EDISON INTERNATIONAL (Form: 10-K, Received: 02/27/2020 16:20:33)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



(Mark One)
☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31, 2019
☐	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			2244 Walnut Grove Avenue
(P.O. Box 976)			(P.O. Box 800)
Rosemead,	California	91770	Rosemead,	California	91770
(Address of principal executive offices)			(Address of principal executive offices)
(626)	302-2222		(626)	302-1212
(Registrant's telephone number, including area code)			(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Edison International:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, no par value	EIX	NYSE	LLC

Southern California Edison Company:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Cumulative Preferred Stock, 4.08% Series	SCEpB	NYSE American LLC
Cumulative Preferred Stock, 4.24% Series	SCEpC	NYSE American LLC
Cumulative Preferred Stock, 4.32% Series	SCEpD	NYSE American LLC
Cumulative Preferred Stock, 4.78% Series	SCEpE	NYSE American LLC

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Edison International Yes ☑ No ☐ Southern California Edison Company Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

Edison International Yes ☐ No ☑ Southern California Edison Company Yes ☐ No ☑

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 ☑ No ☐ Southern California Edison Company Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Edison International Yes ☑ No ☐ Southern California Edison Company Yes ☑ No ☐



Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-12 of the Exchange Act. (Check One):
Edison International	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company	Emerging growth company
	☑	☐	☐	☐	☐
Southern California Edison Company	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company	Emerging growth company
	☐	☐	☑	☐	☐



If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Edison International	☐	Southern California Edison 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 ☑ Southern California Edison Company Yes ☐ No ☑

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 28, 2019, the last business day of the most recently completed second fiscal quarter:

Edison International Approximately $22.0 billion Southern California Edison Company Wholly owned by Edison International



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 February 20, 2020:
Edison International	362,570,075	shares
Southern California Edison Company	434,888,104	shares (wholly owned by Edison International)

DOCUMENTS INCORPORATED BY REFERENCE

Designated portions of the Proxy Statement relating to registrants' joint 2020 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS



				SEC Form 10-K Reference Number
GLOSSARY			vi
FORWARD-LOOKING STATEMENTS			1
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			3	Part II, Item 7
	MANAGEMENT OVERVIEW		3
	Highlights of Operating Results		3
	Wildfire Mitigation and Wildfire Insurance Expenses		5
	2018 General Rate Case		6
	2020 Cost of Capital Application		6
	2018 and 2019 FERC Formula Rate		6
	Southern California Wildfires and Mudslides		7
	2021 General Rate Case		10
	Electricity Industry Trends		11
	Capital Program		11
	RESULTS OF OPERATIONS		13
	Southern California Edison Company		13
		Impact of 2018 GRC	13
		Years ended December 31, 2019, 2018 and 2017	14
		Earning Activities	15
		Cost-Recovery Activities	15
		Supplemental Operating Revenue Information	16
		Income Taxes	16
	Edison International Parent and Other		16
		Loss from Continuing Operations	16
	LIQUIDITY AND CAPITAL RESOURCES		17
	Southern California Edison Company		17
		Available Liquidity	18
		Capital Investment Plan	18
		Decommissioning of San Onofre	20
		SCE Dividends	21
		Margin and Collateral Deposits	22
		Regulatory Balancing and Memorandum Accounts	23
	Edison International Parent and Other		23
		Net Operating Loss and Tax Credit Carryforwards	24
	Historical Cash Flows		24
		Southern California Edison Company	24
		Edison International Parent and Other	28
	Contractual Obligations and Contingencies		29
		Contractual Obligations	29
		Contingencies	30
	Off-Balance Sheet Arrangements		30
	Environmental Developments		30
	MARKET RISK EXPOSURES		30
	Interest Rate Risk		30
	Commodity Price Risk		30
	Credit Risk		31
	CRITICAL ACCOUNTING ESTIMATES AND POLICIES		31
	Rate Regulated Enterprises		31
	Accounting for Contingencies		32
	Income Taxes		33
	Nuclear Decommissioning – Asset Retirement Obligation		34
	Pensions and Postretirement Benefits Other than Pensions		35
	Contributions to the Wildfire Insurance Fund		37
	NEW ACCOUNTING GUIDANCE		37
RISK FACTORS			38	Part I, Item 1A
	RISKS RELATING TO EDISON INTERNATIONAL		38
	RISKS RELATING TO SOUTHERN CALIFORNIA EDISON COMPANY		38
	Regulatory and Legislative Risks		38
	Operating Risks		40
	Financing Risks		43
	Competitive and Market Risks		43
	Cybersecurity and Physical Security Risks		43
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			44	Part II, Item 7A
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			44	Part II, Item 8
	REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		45
	CONSOLIDATED FINANCIAL STATEMENTS		50
	Consolidated Statements of Income for Edison International		50
	Consolidated Statements of Comprehensive Income for Edison International		51
	Consolidated Balance Sheets for Edison International		52
	Consolidated Statements of Cash Flows for Edison International		54
	Consolidated Statements of Changes in Equity for Edison International		55
	Consolidated Statements of Income for Southern California Edison Company		57
	Consolidated Statements of Comprehensive Income for Southern California Edison Company		57
	Consolidated Balance Sheets for Southern California Edison Company		58
	Consolidated Statements of Cash Flows for Southern California Edison Company		60
	Consolidated Statements of Changes in Equity for Southern California Edison Company		61
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		62
	Note 1. Summary of Significant Accounting Policies		62
	Note 2. Property, Plant and Equipment		74
	Note 3. Variable Interest Entities		75
	Note 4. Fair Value Measurements		76
	Note 5. Debt and Credit Agreements		80
	Note 6. Derivative Instruments		81
	Note 7. Revenue		83
	Note 8. Income Taxes		84
	Note 9. Compensation and Benefit Plans		88
	Note 10. Investments		102
	Note 11. Regulatory Assets and Liabilities		103
	Note 12. Commitments and Contingencies		106
	Note 13. Leases		117
	Note 14. Equity		120
	Note 15. Accumulated Other Comprehensive Loss		121
	Note 16. Other Income		121
	Note 17. Supplemental Cash Flows Information		122
	Note 18. Related-Party Transactions		122
	Note 19. Quarterly Financial Data (Unaudited)		123
SELECTED FINANCIAL DATA			125	Part II, Item 6
CONTROLS AND PROCEDURES			126	Part II, Item 9A
OTHER INFORMATION			126	Part II, Item 9B
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			126	Part II, Item 9
BUSINESS			127	Part I, Item 1
	CORPORATE STRUCTURE, INDUSTRY AND OTHER INFORMATION		127
	Subsidiaries of Edison International		127
	Regulation of Edison International as a Holding Company		128
	Employees and Labor Relations		128
	Insurance		128
	SOUTHERN CALIFORNIA EDISON COMPANY		128
	Regulation		128
	Overview of Ratemaking Process		129
	Purchased Power and Fuel Supply		131
	Competition		132
	Properties		133
	Seasonality		133
	ENVIRONMENTAL CONSIDERATIONS		134
	Greenhouse Gas Regulation		134
	Environmental Risks		135
UNRESOLVED STAFF COMMENTS			135	Part I, Item 1B
PROPERTIES			135	Part I, Item 2
LEGAL PROCEEDINGS			135	Part I, Item 3
	Thomas Fire and Koenigstein Fire Litigation		135
	Montecito Mudslides Litigation		136
	Woolsey Fire Litigation		136
MINE SAFETY DISCLOSURES			136	Part I, Item 4
INFORMATION ABOUT OUR EXECUTIVE OFFICERS			137	Part I
	EXECUTIVE OFFICERS OF EDISON INTERNATIONAL		137
	EXECUTIVE OFFICERS OF SOUTHERN CALIFORNIA EDISON COMPANY		138
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			139	Part III, Item 10
EXECUTIVE COMPENSATION			139	Part III, Item 11
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS			139	Part III, Item 12
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE			140	Part III, Item 13
PRINCIPAL ACCOUNTANT FEES AND SERVICES			140	Part III, Item 14
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES			140	Part II, Item 5
	Comparison of Five-Year Cumulative Total Return		140
FORM 10-K SUMMARY			141	Part IV, Item 16
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES			141	Part IV, Item 15
	Exhibit Index		142
	Schedules Supplementing Financial Statements		145
SIGNATURES			152

iii

This is a combined Form 10-K 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.



2017/2018 Wildfire/Mudslide Events		the Thomas Fire, the Koenigstein Fire, the Montecito Mudslides and the Woolsey Fire, collectively
AB 1054		California Assembly Bill 1054, executed by the Governor of California on July 12, 2019
AB 1054 Liability Cap		If the insurance fund allowed under AB 1054 is established, and subject to certain other conditions, a cap on the aggregate requirement to reimburse the insurance fund over a trailing three calendar year period equal to 20% of the equity portion of the utility’s transmission and distribution rate base in the year of the prudency determination
ARO(s)		asset retirement obligation(s)
Bcf		billion cubic feet
BRRBA		Base Revenue Requirement Balancing Account
CAISO		California Independent System Operator
CAL FIRE		California Department of Forestry and Fire Protection
CCAs		Community Choice Aggregators which are cities, counties, and certain other public agencies with the authority to generate and/or purchase electricity for their local residents and businesses
CPUC		California Public Utilities Commission
CSRP		Customer Service Re-platform, a SCE project to implement a new customer service system
DERs		distributed energy resources
Edison Energy		Edison Energy, LLC, a wholly-owned subsidiary of Edison Energy Group that advises and provides energy solutions to large energy users
Edison Energy Group		Edison Energy Group, Inc., a wholly-owned subsidiary of Edison International, is a holding company for subsidiaries engaged in competitive businesses that provide energy services to commercial and industrial customers
EME		Edison Mission Energy
Electric Service Provider		an entity that offers electric power and ancillary services to retail customers, other than electrical corporations (like SCE) and CCAs
ERRA		Energy Resource Recovery Account
FERC		Federal Energy Regulatory Commission
FERC 2018 Settlement Period		January 1, 2018 through November 11, 2019
FHPMA		Fire Hazard Prevention Memorandum Account
Fitch		Fitch Ratings, Inc.
GAAP		generally accepted accounting principles
GHG		greenhouse gas
GRC		general rate case
GS&RP		Grid Safety and Resiliency Program
GWh		gigawatt-hours
Joint Proxy Statement		Edison International's and SCE's definitive Proxy Statement to be filed with the SEC in connection with Edison International's and SCE's Annual Shareholders' Meeting to be held on April 23, 2020
Koenigstein Fire		a wind-driven fire that originated near Koenigstein Road in the City of Santa Paula in Ventura County on December 4, 2017
kV		unit of electrical potential equal to 1000 volts
MD&A		Management's Discussion and Analysis of Financial Condition and Results of Operations in this report
Montecito Mudslides		the mudslides and flooding in Montecito, Santa Barbara County, that occurred in January 2018
Moody's		Moody's Investors Service, Inc.
NEM		net energy metering
NERC		North American Electric Reliability Corporation
NRC		Nuclear Regulatory Commission
PABA		Portfolio Allocation Balancing Account
Palo Verde		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)
PCIA		Power Charge Indifference Adjustment
PG&E		Pacific Gas & Electric Company
ROE		return on common equity
RPS		Renewables portfolio standard
S&P		Standard & Poor's Financial Services LLC
San Onofre		retired nuclear generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest
SCE		Southern California Edison Company, a wholly-owned subsidiary of Edison International
SDG&E		San Diego Gas & Electric
SEC		U.S. Securities and Exchange Commission
SED		Safety and Enforcement Division of the CPUC
SoCalGas		Southern California Gas Company
SoCore Energy		SoCore Energy LLC, a former subsidiary of Edison Energy Group that was sold in April 2018
TAMA		Tax Accounting Memorandum Account
Tax Reform		Tax Cuts and Jobs Act signed into law on December 22, 2017
Thomas Fire		a wind-driven fire that originated in the Anlauf Canyon area Ventura County on December 4, 2017
TOU		Time-Of-Use
US EPA		U.S. Environmental Protection Agency
VCFD		The Ventura County Fire Department
WEMA		Wildfire Expense Memorandum Account
WMP		a wildfire mitigation plan required to be filed every three years under California Assembly Bill 1054 to describe a utility's plans to construct, operate, and maintain electrical lines and equipment that will help minimize the risk of catastrophic wildfires caused by such electrical lines and equipment
Wildfire Insurance Fund		The insurance fund established pursuant to AB 1054
Woolsey Fire		a wind-driven fire that originated in Ventura County in November 2018

vii

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K 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 statements that do 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 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 through regulated rates, including costs related to uninsured wildfire-related and mudslide-related liabilities, costs incurred to mitigate the risk of utility equipment causing future wildfires and costs incurred to implement SCE's new customer service system;


•	ability of SCE to implement its WMP, including effectively implementing Public Safety Power Shut-Offs when appropriate;


•	ability to obtain sufficient insurance at a reasonable cost, including insurance relating to SCE's nuclear facilities and wildfire-related claims, and to recover the costs of such insurance or, in the event liabilities exceed insured amounts, the ability to recover uninsured losses from customers or other parties;

•

risks associated with AB 1054 effectively mitigating the significant risk faced by California investor-owned utilities related to liability for damages arising from catastrophic wildfires where utility facilities are alleged to be a substantial cause, including SCE's ability to maintain a valid safety certification, SCE's ability to recover uninsured wildfire-related costs from the Wildfire Insurance Fund, the longevity of the Wildfire Insurance Fund, and the CPUC's interpretation of and actions under AB 1054, including their interpretation of the new prudency standard established under AB 1054;

•

decisions and other actions by the CPUC, the FERC, the NRC and other regulatory and legislative authorities, including decisions and actions related to determinations of authorized rates of return or return on equity, the recoverability of wildfire-related and mudslide-related costs, issuance of SCE's wildfire safety certification, wildfire mitigation efforts, and delays in regulatory and legislative actions;


•	ability of Edison International or SCE to borrow funds and access bank and capital markets on reasonable terms;


•	risks associated with the decommissioning of San Onofre, including those related to public opposition, permitting, governmental approvals, on-site storage of spent nuclear fuel, delays, contractual disputes, and cost overruns;


•	extreme weather-related incidents and other natural disasters (including earthquakes and events caused, or exacerbated, by climate change, such as wildfires), which could cause, among other things, public safety issues, property damage and operational issues;


•	physical security of Edison International's and SCE's critical assets and personnel and the cybersecurity of Edison International's and SCE's critical information technology systems for grid control, and business, employee and customer data;


•	risks associated with cost allocation resulting in higher rates for utility bundled service customers because of possible customer bypass or departure for other electricity providers such as CCAs and Electric Service Providers;

•

risks inherent in SCE's transmission and distribution infrastructure investment program, 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 acceptance of power delivery), changes in the CAISO's transmission plans, and governmental approvals;


•	risks associated with the operation of transmission and distribution assets and power generating facilities, including public and employee safety issues, the risk of utility assets causing or contributing to wildfires, failure, availability, efficiency, and output of equipment and facilities, and availability and cost of spare parts;


•	actions by credit rating agencies to downgrade Edison International or SCE's credit ratings or to place those ratings on negative watch or outlook;


•	ability of Edison International to develop competitive businesses, manage new business risks, and recover and earn a return on its investment in newly developed or acquired businesses;


•	changes in tax laws and regulations, at both the state and federal levels, or changes in the application of those laws, that could affect recorded deferred tax assets and liabilities and effective tax rate;


•	changes in future taxable income, or changes in tax law, that would limit Edison International's and SCE's realization of expected net operating loss and tax credit carryover benefits prior to expiration;


•	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 adopted by the NERC, CAISO, Western Electricity Council, and similar regulatory bodies in adjoining regions, and changes in California's environmental priorities that lessen the importance the state places on GHG reduction;


•	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;


•	potential for penalties or disallowance for non-compliance with applicable laws and regulations; and


•	cost of fuel for generating facilities and related transportation, which could be impacted by, among other things, disruption of natural gas storage facilities, to the extent not recovered through regulated rate cost escalation provisions or balancing accounts.

Additional information about risks and uncertainties, including more detail about the factors described in this report, is contained throughout this report. Readers are urged to read this entire report, including information incorporated by reference, 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. Edison International and SCE post or provide direct links to (i) certain SCE and other parties' regulatory filings and documents with the CPUC and the FERC and certain agency rulings and notices in open proceedings in a section titled "SCE Regulatory Highlights," (ii) certain documents and information related to Southern California wildfires which may be of interest to investors in a section titled "Southern California Wildfires," and (iii) presentations, documents and other information that may be of interest to investors in a section titled "Events and Presentations" at www.edisoninvestor.com in order to publicly disseminate such information.

Except when otherwise stated, references to each of Edison International, SCE, or Edison Energy Group 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 competitive subsidiaries and "Edison International Parent" mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion related to the results of operations and changes in financial condition for 2018 compared to 2017 is incorporated by reference to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in Edison International's and SCE's combined Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC in February 2019.

MANAGEMENT OVERVIEW

Highlights of Operating Results

Edison International is the parent holding company of SCE and Edison Energy Group. 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 Energy Group is a holding company for Edison Energy which is engaged in the competitive business of providing energy services to commercial and industrial customers. Edison Energy's 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 competitive subsidiaries. Unless otherwise described, all the information contained in this report relates to both filers.



(in millions)	2019			2018			2019 vs 2018 Change			2017
Net income (loss) attributable to Edison International
Continuing operations
SCE	$	1,409		$	(310	)	$	1,719		$	1,012
Edison International Parent and Other	(125		)	(147		)	22			(447		)
Discontinued operations	—			34			(34		)	—
Edison International	1,284			(423		)	1,707			565
Less: Non-core items
SCE
Wildfire-related claims, net of recoveries	(157		)	(1,825		)	1,668			—
Impairment and other	(115		)	9			(124		)	(448		)
Wildfire insurance fund expense	(109		)	—			(109		)	—
Re-measurement of deferred taxes	88			—			88			(33		)
Settlement of 1994 – 2006 California tax audits	—			66			(66		)	—
Edison International Parent and Other
Goodwill impairment	(18		)	—			(18		)	—
Sale of SoCore Energy and other	—			(46		)	46			13
Settlement of 1994 – 2006 California tax audits	—			(12		)	12			—
Re-measurement of deferred taxes	—			—			—			(433		)
Discontinued operations	—			34			(34		)	—
Total non-core items	(311		)	(1,774		)	1,463			(901		)
Core earnings (losses)
SCE	1,702			1,440			262			1,493
Edison International Parent and Other	(107		)	(89		)	(18		)	(27		)
Edison International	$	1,595		$	1,351		$	244		$	1,466

Edison International's earnings are prepared in accordance with GAAP. Management uses core earnings (losses) 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 non-core

items. Non-core items include 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 write downs, asset impairments and other income and expense related to changes in law, outcomes in tax, regulatory or legal proceedings, and exit activities, including sale of certain assets and other activities that are no longer continuing.

Edison International's 2019 earnings increased $1,707 million, driven by an increase in SCE's earnings of $1,719 million and a decrease in Edison International Parent and Other losses of $22 million, partially offset by $34 million of income from discontinued operations in 2018. SCE's higher net income consisted of $1,457 million of lower non-core losses and $262 million of higher core earnings.

The increase in core earnings was due to the adoption of the 2018 GRC final decision in 2019, higher FERC revenue due to the settlement of SCE's 2018 Formula Rate proceeding and rate base growth, and the timing of regulatory deferral and cost recovery of incremental wildfire insurance expenses. These increases were partially offset by higher inspection, preventive maintenance and vegetation management costs that were not deferred as regulatory assets.

Edison International Parent and Other losses from continuing operations for 2019 consisted of $18 million of higher core losses and $40 million of lower non-core losses. The increase in core losses in 2019 was primarily due to higher interest expense and lower income tax benefits, partially offset by lower losses from the competitive businesses under Edison Energy Group.

Consolidated non-core items for 2019 and 2018 for Edison International included:


•	Charges of $218 million ($157 million after-tax) in 2019 and $2.5 billion ($1.8 billion after-tax) in 2018 for SCE's wildfire-related claims, net of expected recoveries from insurance and FERC customers.


•	An impairment charge of $170 million ($123 million after-tax) recorded in 2019 for SCE related to disallowed historical capital expenditures in SCE's 2018 GRC final decision.


•	A charge of $152 million ($109 million after-tax) recorded in 2019 from the amortization of SCE's contributions to the Wildfire Insurance Fund. See "Notes to Consolidated Financial Statements— Note 12. Commitments and Contingencies" for further information.

•

Income tax benefit of $88 million recorded in 2019 for SCE related to changes in the allocation of deferred tax re-measurement between customers and shareholders as a result of a CPUC resolution issued in February 2019. The resolution determined that customers are only entitled to excess deferred taxes which were included when setting rates and other deferred tax re-measurements belong to shareholders.


•	An impairment charge of $25 million ($18 million after-tax) in 2019 for Edison Energy following a goodwill assessment.


•	A loss of $56 million ($46 million after-tax) in 2018 for Edison International Parent and Other primarily related to sale of SoCore Energy in April 2018.


•	Income of $12 million ($9 million after-tax) in 2018 for SCE due to the elimination of the GHG Reduction Funding Program as a result of the Revised San Onofre Order Instituting Investigation Settlement Agreement among SCE, SDG&E and various intervening parties, dated January 30, 2018 and modified on August 2, 2018.


•	The 2018 settlement of the 1994 – 2006 California tax audits, which resulted in income tax expense of $12 million for Edison International Parent and Other and income tax benefits of $66 million and $34 million for SCE and discontinued operations, respectively.

See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations.

Wildfire Mitigation and Wildfire Insurance Expenses

In response to the increase in wildfire activity, and faster progression of and increased damage from wildfires across SCE's service territory and throughout California, SCE is currently incurring wildfire mitigation and wildfire insurance related spending at levels significantly exceeding amounts authorized in its 2018 GRC. Several regulatory mechanisms, including but not limited to the GS&RP memorandum account, the FHPMA, the WMP memorandum account and the WEMA, exist to allow SCE to track and seek recovery of these incremental costs. In accordance with the accounting standards applicable to rate-regulated enterprises, SCE defers costs as regulatory assets that are probable of future recovery from customers and has recorded regulatory assets for these incremental costs. As of December 31, 2019, SCE has recognized $400 million of regulatory assets related to incremental wildfire mitigation expenses and $341 million of regulatory assets related to incremental wildfire insurance expenses. While SCE believes such costs are probable of future recovery, there is no assurance that SCE will collect all amounts currently deferred as regulatory assets. SCE has recorded a further $754 million of wildfire mitigation capital expenditures that could be subject to reasonableness review through the GS&RP and separate tracks of the 2021 GRC proceeding.

Grid Safety and Resiliency Program

In September 2018, SCE filed an application with the CPUC requesting approval of a GS&RP to implement additional wildfire safety measures, including measures to further harden SCE's infrastructure to significantly reduce potential fire ignition sources, bolster SCE's situational awareness capabilities to more fully assess and respond to potential wildfire conditions, and enhance SCE's operational practices to further strengthen fire safety measures and system resiliency. In its GS&RP application, SCE proposed to spend approximately $582 million ($407 million capital) in 2018 dollars between 2018 and 2020 in excess of amounts authorized in SCE's 2018 GRC and requested a balancing account to recover the incremental costs of implementing the program. In January 2019, the CPUC approved the establishment of an interim memorandum account to track GS&RP costs while the CPUC considers SCE's application. There is no assurance that SCE will be allowed to ultimately recover these costs.

In July 2019, SCE and certain parties to SCE's GS&RP proceeding submitted a motion to the CPUC requesting approval of a settlement agreement. If the CPUC approves the settlement agreement, SCE will be authorized to spend approximately $526 million ($407 million capital) in 2018 dollars between 2018 and 2020. If approved by the CPUC, SCE will include the authorized revenue requirement in rates and establish a balancing account to track the difference between actual GS&RP costs and amounts authorized. If spending is less than authorized, SCE will refund those amounts to customers. If spending is in excess of forecasted amounts, or in excess of 115% of forecasted amounts for certain activities, SCE will present those costs for reasonableness review in a later track of the 2021 GRC.

GS&RP capital expenditures for 2019 and 2018 were $370 million and $49 million, respectively. Forecasted GS&RP capital expenditures for 2020 are $564 million excluding capitalized indirect costs. In 2019, $37 million of expenses were recorded to the interim memorandum account.

Wildfire Mitigation Plans

Under AB 1054, SCE is required to submit a wildfire mitigation plan to the CPUC annually for review and approval. SCE's WMPs describe strategies, programs and activities that are in place, being implemented or are under development by SCE, including associated cost estimates, to proactively address and mitigate the threat of electrical infrastructure-associated ignitions that could lead to wildfires. Beginning in 2020, each WMP is required to cover at least a three-year period.

SCE filed its 2019 and 2020 WMPs with the CPUC in February 2019 and February 2020, respectively. Many, but not all, of the programs and activities described in SCE's 2019 and 2020 WMPs are part of SCE's 2018 and 2021 GRC requests or GS&RP application. As required by the CPUC, SCE's 2020 WMP includes updates in the areas of inspection and maintenance, vegetation management, system hardening, and situational awareness.

In May 2019, the CPUC approved SCE's 2019 WMP, however, such approval does not authorize the associated spending. The CPUC decision required SCE to meet certain reporting requirements, capture data, and improve its metrics for evaluating performance. During 2019 SCE recorded $307 million of expenses in the WMP memorandum account. During 2019, WMP capital expenditures not authorized in the 2018 GRC or contemplated in the GS&RP proceedings were $335 million. Forecasted 2020 WMP direct costs not authorized in the 2018 GRC or contemplated in the GS&RP proceedings are $557 million, of which $244 million is capital.

The WMP memorandum account will be subject to a subsequent reasonableness review through separate tracks of the 2021 GRC.

Fire Hazard Prevention Memorandum Account

The FHPMA was established to record the costs incurred related to fire hazard prevention in compliance with decisions from the CPUC. SCE has used the FHPMA to track incremental vegetation management activities to reduce the risk of fires. As of December 31, 2019, operation and maintenance expenses of $198 million have been recorded to the FHPMA.

The FHPMA is expected to be subject to a subsequent reasonableness review through separate tracks of the 2021 GRC.

Wildfire Expense Memorandum Account

SCE tracks insurance premium costs related to wildfire liability insurance policies as well as other wildfire-related costs in its WEMA. In July 2019, SCE filed a WEMA application with the CPUC to seek recovery of $478 million in wildfire insurance premium costs incurred in excess of premiums approved in the 2018 GRC. As of December 31, 2019, SCE has recognized $341 million of regulatory assets in the WEMA related to incremental wildfire insurance costs.

2018 General Rate Case

In May 2019, the CPUC approved a final decision in SCE's 2018 GRC. The final decision authorized a revenue requirement of $5.1 billion for 2018 and identified changes to certain balancing accounts, including the expansion of the TAMA to include the impacts of all differences between forecast and recorded tax expense. The final decision also disallowed certain historical spending, largely related to specific pole replacements the CPUC determined were performed prematurely.

The final decision allows a post-test year rate making mechanism that escalates capital additions by 2.49% for both 2019 and 2020. It also allows operation and maintenance expenses to be escalated for 2019 and 2020 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology set forth in the final decision results in a revenue requirement of $5.5 billion in 2019 and $5.9 billion in 2020.

The revenue requirements in the 2018 GRC final decision are retroactive to January 1, 2018. SCE recorded the prior period impact of the 2018 GRC final decision in 2019, including an increase to core earnings of $131 million from the application of the decision to revenue, depreciation expense and income tax expense and a non-core impairment of utility property, plant and equipment of $170 million ($123 million after-tax) related to disallowed historical capital expenditures. See "Results of Operations—SCE" and "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies" for further information.

2020 Cost of Capital Application

In April 2019, SCE filed an application with the CPUC for authority to establish its authorized cost of capital for utility operations for a three-year term, beginning January 1, 2020. In December 2019, the CPUC issued a final decision increasing the common equity component of SCE's capital structure from its current authorized level of 48% to 52% in 2020 and correspondingly reducing its preferred equity component from 9% to 5%. The final decision maintains SCE's CPUC ROE for the three-year period beginning January 1, 2020 at 10.3%. Under the decision, SCE's annual cost of capital adjustment mechanism also remains unchanged. Under the final decision, SCE's 2020 authorized cost of long-term debt and preferred equity are 4.74% and 5.70%, respectively. Based on the approved capital structure and costs, SCE's weighted average return on rate base for 2020 will be 7.68%.

Based on the revenue requirement approved in SCE's 2018 GRC, SCE’s cost of capital and capital structure approved in the final decision will result in a projected revenue requirement increase in 2020 of approximately $38 million from revenue currently included in CPUC electric rates of $5.9 billion.

2018 and 2019 FERC Formula Rate

In December 2019, the FERC approved a settlement on SCE's formula rates for the 2018 Formula Rate case that established SCE's FERC transmission revenue requirement for the FERC 2018 Settlement Period. The settlement provides for a weighted average ROE of 11.2%, which includes a previously authorized 50 basis point incentive for CAISO participation and individual and previously authorized project incentives. Under the settlement, if the FERC issues a final, unappealable ruling that finds SCE is not eligible for the 50 basis point incentive for CAISO participation, then the ROE for the FERC 2018 Settlement Period will be reduced to 10.7%. Prior to the settlement, SCE had been recognizing revenue during the FERC 2018 Settlement Period based on its expectations of the outcome of the 2018 Formula Rate case. Regulatory assets and liabilities were adjusted based on the settlement of the 2018 Formula Rate case, which resulted in an increase in net income of $29 million related to 2018, being recorded in 2019. The transmission revenue requirement and rates that have been billed to customers for the FERC 2018 Settlement Period were based on a total FERC weighted average ROE of 11.58%, and SCE expects to refund excess amounts billed to customers during 2020. In the 2019 Formula Rate case, SCE's requested base

return on equity, as modified by a partial settlement approved by the FERC, is 11.97% ("FERC Base ROE"). This ROE request reflects a conventional ROE of 11.12% and an additional ROE of 0.85% to compensate investors for current wildfire risk. As with SCE's requested ROE in its 2020 CPUC Cost of Capital proceeding, this request reflects the anticipated impact of AB 1054 on SCE's requested ROE. SCE's total ROE request, inclusive of project incentives and a 0.5% incentive for CAISO participation, would be approximately 13.25%. The 2019 Formula Rate was implemented in rates in November 2019 and remains subject to hearing and settlement procedures. Amounts billed to customers under the 2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved.

In November 2019, the FERC issued a decision in a pending Midcontinent Independent System Operator Transmission Owners ("MISO TO") proceeding which significantly revised the methodology used to determine MISO TO's just and reasonable ROE levels by restricting the valuation methodologies that would be recognized by the FERC in establishing a zone of reasonableness for ROE. The decision also reiterated that authorized ROE, including FERC-authorized project incentives, could not exceed the established zone of reasonableness. The updated methodology led to an authorized ROE for MISO TO of 9.88%, compared to their previously authorized ROE of 12.38%. Numerous parties requested rehearing of the MISO decision on various grounds and, in January 2020, the FERC granted rehearing requests for the limited purpose of allowing the FERC additional time for consideration of the concerns raised.

In December 2019, the CPUC filed a protest with the FERC alleging that $419 million of costs associated with SCE's Tehachapi Transmission Project are imprudent and should be disallowed from SCE's FERC rate base because these costs exceeded the maximum reasonable costs identified by the CPUC when it granted the project’s certificate of public convenience and necessity. The CPUC requested that the FERC set this issue for hearings and consolidate the protest with the settlement proceedings of the 2019 Formula Rate case.

Southern California Wildfires and Mudslides

Multiple factors have contributed to increased wildfire activity, and faster progression of and increased damage from wildfires across SCE's service territory and throughout California. These include the buildup of dry vegetation in areas severely impacted by years of historic drought, lack of adequate clearing of hazardous fuels by responsible parties, higher temperatures, lower humidity, and strong Santa Ana winds. At the same time that wildfire risk has been increasing in Southern California, residential and commercial development has occurred and is occurring in some of the highest-risk areas. Such factors can increase the likelihood and extent of wildfires. SCE has determined that approximately 27% of its service territory is in areas identified as high fire risk.

Over the past several years, wind-driven wildfires impacted portions of SCE's service territory, with wildfires in December 2017 and November 2018 causing loss of life, substantial damage to both residential and business properties, and service outages for SCE customers. In 2019, several wind-driven wildfires originated in Southern California. SCE does not expect any of these 2019 fires to have a material adverse effect on its financial condition, results of operations or cash flows.

Edison International and SCE recorded a charge of $255 million as of December 31, 2019 for wildfire-related claims, net of expected insurance recoveries. The 2019 charge consists of an increase in estimated losses for claims related to the 2017/2018 Wildfire/Mudslide Events of $232 million, against which SCE has recorded expected recoveries through FERC electric rates of $14 million. The resulting charge was $218 million ($157 million after-tax). The fourth quarter 2019 charge also includes $23 million ($17 million after-tax) of expenses primarily associated with self-insured retention for fires that occurred in Southern California in 2019.

2017/2018 Wildfire/Mudslide Events

The investigating government agencies, the VCFD and CAL FIRE, have determined that the largest of the 2017 fires originated on December 4, 2017, in the Anlauf Canyon area of Ventura County (the investigating agencies refer to this fire as the "Thomas Fire"), followed shortly thereafter by the Koenigstein Fire. While the progression of these two fires remains under review, the December 4, 2017 fires eventually burned substantial acreage in both Ventura and Santa Barbara Counties. The largest of the November 2018 fires, known as the Woolsey Fire, originated in Ventura County and burned acreage in both Ventura and Los Angeles Counties.

In March 2019, the VCFD and CAL FIRE jointly issued separate reports finding that the Thomas Fire and the Koenigstein Fire were each caused by SCE equipment. At this time, based on available information, SCE has not determined whether its equipment caused the Thomas Fire. Based on publicly available radar data showing a smoke plume in the Anlauf Canyon area emerging in advance of the start time of the Thomas Fire indicated in the Thomas Fire report, SCE believes that the Thomas Fire started at least 12 minutes prior to any issue involving SCE's system and at least 15 minutes prior to the start time indicated in the report. SCE has previously disclosed that SCE believed its equipment was associated with the ignition

of the Koenigstein Fire. SCE is continuing to assess the progression of the Thomas and Koenigstein Fires and the extent of damages that may be attributable to each fire.

SCE has received a non-final redacted draft of a report from the VCFD subject to a protective order in the litigation related to the Woolsey fire and, other than the information disclosed in this Form 10-K, is not authorized to release the report or its contents to the public at this time. The draft report states that the VCFD investigation team determined that electrical equipment owned and operated by SCE was the cause of the Woolsey Fire. Absent additional evidence, SCE believes that it is likely that its equipment was associated with the ignition of the Woolsey Fire.

Multiple lawsuits related to the Thomas and Koenigstein Fires and the Woolsey Fire have been initiated against SCE and Edison International. Some of the Thomas and Koenigstein Fires lawsuits claim that SCE and Edison International have responsibility for the damages caused by the Montecito Mudslides based on a theory alleging that SCE has responsibility for the Thomas and/or Koenigstein Fires and that the Thomas and/or Koenigstein Fires proximately caused the Montecito Mudslides.

SCE's internal review into the facts and circumstances of each of the 2017/2018 Wildfire/Mudslide Events is ongoing, and SCE expects to obtain and review additional information and materials in the possession of third parties during the course of its internal reviews and the litigation processes. Final determinations of liability for the Thomas Fire, the Koenigstein Fire, the Montecito Mudslides and the Woolsey Fire (each a "2017/2018 Wildfire/Mudslide Event," and, collectively, the "2017/2018 Wildfire/Mudslide Events"), including determinations of whether SCE was negligent, would only be made during lengthy and complex litigation processes. Even when investigations are still pending or liability is disputed, an assessment of likely outcomes, including through future settlement of disputed claims, may require a liability to be accrued under accounting standards. Based on information available to SCE and consideration of the risks associated with litigation, Edison International and SCE expect to incur a material loss in connection with the 2017/2018 Wildfire/Mudslide Events.

In the fourth quarter of 2018, SCE recorded a liability for estimated losses of $4.7 billion related to the 2017/2018 Wildfire/Mudslide Events. In the fourth quarter of 2019, SCE paid $360 million to a number of local public entities to resolve those parties' collective claims arising from the 2017/2018 Wildfire/Mudslide Events (the "Local Public Entity Settlements"). After the Local Public Entity Settlements, the liability accrued for estimated losses as of December 31, 2019 was reduced by the $360 million paid in the Local Public Entity Settlements.

Each reporting period, management reviews its loss estimates for remaining alleged and potential claims related to the 2017/2018 Wildfire/Mudslide Events. The process for estimating losses associated with wildfire litigation claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including, but not limited to: estimates of known and expected claims by third parties based on currently available information, opinions of counsel regarding litigation risk, the status of and developments in the course of litigation, and prior experience litigating and settling wildfire litigation claims. While the low end of the reasonably estimated range of expected losses for the 2017/2018 Wildfire/Mudslide Events is estimated on an aggregate basis, some of the factors evaluated by management in connection with its fourth quarter 2019 review contributed to a significant increase in certain loss estimates, while others contributed to a significant decrease in certain other loss estimates. The net result of management's fourth quarter 2019 review was an increase in estimated losses of $232 million for total estimated losses of $4.5 billion as of December 31, 2019 for unpaid claims related to the 2017/2018 Wildfire Mudslide Events. The accrued liability as of December 31, 2019 corresponds to the lower end of the reasonably estimated range of expected losses that may be incurred in connection with the 2017/2018 Wildfire/Mudslide Events and is subject to change as additional information becomes available.

Edison International and SCE will seek to offset any actual losses realized in connection with the 2017/2018 Wildfire/Mudslide Events with recoveries from insurance policies in place at the time of the events and, to the extent actual losses exceed insurance, through electric rates. As of December 31, 2019, Edison International and SCE have remaining expected recoveries from insurance of $1.7 billion and expected recoveries through FERC electric rates of $149 million on their consolidated balance sheets related to the 2017/2018 Wildfire/Mudslide Events. SCE believes that, in light of the CPUC's decision in a cost recovery proceeding involving SDG&E arising from several 2007 wildfires in SDG&E's service area, there is substantial uncertainty regarding how the CPUC will interpret and apply its prudency standard to an investor-owned utility in future wildfire cost-recovery proceedings for fires ignited prior to July 12, 2019. Accordingly, while the CPUC has not made a determination regarding SCE's prudency relative to any of the 2017/2018 Wildfire/Mudslide Events, SCE is unable to conclude, at this time, that uninsured CPUC-jurisdictional wildfire-related costs are probable of recovery through electric rates.

Edison International and SCE continue to pursue regulatory and legal strategies, and anticipate pursuing legislative strategies in the longer term, to address the application of a strict liability standard to wildfire-related property damages without the guaranteed ability to recover resulting costs in electric rates.

2019 Wildfire Legislation

In July 2019, AB 1054 was signed by the Governor of California and became effective immediately. The summary of the wildfire legislation in this report is based on SCE's interpretation of the legislation and is qualified in its entirety by, and should be read together with, AB 1054 and companion Assembly Bill 111.

Wildfire Insurance Fund

AB 1054 provided for the Wildfire Insurance Fund to reimburse utilities for payment of third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1.0 billion or the utility's insurance coverage. The Wildfire Insurance Fund was established in September 2019 when both SCE and SDG&E made their initial contributions to the fund. The Wildfire Insurance Fund is available for claims related to wildfires ignited after July 12, 2019 that are determined to have been caused by a utility by the responsible government investigatory agency.

SCE and SDG&E have collectively made their initial contributions totaling approximately $2.7 billion to the Wildfire Insurance Fund. While PG&E has committed to make an initial contribution of approximately $4.8 billion to the Wildfire Insurance Fund upon emergence from bankruptcy, its participation in, and contributions to the fund are subject to it resolving its bankruptcy proceeding and meeting certain other conditions prior to June 30, 2020. SCE, SDG&E and PG&E are also collectively expected to make aggregate contributions of $3.0 billion to the Wildfire Insurance Fund through annual contributions to the fund over a 10-year period, of which SCE and SDG&E have made their initial annual contributions totaling approximately $107 million. If PG&E is unable to participate in the Wildfire Insurance Fund, then SCE and SDG&E are collectively expected to make aggregate contributions of approximately $1.0 billion to the fund through annual contributions over the 10-year period. In addition to PG&E's, SCE's and SDG&E's contributions to the Wildfire Insurance Fund, $13.5 billion is expected to be collected over a 15-year period from their ratepayers through a dedicated rate component. The amount collected from ratepayers may be directly contributed to the Wildfire Insurance Fund or used to support the issuance of up to $10.5 billion in bonds by the California Department of Water Resources, the proceeds of which would be contributed to the fund. In addition to funding contributions to the Wildfire Insurance Fund, the amount collected from utility ratepayers will pay for, among other things, any interest and financing costs related to any bonds that are issued by the California Department of Water Resources to support the contributions to the Wildfire Insurance Fund. Based on a decision adopted by the CPUC in October 2019 in the Order Instituting Rulemaking to Consider Authorization of a Non-Bypassable Charge to Support the Wildfire Insurance Fund, PG&E's ratepayers will not be required to contribute to the fund if PG&E does not participate in the Wildfire Insurance Fund. In that case, $7.5 billion will be collected from SCE's and SDG&E's ratepayers through the dedicated rate component to support a contribution to the Wildfire Insurance Fund.

SCE made an initial contribution of approximately $2.4 billion to the Wildfire Insurance Fund in September 2019 and has committed to make ten annual contributions of approximately $95 million per year to the fund, by no later than January 1 of each year. SCE made its first annual contribution to the Wildfire Insurance Fund in December 2019. Edison International supported SCE's initial contribution to the Wildfire Insurance Fund by raising $1.2 billion from the issuance of Edison International equity. SCE raised the remaining $1.2 billion from the issuance of long-term debt. SCE's contributions to the Wildfire Insurance Fund will not be recoverable through electric rates and will be excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. SCE will also not be entitled to cost recovery for any borrowing costs incurred in connection with its contributions to the Wildfire Insurance Fund.

Participating investor-owned utilities will be reimbursed from the Wildfire Insurance Fund for eligible claims, subject to the fund administrator's review, and will be required to reimburse the fund for withdrawn amounts that the CPUC disallows subject, in some instances, to the AB 1054 Liability Cap. A utility will not be eligible for the AB 1054 Liability Cap if it does not maintain a valid safety certification or its actions or inactions that resulted in the wildfire are found to constitute conscious or willful disregard of the rights and safety of others. On July 25, 2019, SCE obtained its initial safety certification that will be valid for twelve months. Based on SCE's 2020 rate base and assuming the equity portion of SCE's capital structure is 52% (SCE's CPUC authorized capital structure), SCE's requirement to reimburse the Wildfire Insurance Fund for eligible claims disallowed in 2020 would be capped at approximately $3.0 billion. SCE will not be allowed to recover borrowing costs incurred to reimburse the fund for amounts that the CPUC disallows. The Wildfire Insurance Fund and, consequently, the AB 1054 Liability Cap will terminate when the administrator determines that the fund has been exhausted.

AB 1054 Prudency Standard

As a result of the establishment of the Wildfire Insurance Fund, AB 1054 created a new standard that the CPUC must apply when assessing the prudency of a utility in connection with a request for recovery of wildfire costs for wildfires ignited after July 12, 2019. Under AB 1054, the CPUC is required to find a utility to be prudent if the utility's conduct related to the ignition was consistent with actions that a reasonable utility would have undertaken under similar circumstances, at the

relevant point in time, and based on the information available at that time. Utilities with a valid safety certification will be presumed to have acted prudently related to a wildfire ignition unless a party in the cost recovery proceeding creates serious doubt as to the reasonableness of the utility's conduct, at which time, the burden shifts back to the utility to prove its conduct was reasonable. If a utility does not have a valid safety certification, it will have the burden to prove, based on a preponderance of evidence, that its conduct was prudent. The new prudency standard will survive the termination of the Wildfire Insurance Fund.

Utilities participating in the Wildfire Insurance Fund that are found to be prudent are not required to reimburse the fund for amounts withdrawn from the fund and can recover wildfire costs through electric rates if the fund has been exhausted.

Capital Expenditure Requirement

Under AB 1054, approximately $1.6 billion spent by SCE on wildfire risk mitigation capital expenditures made after August 1, 2019 cannot be included in the equity portion of SCE's rate base. SCE can apply for an irrevocable order from the CPUC to finance these capital expenditures, including through the issuance of securitized bonds, and can recover any prudently incurred financing costs. SCE expects to finance this capital requirement by issuing securitized bonds.

For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Initial and annual contributions to the wildfire insurance fund established pursuant to California Assembly Bill 1054," "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" and "Legal Proceedings."

2021 General Rate Case

In August 2019, SCE filed its 2021 GRC application for the three-year period 2021-2023. Following amendments and other revisions to the application in November 2019 and February 2020, SCE’s 2021 revenue requirement is $7.6 billion. SCE's request excludes the revenue requirement associated with the approximately $1.6 billion in wildfire risk mitigation capital expenditures that SCE will exclude from the equity portion of rate base as required under AB 1054.

In the amendment of February 2020, SCE removed its CSRP implementation costs from the 2021 GRC. SCE will continue to track the cost of the CSRP program in a memorandum account previously approved in the 2018 GRC and review of the CSRP implementation costs will be deferred to a future application to the CPUC.

The 2021 revenue requirement represents an increase of $1.1 billion over the 2020 revenue requirement authorized in the 2018 GRC and updated for anticipated post test-year ratemaking changes. Including the impact of anticipated lower kilowatt-hour sales in 2021 and one-time memorandum account recoveries, this represents an 11.4% increase over 2020 rates. SCE's 2021 GRC request also includes proposed revenue requirement increases of $423 million in 2022 and $514 million in 2023. The updated revenue requirements were requested based on the ROE and capital structure authorized at the time of the initial filing. A new capital structure has since been authorized. See "—2020 Cost of Capital Application."

SCE's requested increase to its revenue requirement in the 2021 GRC application is largely due to SCE's efforts to reduce wildfire risk. Certain of SCE's key wildfire mitigation forecast expenditures are subject to significant potential volatility. As a result, SCE has proposed establishing two-way balancing accounts for wildfire mitigation-related enhanced vegetation management, inspection activities and grid hardening, as well as for insurance premiums.

The capital programs requested in SCE's 2021 GRC include the infrastructure and programs necessary to implement California's ambitious public policy goals, including wildfire mitigation, de-carbonization of the economy through electrification and integration of distributed energy resources across a rapidly modernizing grid. See "—Capital Program" for further details.

The schedule established in the proceeding includes CPUC issuance of a proposed decision in the fourth quarter of 2020, or during the first quarter of 2021. If the final decision is issued in 2021, SCE will, consistent with CPUC practice in prior GRCs, request the CPUC to issue an order directing that the authorized revenue requirement changes be effective January 1, 2021.

Historically, the CPUC has set an annual revenue requirement for the base year and then set the remaining two years by a methodology established in the GRC proceeding. In January 2020, the CPUC approved a change from a triennial GRC cycle to a quadrennial GRC cycle for large energy utilities such as SCE. SCE is required to file an amendment to its application for the three-year period 2021 – 2023 to add an attrition year for 2024. The timing of the amendment is subject to further direction from the CPUC.

Electricity Industry Trends

In addition to responding to the "new normal" of increased wildfire-activity in California, the electric power industry is also undergoing transformative change driven by technological advances, such as customer-owned generation, electric vehicles and energy storage, which are altering the nature of energy generation and delivery. California is committed to reducing its GHG emissions, improving local air quality and supporting continued economic growth. The state set goals to reduce GHG emissions by 40% from 1990 levels by 2030 and 80% from the same baseline by 2050. Additionally, the state is aiming to be carbon neutral by 2045. State and local air quality plans call for substantial improvements, such as reducing smog-causing nitrogen oxides 90% below 2010 levels by 2032 in the most polluted areas of the state. While these policy goals cannot be achieved by the electric sector alone, the electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives. Therefore, California has set RPS targets which require California retail sellers of electricity to provide 60% of energy sales from renewable resources by 2030. California also requires sellers of electricity to deliver 100% of retail sales from carbon free sources by 2045. In 2019 approximately 48% of SCE's customer deliveries came from carbon-free resources. SCE's climate change objectives align with California's requirements, and SCE anticipates it will meet its own objectives, and therefore California's requirements, through 2045.

The grid is also key to enabling more customer choices with respect to new energy technologies, including fostering the adoption of electric vehicles. Edison International believes that California's 2045 goals can be achieved most economically through emissions reductions from using clean electricity serving 100% of retail sales, electrifying 75% of vehicles and 70% of buildings and using low-carbon fuels for technologies that are not yet viable for electrification. Edison International expects to lead the transformation of the industry by building a modernized and more reliable grid, focusing on opportunities in clean energy and efficient electrification, and enabling customers' technology choices.

SCE plans to enable the adoption of new energy technologies that mitigate wildfire risk and benefit customers of the electric grid while also helping California achieve its environmental goals. SCE expects to achieve these objectives through improving the safety and reliability of the transmission and distribution network and helping customers make cleaner energy choices including enabling increased penetration of DERs, electric transportation, building electrification and energy efficiency programs. SCE's ongoing focus to drive operational and service excellence is intended to allow it to achieve these objectives safely while controlling costs and customer rates. SCE's focus on the transmission and distribution of electricity aligns with California's policy supporting competitive power procurement markets. For more information on the grid development, see "Liquidity and Capital Resources—Capital Investment Plan—Grid Development—Wildfire Mitigation" and "Liquidity and Capital Resources—Capital Investment Plan—Grid Development—Transportation Electrification."

Changes in the electric power industry are impacting customers and jurisdictions outside California as well. Edison International believes that other states will also pursue climate change and GHG reduction objectives and large commercial and industrial customers will continue to pursue cost reduction and sustainability goals. Edison Energy provides energy services and managed portfolio solutions to commercial and industrial customers who may be impacted by these changes. Edison Energy seeks to provide advice in dealing with increasingly complex tariff and technology choices in order to support customers and their management of energy costs and risks.

To better engage in this broader transformation and provide a view of developments outside of SCE, Edison International has made several minority investments in emerging companies in areas related to the technology changes that are driving industry transformation and may make additional investments in the future. These investments are not financially material to Edison International.

Capital Program

Total capital expenditures (including accruals) were $4.8 billion in 2019 and $4.4 billion in 2018. SCE's year-end rate base was $32.6 billion at December 31, 2019 compared to $29.6 billion at December 31, 2018. Under AB 1054, approximately $1.6 billion of wildfire risk mitigation capital expenditures cannot be included in the equity portion of SCE's rate base and instead can be recovered through issuance of securitized bonds. The year-end rate base of $32.6 billion at December 31, 2019 excludes $252 million wildfire risk mitigation capital expenditures as required by AB 1054.

Based on the 2021 GRC request, SCE forecasts capital expenditures for 2020 – 2023 to be approximately $19.4 billion to $21.2 billion. SCE's capital expenditure forecast for 2020 reflects planned CPUC jurisdictional spending as informed by the 2018 GRC final decision, spending associated with SCE's wildfire mitigation-related capital expenditures under the GS&RP and WMP, and current expectations of FERC- jurisdictional spending. SCE's capital expenditure forecast for 2021 – 2023 reflects the requested CPUC jurisdictional spending included in the 2021 GRC application, approved non-GRC CPUC capital spending, and current expectations of FERC- jurisdictional capital spending. SCE's forecasted capital expenditures for 2020 – 2021 include approximately $300 million of capital spending on the CSRP project. Total forecasted capital expenditures for

the CSRP project are approximately $540 million from inception through 2021. In the 2018 GRC, SCE provided a cost estimate to the CPUC of $209 million in capital expenditures for the CSRP program. In February 2020, SCE filed an update with the CPUC to exclude CSRP program expenditures from rate base and capital expenditures of the 2021 GRC application and to continue to track the cost of the CSRP program in a memorandum account previously approved in the 2018 GRC. Forecasted expenditures for FERC-jurisdictional capital projects are subject to change due to timeliness of permitting, licensing, regulatory approvals and contractor bids. Capital spending in 2021, 2022 and 2023 will be dependent upon the amount approved in a 2021 GRC final decision.

Based on management judgment using historical precedent of previously authorized amounts and potential permitting delays and other operational considerations, a range case has been provided reflecting a 10% reduction on the total capital forecast for 2021 – 2023 and a 10% reduction on FERC capital spending and non-GRC programs for 2020.

The following table sets forth a summary of capital expenditures for 2019 actual spend and a forecast for 2020 – 2023 on the basis described above:



(in billions)	2019		2020		2021		2022		2023		Total 2020 – 2023
Traditional capital expenditures
Distribution	$	3.1	$	3.2	$	3.4	$	3.3	$	3.2	$	13.1
Transmission	0.8		0.7		0.8		0.8		0.6		2.9
Generation	0.2		0.2		0.2		0.2		0.2		0.8
Subtotal	4.1		4.1		4.4		4.3		4.0		16.8
Wildfire mitigation-related capital expenditures	0.7		0.9		1.0		1.1		1.4		4.4
Total capital expenditures	$	4.8	$	5.0	$	5.4	$	5.4	$	5.4	$	21.2
Total capital expenditures using range case discussed above	*		$	4.8	$	4.9	$	4.9	$	4.8	$	19.4

* Not applicable

SCE's authorized CPUC-jurisdictional rate base is determined through the GRC and other regulatory proceedings. Differences between actual and CPUC-authorized capital expenditures are addressed in subsequent GRC or other regulatory proceedings. FERC-jurisdictional rate base is generally determined based on actual capital expenditures.

Reflected below is SCE's weighted average annual rate base for 2019 – 2023 incorporating CPUC capital expenditures authorized in the 2018 GRC final decision, expected FERC capital expenditures and capital expenditures included in the 2021 GRC application. The table below does not reflect the $1.6 billion of wildfire risk mitigation capital expenditures to be excluded from the equity portion of SCE's rate base under AB 1054. The table below does not reflect rate base associated with non-GRC projects or programs that have not yet been approved by the CPUC, including CSRP, with the exception of GS&RP spend incurred before August 1, 2019. In addition, a third-party holds an option to invest up to $400 million in the West of Devers Transmission project at the estimated in-service date of 2021. The rate base in the table below is reduced to reflect this option.



(in billions)	2019		2020		2021		2022		2023
Rate base for expected capital expenditures	$	30.8	$	33.4	$	35.9	$	38.2	$	41.0
Rate base for expected capital expenditures (using range case described above)	*		$	33.3	$	35.1	$	37.0	$	39.2

* Not applicable

For additional information, see "Liquidity and Capital Resources—Capital Investment Plan."

RESULTS OF OPERATIONS

SCE

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

•

Earning activities – representing revenue authorized by the CPUC and the 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 earnings activities are revenue or penalties related to incentive mechanisms, other operating revenue and regulatory charges or disallowances.

•

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. 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) and certain operation and maintenance expenses. SCE earns no return on these activities.

Impact of 2018 GRC

The 2018 GRC final decision determines the amount of revenue that SCE is authorized to collect from customers to recover anticipated costs, including return on rate base. The 2018 GRC final decision approved an authorized revenue requirement of $5.1 billion for 2018, the first year ("Test Year") of the three-year GRC period, and authorized annual increases under a set escalation mechanism based on labor, non-labor and medical expenses.

In the absence of a 2018 GRC final decision, SCE recognized revenue in 2018 and the first quarter of 2019 based on the 2017 authorized revenue requirement, adjusted for items SCE determined to be probable of occurring, primarily the July 2017 cost of capital decision and Tax Reform. Adjustments were also made to 2017 authorized revenue to reflect changes in authorized tax benefits for certain balancing accounts.

As indicated in the table below, authorized revenue in the 2018 GRC final decision is less than the amount recognized in 2018:



(in millions)	2017 Authorized Revenue		Adjustments			2018 Revenue Recognized in Form 10-K			2018 Test Year Authorized Revenue			Adjustment to 2018 Revenue Recorded in 2019
Authorized revenue	$	5,640	$	(235	)	$	5,405		$	5,116		$	(289	)	¹
Cost of service:
Operation and maintenance	1,931		(11		)	1,920			1,582			(338		)	²
Depreciation	1,575		59			1,634			1,579			(55		)	³
Property and payroll taxes	285		9			294			315			21
Income taxes	257		(287		)	(30		)	(19		)	11
Authorized return	1,592		(5		)	1,587			1,659			72
Total authorized revenue	$	5,640	$	(235	)	$	5,405		$	5,116		$	(289	)


¹	The change in authorized revenue in the Test Year is comprised of $129 million in earnings activities and $160 million in cost recovery activities.


²	Authorized revenue for operation and maintenance costs decreased due to:


•	$178 million reduction for earnings activities primarily from SCE's initiatives to improve operational efficiency, which has resulted in lower forecasted costs than included in the 2017 authorized amounts.


•	$160 million reduction in cost-recovery activities, which do not impact earnings, primarily for medical and employee benefit costs.

³ Authorized revenue for depreciation decreased as a result of lower authorized depreciation rates.

After the application of escalation factors to the Test Year, the CPUC authorized SCE to collect $5.5 billion from customers in 2019. During the second quarter of 2019, SCE recorded a reduction of revenue of $265 million to reflect $289 million of lower authorized revenue related to 2018 and $24 million of higher authorized revenue in 2019. The 2018 GRC final decision is retroactive to January 1, 2018 and the reduction of revenue contributed to a refund to customers of $554 million, which SCE recorded as a regulatory liability. SCE expects to refund these amounts to customers through December 2020.

Years ended December 31, 2019, 2018 and 2017

The following table is a summary of SCE's results of operations for the periods indicated:



	2019									2018									2017
(in millions)	Earning Activities			Cost- Recovery Activities			Total Consolidated			Earning Activities			Cost- Recovery Activities			Total Consolidated			Earning Activities			Cost- Recovery Activities			Total Consolidated
Operating revenue	$	6,678		$	5,628		$	12,306		$	6,560		$	6,051		$	12,611		$	6,611		$	5,643		$	12,254
Purchased power and fuel	—			4,839			4,839			—			5,406			5,406			—			4,873			4,873
Operation and maintenance¹	2,073			863			2,936			1,972			730			2,702			1,898			824			2,722
Wildfire-related claims, net of insurance recoveries	255			—			255			2,669			—			2,669			—			—			—
Wildfire insurance fund expense	152			—			152			—			—			—			—			—			—
Depreciation and amortization	1,727			1			1,728			1,867			—			1,867			2,032			—			2,032
Property and other taxes	396			—			396			392			—			392			372			—			372
Impairment and other	159			—			159			(12		)	—			(12		)	716			—			716
Other operating income	(4		)	—			(4		)	(7		)				(7		)	(8		)	—			(8		)
Total operating expenses	4,758			5,703			10,461			6,881			6,136			13,017			5,010			5,697			10,707
Operating income (loss)	1,920			(75		)	1,845			(321		)	(85		)	(406		)	1,601			(54		)	1,547
Interest expense	(738		)	(1		)	(739		)	(671		)	(2		)	(673		)	(588		)	(1		)	(589		)
Other income	119			76			195			107			87			194			93			55			148
Income (loss) before income taxes	1,301			—			1,301			(885		)	—			(885		)	1,106			—			1,106
Income tax benefit	(229		)				(229		)	(696		)	—			(696		)	(30		)	—			(30		)
Net income (loss)	1,530			—			1,530			(189		)	—			(189		)	1,136			—			1,136
Preferred and preference stock dividend requirements	121						121			121			—			121			124			—			124
Net income (loss) available for common stock	$	1,409		$	—		$	1,409		$	(310	)	$	—		$	(310	)	$	1,012		$	—		$	1,012
Net income (loss) available for common stock							$	1,409								$	(310	)							$	1,012
Less: Non-core items
Wildfire insurance fund expense							(109		)							—									—
Wildfire-related claims, net of recoveries							(157		)							(1,825		)							—
Impairment and other							(115		)							9									(448		)
Re-measurement of deferred taxes							88									—									(33		)
Settlement of California tax audits																66									—
Core earnings²							$	1,702								$	1,440								$	1,493


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

Earning Activities

2019 vs 2018

Earning activities were primarily affected by the following:


•	Higher operating revenue of $118 million is primarily due to:


•	An increase in CPUC-related revenue of $100 million primarily due to the adoption of the 2018 GRC final decision, including the application of the decision retroactively to January 1, 2018, as discussed above.


•	An increase of $38 million in FERC-related revenue primarily due to the settlement of SCE's 2018 Formula Rate proceeding, rate base growth and higher operating costs subject to balancing account treatment, partially offset by lower recoveries from FERC customers for wildfire-related claims in 2019 as compared to 2018.


•	A decrease in other operating revenue of $20 million primarily due to rate adjustments implemented in the second quarter of 2019.

•

Higher operation and maintenance expenses of $101 million primarily due to expenses related to wildfire mitigation activity that were not deferred as regulatory assets. Activities driving higher expenses included higher inspection, preventive maintenance and vegetation management costs in non-high fire risk areas. SCE has not recorded regulatory assets for $119 million of 2019 wildfire mitigation costs as there is no current precedent for recovery of these costs, but SCE is seeking recovery of these costs through a separate track of the 2021 GRC. Those costs were partially offset by the impact of the adoption of the 2018 GRC final decision primarily due to a change in capitalization rates and the timing of regulatory deferral and cost recovery of incremental wildfire insurance expenses.


•	Charges of $255 million and $2.7 billion recorded in 2019 and 2018, respectively, for wildfire-related claims, net of expected insurance recoveries.


•	Expense of $152 million for insurance protection from the Wildfire Insurance Fund following SCE's election to participate in and contribute to the fund. See "Management Overview—Southern California Wildfires and Mudslides" for further information.


•	Lower depreciation and amortization expense of $140 million primarily related to the change in depreciation rates and the impact of disallowed historical capital expenditures from the adoption of the 2018 GRC final decision.


•	Higher impairment and other of $171 million primarily related to the disallowed historical capital expenditures in SCE's 2018 GRC final decision, as discussed above.


•	Higher interest expense of $67 million primarily due to increased borrowings.


•	Higher other income of $12 million primarily due to interest income from various balancing accounts.


•	Lower income tax benefits of $467 million primarily due to the following:


•	Lower tax benefit of $612 million due to higher pre-tax income.


•	Lower tax benefit of $66 million due to the 2018 settlement of the 1994 – 2006 California tax audit.


•	Higher tax benefit of $211 million primarily due to the changes in the allocation of deferred tax re-measurement between customers and shareholders as a result of a CPUC resolution issued in February 2019, the adoption of the 2018 GRC final decision and tax benefit on property-related items.

Cost-Recovery Activities

2019 vs 2018

Cost-recovery activities were primarily affected by the following:


•	Lower purchased power and fuel costs of $567 million primarily driven by lower load related to customer departures to CCAs and cooler weather, partially offset by lower congestion revenue right credits, higher contract termination charges and the absence of settlement funds received in 2018 related to the California energy crisis.


•	Higher operation and maintenance expenses of $133 million primarily driven by the authorization to recover 2018 wildfire insurance costs that had been deferred as regulatory assets and higher transmission access charges, partially offset by lower employee-related expenses subject to balancing account treatment and lower spending on public programs.


•	Lower other income of $11 million primarily driven by lower net periodic benefit income related to the non-service cost components for SCE's other post-retirement benefit plans. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for further information.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales) was $11.4 billion, $11.7 billion and $11.4 billion for 2019, 2018 and 2017, respectively.

The 2019 revenue decrease is primarily related to lower load related to customer departures to CCAs and cooler weather, partially offset by higher CPUC revenue due to the adoption of the 2018 GRC final decision. See "—Cost-Recovery Activities" and "—Earnings Activities" for further details.

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

Income Taxes

SCE's income tax provision decreased by $467 million in 2019 compared to 2018. The effective tax rates were (17.6)% and (78.6)% for 2019 and 2018, respectively. SCE's effective tax rate is below the federal statutory rate of 21% for 2019 and 2018 primarily due to the CPUC's 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. The effective tax rate decrease in 2019 is primarily due to impact of higher pre-tax income and absence of the 2018 settlement of the 1994 – 2006 California tax audit in 2018, partially offset by higher tax benefits on property-related items recorded as a result of 2018 GRC final decision and the changes in the allocation of excess deferred tax re-measurement between customers and shareholders as a result of a CPUC resolution issued in February 2019.

See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for a reconciliation of the federal statutory rate to the effective income tax rates.

Edison International Parent and Other

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

Loss from Continuing Operations

The following table summarizes the results of Edison International Parent and Other:



	Years ended December 31,
(in millions)	2019			2018			2017
Edison Energy Group and subsidiaries	$	(24	)	$	(78	)	$	(26	)
Corporate expenses and other subsidiaries	(101		)	(69		)	(421		)
Total Edison International Parent and Other	$	(125	)	$	(147	)	$	(447	)

The loss from continuing operations of Edison International Parent and Other decreased $22 million in 2019 compared to 2018 primarily due to an after-tax loss of $50 million in 2018 related to the sale of SoCore Energy, partially offset by higher interest expense as a result of increased borrowings in 2019.

LIQUIDITY AND CAPITAL RESOURCES

SCE

SCE's ability to operate its business, fund capital expenditures and implement its business strategy is dependent upon its cash flow and access to the bank and 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, dividend payments to and equity contributions from Edison International, obligations to preferred and preference shareholders, and the outcome of tax and regulatory matters.

During 2019 SCE, along with Edison International Parent, engaged in a financing program to enable SCE to make an initial contribution of $2.4 billion to the Wildfire Insurance Fund in September 2019, fund a significant increase in wildfire mitigation expenditures, and increase the equity portion of SCE's capital structure to 52% by year-end 2020 based on SCE's current 37-month backwards looking compliance period. The increase in the equity portion of SCE's capital structure was authorized in the 2020 Cost of Capital proceeding in December 2019. See "Management Overview—2020 Cost of Capital Application."

The 2019 financing program included $3.3 billion of equity contributions from Edison International Parent to SCE, as well as SCE issuing $2.3 billion of first and refunding mortgage bonds. Additionally, in February 2019, SCE borrowed $750 million under a term loan which was repaid in full in April 2019.

In the next 12 months, SCE expects to continue to fund its cash requirements through operating cash flows, bank and capital market financings, and equity contributions from Edison International Parent, as needed, while continuing to increase the equity portion of its capital structure. SCE also expects to repurchase or redeem preferred or preference stock to reduce the preferred equity component of the capital structure to 5% in line with the capital structure authorized in the 2020 Cost of Capital proceeding. See "Management Overview—2020 Cost of Capital Application." SCE also has availability under its credit facility to fund cash requirements.

SCE's long-term issuer credit ratings remain at investment grade levels. In the third quarter of 2019, the major credit agencies changed SCE's outlook from negative to stable due to the passage of AB 1054 and the establishment of the Wildfire Insurance Fund, which provided the AB 1054 Liability Cap and the new standard that the CPUC must apply when assessing the prudency of a utility in wildfire-related cost recovery proceedings. For further information, see "Management Overview—Southern California Wildfires and Mudslides." The following table summarizes SCE's current, long-term issuer credit ratings and outlook from the major credit rating agencies:



	Moody's	Fitch	S&P
Credit Rating	Baa2	BBB-	BBB
Outlook	Stable	Stable	Stable

SCE's credit ratings may be further affected if, among other things, regulators fail to successfully implement AB 1054 in a consistent and credit supportive manner or the Wildfire Insurance Fund is depleted by claims from catastrophic wildfires. Credit rating downgrades increase the cost and may impact the availability of short-term and long-term borrowings, including commercial paper, credit facilities, bond financings or other borrowings. In addition, some of SCE's power procurement contracts would require SCE to pay related liabilities or post additional collateral if SCE's credit rating were to fall below investment grade. Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade are $44 million as of December 31, 2019. In addition, if SCE's credit rating falls below investment grade, it may be required to post up to $50 million in collateral in connection with its environmental remediation obligations, within 120 days of the end of the fiscal year in which the downgrade occurs. Furthermore, if SCE was downgraded below investment grade, counterparties may also institute new collateral requirements for future transactions. For further details, see "— Margin and Collateral Deposits."

Available Liquidity

At December 31, 2019, SCE had approximately $2.3 billion available under its $3.0 billion credit facility. In June 2019, SCE extended its credit facility through May 2024, pursuant to an option to extend, and may extend its credit facility for one

additional year with the lenders' approval.

SCE may finance balancing account undercollections and working capital requirements to support operations and capital expenditures with commercial paper, its credit facility or other borrowings, subject to availability in the bank and capital markets. SCE expects to finance approximately $1.6 billion of wildfire mitigation capital expenses by issuing securitized bonds. Prior to issuance of such bonds, other debt instruments may be used to temporarily finance the expenditures.

As necessary, SCE will utilize its available liquidity, capital market financings, other borrowings or parent company equity contributions in order to meet its obligations as they become due, including any potential costs related to the 2017/2018 Wildfire/Mudslide Events. For further information, see "Management Overview—Southern California Wildfires

and Mudslides."

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 December 31, 2019, SCE's debt to total capitalization ratio was 0.47 to 1.

At December 31, 2019, SCE was in compliance with all financial covenants that affect access to capital.

Capital Investment Plan

Major Transmission Projects

A summary of SCE's most significant transmission and substation construction projects during the next three years is presented below. The timing of the projects below is subject to timely receipt of permitting, licensing and regulatory approvals.



Project Name	Project Lifecycle Phase	Direct Expenditures (in millions)¹	Inception to Date (in millions)¹	Scheduled In-Service Date
West of Devers	Construction	$840	$484	2021
Mesa Substation	Construction	646	373	2022
Alberhill System²	Licensing	486	41	—²
Riverside Transmission Reliability³	Licensing	451	11	2024
Eldorado-Lugo-Mohave Upgrade	Licensing	246	93	2021


¹	Direct expenditures include direct labor, land and contract costs incurred for the respective projects and exclude overhead costs that are included in the capital expenditures forecast discussed in "Management Overview—Capital Program."


²	Includes the original estimated project cost for Alberhill. In January 2020, SCE submitted a supplemental analysis to the CPUC which included alternative projects as well as an update to the original project cost. SCE is unable to predict the timing of a final CPUC decision, the corresponding in-service date, and what the final project costs will be for the Alberhill System Project.

³While the Riverside Transmission Reliability Project total cost is currently estimated to be $451 million, the CPUC issued a proposed decision, which if adopted would increase the project cost to $584 million. See discussion in "Riverside Transmission Reliability" below for further information.

West of Devers

The West of Devers Project consists of upgrading and reconfiguring approximately 48 miles of existing 220-kV transmission lines between the Devers, El Casco, Vista and San Bernardino substations, increasing the power transfer capabilities in support of California's renewable portfolio standards goals.

In August 2016, the CPUC approved the construction of the West of Devers Project. During 2018, SCE started construction on the 220-kV transmission line. Construction is on plan and SCE expects to complete construction in 2021.

Mesa Substation

The Mesa Substation Project consists of replacing the existing 220-kV Mesa Substation with a new 500/220-kV substation. The Mesa Substation Project would address reliability concerns by providing additional transmission import capability, allowing greater flexibility in the siting of new generation, and reducing the total amount of new generation required to meet local reliability needs in the Western Los Angeles Basin area. In February 2017, the CPUC issued a final decision approving the project largely consistent with SCE's proposal and rejected alternative project configurations proposed by CPUC staff. Construction on the initial phase of construction (a new 220- kV substation) commenced in October 2017. In October 2019, SCE achieved first energization of the new substation. The remaining phases of construction are anticipated to be put out for competitive bid and SCE expects that costs associated with the project may change as a result of the competitive bidding process. SCE anticipates project completion in the first quarter of 2022.

Alberhill System

The Alberhill System Project would consist of constructing a new 500-kV substation, two 500-kV transmission lines to connect the proposed substation to the existing Serrano-Valley 500-kV transmission line, telecommunication equipment and subtransmission lines in unincorporated and incorporated portions of western Riverside County. The project was designed to meet long-term forecasted electrical demand in the proposed Alberhill System Project area and to increase electrical system reliability and resiliency. In April 2018 and July 2018, the CPUC issued a proposed decision and an alternate proposed decision, both denying SCE's ability to construct the Alberhill System Project based on a perceived lack of need. SCE filed comments on both proposed decisions requesting that the CPUC grant the certificate of public convenience and necessity for the Alberhill System Project. In August 2018, the CPUC issued a decision that did not deny or approve the Alberhill System Project but directed SCE to submit supplemental information on the Alberhill System Project including but not limited to a load forecast and cost benefit analysis of several alternatives to the proposed project. Ongoing capital spending has been deferred as a result of the CPUC request for additional information. In January 2020, SCE submitted a supplemental analysis to the CPUC for the Alberhill System Project including several alternatives to the proposed project as well as an update to the original project cost. A final decision on the Alberhill System Project is pending based on the supplemental analysis. Given the uncertainty associated with the resolution of the permitting process, potential revisions to the project have not been reflected in total direct expenditures. SCE continues to believe a system solution is needed for the project area but is unable to predict the timing of a final CPUC decision in connection with the Alberhill System Project proceeding.

Approximately 48% of the Alberhill System Project costs spent to date would be subject to recovery through CPUC revenue and 52% through FERC revenue. In October 2017, SCE obtained approval from the FERC for abandoned plant treatment for the Alberhill System Project, which allows SCE to seek recovery of 100% of all prudently incurred costs after the approval date and 50% of prudently incurred costs prior to the approval date. Excluding land costs, which may be recovered through sale to a third party, SCE has incurred approximately $46 million of capital expenditures, including overhead costs, as of December 31, 2019, of which approximately $34 million may not be recoverable if the project is cancelled.

Riverside Transmission Reliability

The Riverside Transmission Reliability Project is a joint project between SCE and Riverside Public Utilities ("RPU"), the municipal utility department of the City of Riverside. While RPU would be responsible for constructing some of the project's facilities within Riverside, SCE's portion of the project consists of constructing upgrades to its system, including a new 230-kV Substation; certain interconnection and telecommunication facilities and transmission lines in the cities of Riverside, Jurupa Valley and Norco and in portions of unincorporated Riverside County. The purpose of the project is to provide RPU and its customers with adequate transmission capacity to serve existing and projected load, to provide for long-term system capacity for load growth, and to provide needed system reliability. Due to changed circumstances since the time the project was originally developed, SCE informed the CPUC in August 2016 that it supports revisions to the proposed Project. In October 2018, the CPUC issued an environmental report that identified a new route alternative, as the environmentally preferred project and proposed an additional underground section of the proposed 220-kV power line. In January 2020, SCE received a proposed decision from the CPUC that would approve the project consistent with the environmental report. If adopted, the cost of the revised project is estimated to be $584 million.

Eldorado-Lugo-Mohave Upgrade

The Eldorado-Lugo-Mohave Upgrade Project will increase capacity on existing transmission lines to allow additional renewable energy to flow from Nevada to southern California. The project would modify SCE's existing Eldorado, Lugo, and Mohave electrical substations to accommodate the increased current flow from Nevada to southern California; increase the power flow through the existing 500-kV transmission lines by constructing two new capacitors along the lines; raise transmission tower heights to meet ground clearance requirements; and install fiber optics on the transmission lines to

provide communications between existing SCE substations. A final CPUC decision is anticipated during 2020. In April 2019, as directed by the CPUC, SCE filed an amended application for a certificate of public convenience and necessity with the CPUC, which included total project costs of $257 million. A subsequent change to the project work scope reduced the project total cost to $246 million, a decrease of $11 million as compared to the estimate provided in the amended application.

Grid Development - Wildfire Mitigation

See "Management Overview—Wildfire Mitigation and Wildfire Insurance Expenses."

Grid Development - Transportation Electrification

Medium- and Heavy-Duty Vehicle Transportation Electrification

In January 2017, SCE filed an application with the CPUC requesting approval of transportation electrification programs to accelerate the adoption of electric transportation, which is critical to California's climate change and GHG reduction objectives. The application proposed a five-year program to fund medium- and heavy-duty vehicle charging infrastructure that follows the model developed for SCE's Charge Ready program, as well as six pilot projects to be considered on an accelerated basis. In January 2018, the CPUC issued a final decision approving five pilot projects with a budget of $16 million ($10 million capital) in 2016 dollars. In May 2018, the CPUC issued a final decision approving the five-year program, with certain modifications, to install charging infrastructure to support the electrification of 8,490 medium- and heavy-duty electric vehicles at 870 sites, which must be fully contracted for by 2024. The final decision includes an approved five-year budget of $356 million ($242 million capital) in nominal dollars. SCE expects to propose additional programs and pilots in the future. SCE's 2020 capital plan contemplates $4 million of medium- and heavy-duty vehicle transportation electrification spending.

Charge Ready Program

In January 2016, the CPUC approved SCE's $22 million Charge Ready Program Pilot, which allows SCE to install light-duty electric vehicle charging infrastructure, provide rebates to offset the cost of qualified customer-owned charging stations, and implement a supporting marketing, education and outreach campaign. As of December 31, 2019, SCE had executed agreements and reserved funding for 81 sites to deploy 1,301 charge ports under this pilot. The results of this pilot helped shape Charge Ready 2, the second phase of the Charge Ready program.

In June 2018, SCE filed an application to obtain approval for Charge Ready 2. In the application, SCE requested approval for $760 million ($561 million capital) in 2018 dollars to install infrastructure and provide rebates to support 48,000 new electric vehicle charging ports as part of a four-year program that will also include a marketing, education and outreach campaign. In December 2018, the CPUC approved $22 million in bridge funding to continue the Charge Ready Program Pilot while the Charge Ready 2 application remains pending. As of December 31, 2019, with this additional funding, SCE had executed agreements and reserved funding for 66 additional sites to deploy 1,463 additional charge ports. SCE's 2020 capital plan contemplates $8 million of bridge Charge Ready Program Pilot spending.

Decommissioning of San Onofre

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. SCE has engaged a decommissioning general contractor to undertake a significant scope of decommissioning activities for Units 1, 2 and 3 at San Onofre. The decommissioning of San Onofre is expected to take many years.

Decommissioning of San Onofre Unit 1 began in 1999 and the transfer of spent nuclear fuel from Unit 1 to dry cask storage in the Independent Spent Fuel Storage Installation ("ISFSI") was completed in 2005. Major decommissioning work for Unit 1 has been completed except for reactor vessel disposal and certain underground work. Some spent nuclear fuel from Units 2 and 3 also was transferred to the ISFSI between 2007 and 2012. Radiological decommissioning of San Onofre Units 2 and 3 began in June 2013 with SCE filing a certification of permanent cessation of power operations at San Onofre with the NRC. The transfer of the remaining spent nuclear fuel from Units 2 and 3 to the ISFSI began in 2018. The spent fuel transfer operations were suspended on August 3, 2018 due to an incident that occurred when an SCE contractor was loading a spent fuel canister into the ISFSI. The incident did not result in any harm to the public or workers and the canister was subsequently safely loaded into the ISFSI. In May 2019, after an extensive review, the NRC determined that fuel loading can be safely resumed at San Onofre. SCE commenced fuel transfer operations at San Onofre in July 2019. In October 2019, the California Coastal Commission approved SCE's application for the Coastal Development Permit, the principle discretionary permit required to start major decommissioning activities at San Onofre. SCE plans on commencing major decommissioning activities in 2020 in accordance with the terms of the permit, subject to any court rulings in a proceeding brought in

December 2019 to challenge the California Coastal Commission's issuance of the permit.

In December 2018, SCE updated its decommissioning cost estimate for decommissioning activities to be completed at San Onofre Units 2 and 3 to $3.4 billion (SCE share is $2.5 billion) in 2017 dollars. The decommissioning cost estimate includes costs through the respective expected decommissioning completion dates, currently estimated to be in 2051 for San Onofre Units 2 and 3. The decommissioning cost estimate is subject to a number of uncertainties including the cost of disposal 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 will provide for either interim or permanent off-site storage of spent nuclear fuel enabling the removal and transport of spent fuel canisters from the San Onofre site, as to which there can be no assurance. The cost estimate is subject to change as decommissioning proceeds and such changes may be material. The CPUC will conduct a reasonableness review for costs for each year. SCE's share of the San Onofre decommissioning costs recorded during 2019 were $172 million.

SCE had nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $2.8 billion as of December 31, 2019. Based upon the resolution of a number of uncertainties, including the cost and timing of nuclear waste disposal, the time it will take to obtain required permits, cost of removal of property, site remediation costs, the financial performance of the nuclear decommissioning trust fund investments, as well as the resolution of a number of other assumptions and estimates, additional contributions to the nuclear decommissioning trust funds may be required. If additional contributions to the nuclear decommissioning trust funds become necessary, SCE will seek recovery of such additional funds through electric rates and any such recovery will be subject to a reasonableness review by the CPUC. Cost increases resulting from contractual disputes or significant permitting delays, among other things, could cause SCE to materially overrun the decommissioning cost estimate and could materially impact the sufficiency of trust funds.

SCE Dividends

CPUC holding company rules require that SCE's dividend policy be established by SCE's Board of Directors on the same basis as if SCE were a stand-alone utility company, and that the capital requirements of SCE, as deemed to be necessary to meet SCE's electricity service obligations, shall receive first priority from the Boards of Directors of both Edison International and SCE. In addition, the CPUC regulates SCE's capital structure which limits the dividends it may pay to its shareholders.

Prior to January 1, 2020, under SCE's interpretation of CPUC regulations and capital structure decisions, the common equity component of SCE's capital structure was required to remain at or above 48% on a weighted average basis over the 37-month period that SCE's capital structure was in effect for ratemaking purposes and SCE was required to file an application for a waiver of the 48% equity ratio condition discussed above if an adverse financial event reduces its spot equity ratio below 47%. Effective January 1, 2020, the common equity component of SCE's authorized capital structure was increased from 48% to 52%. For further information, see "Management Overview—2020 Cost of Capital Application." Under AB 1054, the impact of SCE's contributions to the Wildfire Insurance Fund are excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. For further information, see "Management Overview—Southern California Wildfires and Mudslides."

On February 28, 2019, SCE submitted an application to the CPUC for waiver of compliance with this equity ratio requirement, describing that while the charge accrued in connection with the 2017/2018 Wildfire/Mudslide Events caused its equity ratio to fall below 47% on a spot basis as of December 31, 2018, SCE remains in compliance with the 48% equity ratio over the applicable 37-month average basis. In its application, SCE requested a limited waiver to exclude wildfire-related charges and wildfire-related debt issuances from its equity ratio calculations until a determination regarding cost recovery is made. The CPUC has ruled that while the application is pending resolution, SCE must notify the CPUC if an adverse financial event reduces SCE's spot equity ratio by more than one percent from the level most recently filed with the CPUC in the proceeding. The last spot equity ratio SCE filed with the CPUC in the proceeding was 45.2% as of December 31, 2018. Under the CPUC's rules, SCE will not be deemed to be in violation of the equity ratio requirement, and therefore may continue to issue debt and dividends, while the waiver application is pending resolution. For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides." At December 31, 2019, without excluding the $2.0 billion after-tax wildfire-related charges incurred in 2018 and 2019, SCE's 37-month average common equity component of total capitalization was 48.5% and the maximum additional dividend that SCE could pay to Edison International under this limitation was $179 million, resulting in a restriction on net assets of approximately $17.6 billion. If the wildfire-related charges were excluded at December 31, 2019, SCE's 37-month average common equity component of total capitalization would have been 49.6%.

As a California corporation, SCE's ability to pay dividends is also governed by the California General Corporation Law. California law requires that for a dividend to be declared: (a) retained earnings must equal or exceed the proposed dividend, or (b) immediately after the dividend is made, the value of the corporation's assets must exceed the value of its liabilities plus amounts required to be paid, if any, in order to liquidate stock senior to the shares receiving the dividend. Additionally, a California corporation may not declare a dividend if it is, or as a result of the dividend would be, likely to be unable to meet its liabilities as they mature. Prior to declaring dividends, SCE's Board of Directors evaluates available information, including when applicable, information pertaining to the 2017/2018 Wildfire/Mudslide Events, to ensure that the California law requirements for the declarations are met. On February 27, 2020, SCE declared a dividend to Edison International of $269 million.

The timing and amount of future dividends are also dependent on a number of other factors including SCE's requirements to fund other obligations and capital expenditures, its ability to access the capital markets, and generate operating cash flows and earnings. If SCE incurs significant costs related to catastrophic wildfires, including the 2017/2018 Wildfire/Mudslide Events, and is unable to recover such costs through insurance, the Wildfire Insurance Fund (for fires after July 12, 2019), or from customers or access capital markets on reasonable terms, SCE may be limited in its ability to pay future dividends to Edison International and its preferred and preference shareholders.

Margin and Collateral Deposits

Certain derivative instruments, power and energy procurement contracts and other contractual arrangements contain collateral requirements. In addition, certain environmental remediation obligations require financial assurance that may be in the form of collateral postings. Future collateral requirements may differ from the requirements at December 31, 2019 due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations, and the impact of SCE's credit ratings falling below investment grade.

The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would have been required as of December 31, 2019 if SCE's credit rating had been downgraded to below investment grade as of that date. The table below also provides the potential collateral that could be required due to adverse changes in wholesale power and natural gas prices over the remaining lives of existing power and energy procurement contracts.



(in millions)
Collateral posted as of December 31, 2019¹	$	178
Incremental collateral requirements for purchased power and fuel contracts resulting from a potential downgrade of SCE's credit rating to below investment grade²	44
Incremental collateral requirements for purchased power and fuel contracts resulting from adverse market price movement³	27
Posted and potential collateral requirements	$	249


¹	Net collateral provided to counterparties and other brokers consisted of $154 million in letters of credit and surety bonds and $24 million of cash collateral which was reflected in "Other current assets" on the consolidated balance sheets.

If SCE's credit rating fell below investment grade, existing purchased power and fuel contracts would require $44 million of incremental collateral. Counterparties may also institute new collateral requirements, applicable to future transactions, at the time of a downgrade. Furthermore, SCE may also be required to post up to $50 million in collateral in connection with its environmental remediation obligations, within 120 days of the end of the fiscal year in which the downgrade occurs.


³	Incremental collateral requirements were based on potential changes in SCE's forward positions as of December 31, 2019 due to adverse market price movements over the remaining lives of the existing power and fuel contracts using a 95% confidence level.

Regulatory Balancing and Memorandum Accounts

SCE's cash flows are affected by regulatory balancing and memorandum accounts overcollections or undercollections. Overcollections and undercollections represent differences between cash collected in current rates for specified forecasted costs and the costs actually incurred. With some exceptions, SCE seeks to adjust rates on an annual basis or at other designated times to recover or refund the balances recorded in its balancing accounts. Undercollections or overcollections in these balancing and memorandum accounts impact cash flows and can change rapidly. Undercollections and overcollections generally accrue interest based on a three-month commercial paper rate published by the Federal Reserve.

As of December 31, 2019, SCE had net overcollections of $365 million for regulatory balancing and memorandum accounts, primarily consisting of overcollections related to public purpose-related and energy efficiency program costs and BRRBA, offset by undercollections related to wildfire risk related costs and PABA. Overcollections related to public purpose-related programs may decrease as costs are incurred to fund programs established by the CPUC. Overcollections related to BRRBA are expected to decrease as refunds are provided to customers in 2020. SCE is currently incurring wildfire-related spending at levels significantly exceeding amounts authorized in the 2018 GRC and has recognized regulatory assets for certain of these costs. Total spending on wildfire mitigation is expected to continue at higher levels in 2020 and beyond. Undercollections related to PABA are expected to decrease through the implementation of the annual ERRA and PABA review proceeding in 2020. See "Notes to Consolidated Financial Statements—Note 11. Regulatory Assets and Liabilities" for further information.

Edison International Parent and Other

In the next 12 months, Edison International expects to fund its net cash requirements through capital market and bank financings, including by issuing additional debt and equity, as needed.

In June 2019, Edison International Parent extended its credit facility through May 2024, pursuant to an option to extend, and may extend the credit facility for one additional year with the lenders' approval. At December 31, 2019, Edison International Parent's entire $1.5 billion credit facility was available for borrowing.

During 2019, Edison International Parent engaged in a financing program to support SCE's initial contribution to the Wildfire Insurance Fund in September 2019, fund SCE's wildfire mitigation expenditures, and increase the equity portion of SCE's capital structure. This included issuing 2.8 million shares of common stock for net proceeds of $198 million through the ATM program and issuing 32.2 million shares of common stock for net proceeds of $2.2 billion in an underwritten offering during 2019. For further details, see "Notes to Consolidated Financial Statements—Note 14. Equity." Edison International Parent also issued $1.4 billion of senior notes during 2019. The proceeds of these financing activities allowed Edison International to contribute $3.3 billion to SCE as equity contributions and repay a $1.0 billion term loan. The term loan was borrowed in April 2019 and the proceeds of the term loan were contributed to SCE largely to enable repayment of SCE's February 2019 term loan. Edison International Parent's term loan was repaid in full in December 2019.

At December 31, 2019, the current portion of Edison International Parent’s long-term debt included senior notes of $400 million due in April 2020.

Edison International Parent and Other's liquidity and its ability to pay operating expenses, satisfy debt obligations and pay dividends to common shareholders are dependent on access to the bank and capital markets, dividends from SCE, realization of tax benefits and its ability to meet California law requirements for the declaration of dividends. Prior to declaring dividends, Edison International's Board of Directors evaluates available information, including when applicable, information pertaining to the 2017/2018 Wildfire/Mudslide Events, to ensure that the California law requirements for the declarations are met. For information on the California law requirements on the declaration of dividends, see "—SCE—SCE Dividends." Edison International intends to maintain its target payout ratio of 45% – 55% of SCE's core earnings, subject to the factors identified above.

Edison International may finance its ongoing cash requirements, including common stock dividends, working capital requirements, payment of obligations, and capital investments, including capital contributions to subsidiaries, with short-term or other financings, subject to availability in the bank and capital markets.

A debt covenant in Edison International Parent's credit facility requires a consolidated debt to total capitalization ratio as defined in the credit agreement of less than or equal to 0.70 to 1. At December 31, 2019, Edison International Parent's consolidated debt to total capitalization ratio was 0.55 to 1.

At December 31, 2019, Edison International Parent was in compliance with all financial covenants that affect access to capital.

Edison International Parent's long-term issuer credit ratings remain at investment grade levels after downgrade actions taken by the major credit rating agencies in 2018 and early 2019. In the third quarter of 2019, the major credit agencies changed Edison International Parent's outlook from negative to stable, due to the passage of AB 1054 and the establishment of the Wildfire Insurance Fund, which provided the AB 1054 Liability Cap and the new standard that the CPUC must apply when assessing the prudency of a utility in wildfire-related cost recovery proceedings. The following table summarizes Edison International Parent's current, long-term issuer credit ratings and outlook from the major credit rating agencies:



	Moody's	Fitch	S&P
Credit Rating	Baa3	BBB-	BBB
Outlook	Stable	Stable	Stable

Edison International Parent's credit ratings may be further affected if, among other things, regulators fail to successfully implement AB 1054 in a consistent and credit supportive manner or the Wildfire Insurance Fund is depleted by claims from catastrophic wildfires. Credit rating downgrades increase the cost and may impact the availability of short-term and long-term borrowings, including commercial paper, credit facilities, note financings or other borrowings.

Net Operating Loss and Tax Credit Carryforwards

Edison International has approximately $1.3 billion of tax effected net operating loss and tax credit carryforwards at December 31, 2019 (after offsetting $212 million of unrecognized tax benefits and $212 million of Capistrano Wind net operating loss and tax credit carryforwards), which are available to offset future consolidated tax liabilities. See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for further information regarding taxes payable to Capistrano Wind. Forecast monetization has been delayed, mainly due to anticipated future payment of wildfire claims and the contribution to the Wildfire Insurance Fund as described in AB 1054. Edison International expects to utilize its net operating loss and tax credit carryforwards through 2027.

Historical Cash Flows

SCE



(in millions)	2019			2018			2017
Net cash (used in) provided by operating activities	$	(91	)	$	3,191		$	3,735
Net cash provided by financing activities	4,771			616			243
Net cash used in investing activities	(4,678		)	(4,300		)	(3,503		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	$	2		$	(493	)	$	475

Net Cash (Used in) Provided by Operating Activities

The following table summarizes major categories of net cash provided by operating activities as provided in more detail in SCE's consolidated statements of cash flows for 2019, 2018 and 2017:



	Years ended December 31,									Change in cash flows
(in millions)	2019			2018			2017			2019/2018			2018/2017
Net income (loss)	$	1,530		$	(189	)	$	1,136
Non-cash items¹	1,782			1,291			3,058
Subtotal	3,312			1,102			4,194			2,210			(3,092		)
Contributions to Wildfire Insurance Fund	(2,457		)	—			—			(2,457		)	—
Changes in cash flow resulting from working capital²	298			(313		)	(148		)	611			(165		)
Regulatory assets and liabilities, net	(1,278		)	(92		)	4			(1,186		)	(96		)
Other noncurrent assets and liabilities, net³	34			2,494			(315		)	(2,460		)	2,809
Net cash (used in) provided by operating activities	$	(91	)	$	3,191		$	3,735		$	(3,282	)	$	(544	)


¹	Non-cash items include depreciation and amortization, allowance for equity during construction, impairment and other, Wildfire Insurance Fund amortization expense, deferred income taxes and other.


²	Changes in working capital items include receivables, inventory, amortization of prepaid expenses, accounts payable, tax receivables and payables, and other current assets and liabilities.


³	Includes changes in liabilities for wildfire-related claims and wildfire-related insurance receivables. Also includes nuclear decommissioning trusts. See "Nuclear Decommissioning Activities" below for further information.

Net cash provided by operating activities was impacted by the following:

Net income and non-cash items increased in 2019 by $2.2 billion from 2018. Net Income in 2019 increased by $1.7 billion primarily due to a $2.3 billion reduction in charges for wildfire-related claims, net of expected recoveries from insurance and FERC customers in 2019 as compared to 2018, the adoption of the 2018 GRC final decision in 2019, higher FERC revenue due to the settlement of SCE's 2018 Formula Rate proceeding and rate base growth in 2019, and the timing of regulatory deferral and cost recovery of incremental wildfire insurance expenses. These increases were partially offset by higher inspection, preventive maintenance and vegetation management costs that were not deferred as regulatory assets. Non-cash items included depreciation and amortization of $1.8 billion and $1.9 billion in 2019 and 2018, respectively, changes in deferred income taxes of $(243) million and $(552) million in 2019 and 2018, respectively, an impairment charge of $170 million recorded in 2019 related to disallowed historical capital expenditures in SCE's 2018 GRC decision and Wildfire Insurance Fund amortization expense of $152 million recorded in 2019.

Net cash used in operating activities was also impacted by cash outflow of $2.5 billion related to SCE's contributions to the Wildfire Insurance Fund in 2019. See "Notes to Consolidated Financial Statements—Note 12. Commitment and Contingencies" for further information.

Net cash inflow (outflow) for working capital was $298 million and $(313) million in 2019 and 2018, respectively. The net cash for each period was primarily related to timing of disbursements of $237 million and $(15) million in 2019 and 2018, respectively, and changes in receivables from customers of $(73) million and $(288) million in 2019 and 2018, respectively. Net cash for working capital also included insurance premium payments of $(471) million and $(197) million in 2019 and 2018, respectively, primarily for wildfire-related coverage, partially offset by net tax refunds of $164 million and $57 million in 2019 and 2018, respectively.

Net cash provided by regulatory assets and liabilities, including changes in net under collections of balancing accounts, was $(1,278) million and $(92) million in 2019 and 2018, respectively. SCE has a number of balancing accounts, which impact cash flows based on differences between timing of collection of amounts through rates and accrual expenditures. Cash flows were primarily impacted by the following:

2019


•	BRRBA overcollections decreased by $300 million primarily due to refunds of prior overcollections (including incremental tax benefits) and current year undercollection due to rate changes delayed beyond January 1, 2019, offset by additional overcollection of distribution revenue to be refunded to customers over an 18-month period, starting in July 2019, as part of SCE's 2018 GRC final decision.

•

PABA was established in May 2019 to determine and pro-ratably recover from responsible bundled service and departing load customers the "above-market" costs of all generation resources that are eligible for cost recovery. Net undercollections for ERRA, PABA and the New System Generation Balancing Account decreased by $142 million primarily due to recovery of prior ERRA undercollections and overcollections of generation revenue occurring in 2019 and 2018 that are being refunded over an 18-month period, starting in July 2019, as part of SCE's 2018 GRC final decision. The cash inflow was partially offset by lower sales than forecasted in rates, higher than forecasted energy prices experienced in 2019, charges from CPUC-authorized contract terminations and refunds of prior overcollections from the New System Generation Balancing Account.


•	Lower cash due to elimination of approximately $360 million in a regulatory liability that was established in 2018 to record adjustments associated with the delay in the 2018 GRC decision. In May 2019, the CPUC approved the final decision in SCE's 2018 GRC, resulting in 2019 and 2018 overcollections being refunded to customers through BRRBA and PABA, as discussed above.


•	Additional undercollections of $596 million related to wildfire-related expenses that are probable of future recovery from customers, including wildfire risk mitigation costs, insurance premiums and service restoration and damage repair costs. See "Notes to Consolidated Financial Statements—Note 11. Regulatory Assets and Liabilities" for further information.


•	Higher cash due to $115 million of overcollections related to the timing of GHG auction revenue, low carbon fuel standard credit sales, and the related refunds and rebates to eligible customers.


•	Additional cash outflow due to refund of prior year overcollection of recovery of certain employee benefit related costs and reversal of TAMA overcollection as a result of adoption of the 2018 GRC final decision.

2018


•	BRRBA overcollections increased by $428 million primarily due to a $263 million reclassification of 2017 incremental tax benefits from TAMA to BRRBA (to be refunded in 2019) and higher sales than forecasted in rates, partially offset by a refund of 2016 incremental tax benefits.

•

Higher cash from increased regulatory liabilities of approximately $365 million primarily due to the delay in the 2018 GRC decision. During 2018, the amounts billed to customers were largely based on the 2017 authorized GRC revenue requirement, however, the amount of revenue recognized has been adjusted mainly for the July 2017 cost of capital decision and Tax Reform pending the outcome of the 2018 GRC and therefore, a regulatory liability has been established to record any associated adjustments.

•

Net undercollections for ERRA and the new system generation program were $741 million and $267 million at December 31, 2018 and 2017, respectively. Net undercollections increased $474 million during 2018 primarily due to an increase in costs due to higher than forecasted power and gas prices experienced in 2018 and higher load requirements than forecasted in rates, partially offset by an increase in cash due to recovery of prior year undercollections.


•	TAMA overcollections decreased by $287 million primarily due to a $263 million reclassification from TAMA to BRRBA to refund customers as discussed above.


•	Undercollections of $128 million related to the establishment, in the fourth quarter of 2018, of a WEMA to track wildfire-related costs including insurance premiums in excess of the amounts that will be ultimately approved in the 2018 GRC decision.

Cash flows provided by other noncurrent assets and liabilities were primarily related to an increase of $232 million and $4.7 billion in liabilities for the 2017/2018 Wildfire/Mudslide Events related claims in 2019 and 2018, respectively, partially offset by the Local Public Entity Settlements payment of $360 million reduced by the subsequent insurance recovery of $290 million in 2019, and an increase of $2.0 billion in insurance receivables in 2018. Also includes net earnings from nuclear decommissioning trust investments ($67 million and $41 million in 2019 and 2018, respectively) and SCE's payments of decommissioning costs ($172 million and $140 million in 2019 and 2018, respectively). See "Nuclear Decommissioning Activities" below for further discussion.

Net Cash Provided by Financing Activities

The following table summarizes cash provided by financing activities for 2019, 2018 and 2017. Issuances of debt and preference stock and capital contribution from Edison International Parent are discussed in "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements" and "—Note 14. Equity."



(in millions)	2019			2018			2017
Issuances of first and refunding mortgage bonds, net of (discount) premium and issuance costs	$	2,306		$	2,692		$	1,011
Issuance of term loan	750			—			300
Repayment of term loan	(750		)	—			—
Remarketing and issuances of pollution control bonds, net of issuance costs	—			—			134
Long-term debt matured or repurchased	(82		)	(639		)	(882		)
Capital contributions from Edison International Parent	3,250			—			—
Issuances of preference stock, net of issuance costs	—			—			462
Redemptions of preference stock	—			—			(475		)
Short-term debt (repayments), net of borrowings and discount	(171		)	(520		)	469
Payments of common stock dividends to Edison International	(400		)	(788		)	(573		)
Payments of preferred and preference stock dividends	(121		)	(121		)	(124		)
Other	(11		)	(8		)	(79		)
Net cash provided by financing activities	$	4,771		$	616		$	243

Net Cash Used in Investing Activities

Cash flows used in investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $4.9 billion, $4.5 billion and $3.8 billion for 2019, 2018 and 2017, respectively, primarily related to transmission and generation investments. SCE had a net redemption of nuclear decommissioning trust investments of $106 million and $109 million in 2019 and 2018, respectively. See "Nuclear Decommissioning Activities" below for further discussion.

Nuclear Decommissioning Activities

SCE's statements of cash flows includes nuclear decommissioning activities, which are reflected in the following line items:



(in millions)	2019			2018			2017
Net cash used in operating activities: Net earnings from nuclear decommissioning trust investments	$	67		$	41		$	55
SCE's decommissioning costs	(172		)	(140		)	(236		)
Net cash provided by investing activities: Proceeds from sale of investments	4,389			4,340			5,239
Purchases of investments	(4,283		)	(4,231		)	(5,042		)
Net cash impact	$	1		$	10		$	16

Net cash used in operating activities relates to interest and dividends less administrative expenses, taxes and SCE's decommissioning costs. Investing activities represent the purchase and sale of investments within the nuclear decommissioning trusts, including the reinvestment of earnings from nuclear decommissioning trust investments.

Funds for decommissioning costs are requested from the nuclear decommissioning trusts one month in advance. Decommissioning disbursements are funded from sales of investments of the nuclear decommissioning trusts. See "Notes to Consolidated Financial Statements—Note 10. Investments" for further information. The net cash impact reflects timing of decommissioning payments ($172 million and $140 million in 2019 and 2018, respectively) and reimbursements to SCE from the nuclear decommissioning trust ($173 million and $150 million in 2019 and 2018, respectively).

Edison International Parent and Other

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



(in millions)	2019			2018			2017
Net cash used in operating activities	$	(216	)	$	(14	)	$	(138	)
Net cash provided by (used in) financing activities	132			(534		)	764
Net cash provided by (used in) investing activities	—			61			(83		)
Net (decrease) increase in cash, cash equivalents and restricted cash	$	(84	)	$	(487	)	$	543

Net Cash Used in Operating Activities

Net cash used in operating activities increased in 2019 by $202 million from 2018 due to:


•	Outflows of $137 million and $92 million from operating activities in 2019 and 2018, respectively, due to payments and receipts relating to interest and operating costs.


•	An outflow of $79 million in 2019 primarily related to $164 million of intercompany tax-allocation payments offset by $85 million of federal and state income tax refunds. An inflow of $78 million in 2018 primarily related to federal income tax refunds.

Net Cash Provided by (Used in) Financing Activities

Net cash provided by (used in) financing activities were as follows:



(in millions)	2019			2018			2017
Dividends paid to Edison International common shareholders	$	(810	)	$	(788	)	$	(707	)
Dividends received from SCE	400			788