provides that such costs be refunded to ratepayers.


(iii)	Because this Agreement provides a ratemaking disposition for all costs described in A. 13-01-016, no further reasonableness review is required. The Settling Parties shall jointly request that the Commission grant A. 13-01-016 to the extent that this Agreement provides for rate recovery of the costs recorded in SCE’s SONGSMA during 2012.


(e)	A. 13-03-013


(i)	The Settling Parties agree that the costs recorded in SDG&E’s SONGSBA during the year 2012 were reasonable and prudent to the extent this Agreement provides that SDG&E shall recover such costs.


(ii)	None of the Settling Parties will take the position, in any proceeding whatsoever, that any of the costs recorded in SDG&E’s SONGSBA during 2012 were unreasonable, or should be disallowed, except to the extent that this Agreement provides that such costs be refunded to ratepayers.


(iii)	Because this Agreement provides a ratemaking disposition for all costs described in A. 13-03-013, no further reasonableness review is required. The Settling Parties shall jointly request that the Commission grant A. 13-03-013 to the extent that this Agreement provides for rate recovery of the costs recorded in SDG&E’s SONGSBA during 2012.


4.18.	In light of this Agreement, the Settling Parties urge the CPUC to withdraw the November 19, 2013, Proposed Decision on Phase 1 and Phase 1A issues.

V.
GENERAL PROVISIONS AND RESERVATIONS


5.1.	The Settling Parties shall use their best efforts to obtain Commission Approval. Following execution of this Agreement, the Settling Parties shall:


(a)	Jointly file a motion requesting that the Commission:


(i)	Approve the Agreement in its entirety without change;


(ii)	Find the Agreement to be reasonable in light of the whole record, consistent with law, and in the public interest; and


(iii)	Expedite its consideration and approval of the Agreement in order to provide the benefits of the Agreement as soon as possible.


(b)	Support and mutually defend this Agreement in its entirety until the Commission has issued final approval of the Agreement.


(c)	Oppose any modifications to this Agreement proposed by any non-settling party to the OII, unless all Settling Parties jointly agree to support such modification.


(d)	Cooperate reasonably on all submissions, including briefs, necessary to achieve Commission Approval of the Agreement.

(e)

Review any Commission orders regarding this Agreement to determine if the Commission has changed or modified this Agreement, deleted a term, or imposed a new term in this Agreement. If any Settling Party is unwilling to accept such change, modification, deletion, or addition of a new term, that Settling Party shall so notify the other Settling Parties within 15 days of issuance of the order by the

Commission. The Settling Parties shall thereafter promptly discuss each change, modification, deletion, or new term to this Agreement found unacceptable and negotiate in good faith to achieve a resolution acceptable to all Settling Parties and promptly seek Commission approval of the resolution so achieved. Failure to resolve such change, modification, deletion, or new term to this Agreement to the satisfaction of all Settling Parties within 15 days of notification, or to obtain Commission approval of such resolution promptly thereafter, shall entitle any Settling Party to terminate this Agreement through prompt notice to all other Settling Parties.


5.2.	In accordance with Rule 12.5, the Settling Parties intend that Commission adoption of this Agreement will constitute a complete resolution of this OII and will have the effect set forth in Rule 12.5 of the Commission’s Rules of Practice and Procedure.

5.3.

Since this Agreement represents a compromise by them, the Settling Parties have entered into each stipulation contained in this Agreement on the basis that the stipulation not be construed as an admission or concession by any Settling Party regarding any fact or matter of law at issue in this proceeding. Should this Agreement not be approved in its entirety by the Commission, the Settling Parties reserve all rights to take any position whatsoever with respect to any fact or matter of law at issue in the OII.


5.4.	The Settling Parties agree that no signatory to this Agreement or any employee thereof assumes any personal liability as a result of this Agreement.


5.5.	If any Settling Party fails to perform its respective obligations under this Agreement, any other Settling Party may come before the Commission to pursue a remedy including enforcement.


5.6.	The provisions of this Agreement are not severable. If the Commission, or any court of competent jurisdiction, overrules or modifies as legally invalid any material provision of this Agreement, the Agreement may be considered rescinded, at the discretion of any of the Settling Parties, as of the date such ruling or modification becomes final.

5.7.

The Settling Parties acknowledge and stipulate that they are agreeing to this Agreement freely, voluntarily, and without any fraud, duress, or undue influence by any other party. Each Settling Party hereby states that, through its authorized representatives, it has read and fully understands its rights, privileges, and duties under this Agreement, including each Settling Party’s right to discuss this Agreement with its legal counsel and has exercised those rights, privileges, and duties to the extent deemed necessary.


5.8.	In executing this Agreement, each Settling Party declares and mutually agrees that the terms and conditions herein are reasonable, consistent with the law, and in the public interest.


5.9.	This Agreement constitutes the Settling Parties’ entire agreement on the subject matters addressed herein, which cannot be amended or modified without the express written and signed consent of all the Settling Parties hereto.

5.10.

None of the provisions of this Agreement shall be considered waived by any Settling Party unless such waiver is given in writing. The failure of a Settling Party to insist in any one or more instances upon strict performance of any of the provisions of this Agreement or to take advantage of any of their rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect.


5.11.	No Settling Party has relied, or presently relies, upon any statement promise, or representation by any other Settling Party, whether oral or written, except as specifically set forth in this Agreement. Each Settling Party expressly assumes the risk of any mistake of law or fact made by such Settling Party or its authorized representative in entering into this Agreement.


5.12.	This Agreement may be executed in up to four separate counterparts by the different Settling Parties hereto with the same effect as if all Settling Parties had signed one and the same document. All such counterparts shall be deemed to be an original and shall together constitute one and the same Agreement.


5.13.	This Agreement shall become effective and binding on the Settling Parties as of the Effective Date. However, the provisions of Section 5.1 of this Agreement shall impose obligations on the Settling Parties immediately upon the execution of this Agreement by all of the Settling Parties.


5.14.	This Agreement shall be governed by the laws of the State of California as to all matters, including but not limited to, matters of validity, construction, effect, performance, and remedies.


5.15.	To the extent this Agreement requires that any Settling Party provide notice to any other Settling Party, such notice shall be in writing and directed to the signatories to this agreement.

VI.
IMPLEMENTATION OF AMENDED AND RESTATED SETTLEMENT AGREEMENT

6.1.

Within 30 days of the Effective Date, the Utilities shall file revised tariff sheets to implement the revenue requirement, accounting procedures, and charges authorized in this Agreement and to incorporate the relevant findings and conclusions of the decision adopting this Agreement. The revised tariff sheets shall become effective on filing, subject to a finding of compliance by the Energy Division, and shall comply with General Order 96-B. Notwithstanding any of the figures set forth in Sections 3.36 – 3.48 of this Agreement, ORA and TURN have the prerogative to review and validate any amounts used by the Utilities to implement the revenue requirement, accounting procedures, and charges authorized in this Agreement, to meet and confer with the Utilities to resolve any concerns, and to protest the advice letters if such concerns are not resolved to their satisfaction.


6.2.	The Utilities shall file Tier 2 Advice Letters (which may be combined with Tier 2 Advice Letters proposing consolidated rate changes pursuant to the Utilities’ respective General

Rate Case decisions) to implement changes to their respective revenue requirements, including implementation of changes pursuant to Sections 4.2, 4.3, 4.5, and 4.6 – 4.13 consistent with the terms of this Agreement.

6.3.

The Utilities shall include in the filing of the revised tariff sheets (pursuant to Section 6.1) and the Tier 2 Advice Letters (pursuant to Section 6.2), a description of the agreed-upon formula referred to in Section 4.9(k) for allocating company-wide expenses to SONGS. The Utilities shall also include, in the filing of the revised tariff sheets (pursuant to Section 6.1) and the Tier 2 Advice Letters (pursuant to Section 6.2), documentation of any revised calculations of the revenue requirement for CWIP referred to in Section 4.8 based on changes in the Authorized Cost of Debt and Authorized Cost of Preferred Stock.

VII.
EXECUTION

IN WITNESS WHEREOF, the Settling Parties have duly executed this Agreement. This Agreement is executed in six counterparts, each of which shall be deemed an original. The undersigned represent that they are authorized to sign on behalf of the party represented.



SOUTHERN CALIFORNIA EDISON COMPANY By: /s/ Ronald Nichols Title: Senior Vice President Date: 09-23-2014	SAN DIEGO GAS & ELECTRIC COMPANY By: /s/ Lee Schavrien Title: SVP - FIN, REG & LEGIS AFRS Date: 9/23/14



THE UTILITY REFORM NETWORK By: /s/ Matthew Freedman Title: Staff Attorney Date: September 23, 2014	OFFICE OF RATEPAYER ADVOCATES By: /s/ Linda Serizawa Title: Deputy Director Date: 9/23/2014
FRIENDS OF THE EARTH By: /s/ Lawrence Chaset Title: Attorney for Friends of the Earth Date: Sep. 23, 2014	THE COALITION OF CALIFORNIA UTILITY EMPLOYEES By: /s/ Jamie Mauldin Title: Attorney Date: 9/23/14

Exhibit A

ILLUSTRATIVE EXAMPLE FOR BASE PLANT AND MATERIALS AND SUPPLIES (M&S)



	As of February 1, 2012
Base Plant ¹	$	622
M&S		99
Regulatory Asset		721
Less: Accumulated Deferred Taxes ²		(152)
Regulatory Asset, adjusted for deferred taxes		569
Rate of Return		2.95	%
Return ^3,4	$	17

__________________________

¹ Base Plant excludes nuclear fuel and CWIP

² Includes deferred taxes associated with nuclear fuel

³ Does not include associated income taxes

⁴ Calculation of return illustrative for a single point in time; actual calculation will be based on an average

CONFIDENTIAL

PRELIMINARY AND APPROXIMATE

Exhibit 31.1

CERTIFICATION

I, THEODORE F. CRAVER, JR., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, of Edison International;

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

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

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

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

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

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

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

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

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

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

Date: October 28, 2014

/s/ THEODORE F. CRAVER, JR.

THEODORE F. CRAVER, JR.

Chief Executive Officer

Exhibit 31.1

CERTIFICATION

I, W. JAMES SCILACCI, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, of Edison International;

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

Date: October 28, 2014

/s/ W. JAMES SCILACCI

W. JAMES SCILACCI

Chief Financial Officer

Exhibit 31.2

CERTIFICATION

I, PEDRO J. PIZARRO, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, of Southern California Edison Company;

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

Date: October 28, 2014

/s/ PEDRO J. PIZARRO

PEDRO J. PIZARRO

President

Exhibit 31.2

CERTIFICATION

I, MARIA RIGATTI, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, of Southern California Edison Company;

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

Date: October 28, 2014

/s/ MARIA RIGATTI

MARIA RIGATTI

Chief Financial Officer

Exhibit 32.1

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

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

In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended October 28, 2014 (the "Quarterly Report"), of Edison International (the "Company"), and pursuant to 18 U.S.C. Section 1350, as enacted by Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned certifies, to the best of his knowledge, that:


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


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

Date: October 28, 2014

/s/ THEODORE F. CRAVER, JR.

THEODORE F. CRAVER, JR.

Chief Executive Officer

Edison International

/s/ W. JAMES SCILACCI

W. JAMES SCILACCI

Chief Financial Officer

Edison International

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

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

Exhibit 32.2

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

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

In connection with the accompanying Quarterly Report on Form 10-Q for the quarter ended October 28, 2014 (the "Quarterly Report"), of Southern California Edison Company (the "Company"), and pursuant to 18 U.S.C. Section 1350, as enacted by Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned certifies, to the best of his or her knowledge, that:


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


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

Date: October 28, 2014

/s/ PEDRO J. PIZARRO

PEDRO J. PIZARRO

President

Southern California Edison Company

/s/ MARIA RIGATTI

MARIA RIGATTI

Chief Financial Officer

Southern California Edison Company

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