Company Quick10K Filing
Quick10K
Edison
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-03-13 Regulation FD, Other Events, Exhibits
8-K 2018-10-31 Regulation FD, Exhibits
8-K 2018-10-30 Earnings, Regulation FD, Exhibits
8-K 2018-07-27 Regulation FD, Exhibits
8-K 2018-07-26 Earnings, Regulation FD, Exhibits
8-K 2018-05-17 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-05-02 Regulation FD, Exhibits
8-K 2018-04-26 Shareholder Vote
8-K 2018-03-08 Other Events, Exhibits
8-K 2018-02-27 Officers
8-K 2018-02-23 Regulation FD, Exhibits
8-K 2018-01-30 Enter Agreement, Impairments, Exhibits
8-K 2018-01-26 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-01-10 Regulation FD, Exhibits
ACAN Americann 0
WUC Western Uranium 0
LMRK Landmark Infrastructure Partners 0
EV Eaton Vance 0
FGBI First Guaranty Bancshares 0
RUN Sunrun 0
CRY Cryolife 0
MCCX McorpCX 0
AXNX Axonics Modulation Technologies 0
HMMR Hammer Fiber Optics Holdings 0
EIX 2018-12-31
Note 1. Summary of Significant Accounting Policies
Note 2. Property, Plant and Equipment
Note 3. Variable Interest Entities
Note 4. Fair Value Measurements
Note 5. Debt and Credit Agreements
Note 6. Derivative Instruments
Note 7. Revenue
Note 8. Income Taxes
Note 9. Compensation and Benefit Plans
Note 10. Investments
Note 11. Regulatory Assets and Liabilities
Note 12. Commitments and Contingencies
Note 13. Preferred and Preference Stock of Utility
Note 14. Accumulated Other Comprehensive Loss
Note 15. Other Income and Expenses
Note 16. Supplemental Cash Flows Information
Note 17. Related-Party Transactions
Note 18. Quarterly Financial Data (Unaudited)
Note 1. Basis of Presentation
Note 2. Debt and Credit Agreements
Note 3. Related-Party Transactions
Note 4. Contingencies
EX-10.11 q4eix-sce10k2018xex1011.htm
EX-21 q4eix-sce10k2018xex21.htm
EX-23.1 q4eix-sce10k2018xex231.htm
EX-23.2 q4eix-sce10k2018xex232.htm
EX-24.1 q4eix-sce10k2018xex241.htm
EX-24.2 q4eix-sce10k2018xex242.htm
EX-31.1 q4eix-sce10k2018xex311.htm
EX-31.2 q4eix-sce10k2018xex312.htm
EX-32.1 q4eix-sce10k2018xex321.htm
EX-32.2 q4eix-sce10k2018xex322.htm

Edison Earnings 2018-12-31

EIX 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 eix-sceq4201810k.htm EIX/SCE 2018 10-K Document


 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2018
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                        to
Commission
File Number
 
Exact Name of Registrant
as specified in its charter
 
State or Other Jurisdiction of
Incorporation or Organization
 
IRS Employer
Identification Number
1-9936
 
EDISON INTERNATIONAL
 
California
 
95-4137452
1-2313
 
SOUTHERN CALIFORNIA EDISON COMPANY
 
California
 
95-1240335
EDISON INTERNATIONAL
 
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue
(P.O. Box 976)
Rosemead, California 91770
(Address of principal executive offices)
 
2244 Walnut Grove Avenue
(P.O. Box 800)
Rosemead, California 91770
(Address of principal executive offices)
(626) 302-2222
(Registrant's telephone number, including area code)
 
(626) 302-1212
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Edison International: Common Stock, no par value
 
NYSE LLC
Southern California Edison Company: Cumulative Preferred Stock
 
NYSE American LLC
4.08% Series, 4.24% Series, 4.32% Series, 4.78% Series
 
 
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 þ No o    Southern California Edison Company        Yes þ No o
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 o No þ    Southern California Edison Company        Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Edison International        Yes þ No o    Southern California Edison Company        Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post such files).
Edison International        Yes þ No o    Southern California Edison Company        Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Edison International         þ        Southern California Edison Company         þ    
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 þ
Accelerated Filer o
Non-accelerated Filer o
Smaller Reporting Company o
Emerging growth company o
Southern California Edison Company
Large Accelerated Filer o
Accelerated Filer o
Non-accelerated Filer þ
Smaller Reporting Company o
Emerging growth company o
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
o
                        Southern California Edison Company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Edison International        Yes o No þ    Southern California Edison Company        Yes o No þ
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 29, 2018, the last business day of the most recently completed second fiscal quarter:
Edison International    Approximately $20.6 billion    Southern California Edison Company    Wholly owned by Edison International
Common Stock outstanding as of February 26, 2019:
 
 
Edison International
 
325,811,206 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 2019 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.
 
 
 
 
 
 









TABLE OF CONTENTS
 
 
 
 
 
SEC Form 10-K Reference Number
 
 
Part II, Item 7
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


i



 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Part I, Item 1A
 
 
 
 
 
 


ii



 
 
 
 
 
 
Part II, Item 7A
Part II, Item 8
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


iii



 
 
 
 
 
 
 
 
 
Note 15. Other Income and Expenses
 
 
 
 
 
 
 
Part II, Item 6
Part II, Item 9A
Part II, Item 9B
Part II, Item 9
Part I, Item 1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


iv



Part I, Item 1B
Part I, Item 2
Part I, Item 3
 
 
 
 
 
 
Part I, Item 4
Part III, Item 10
Part III, Item 10
Part III, Item 10
Part III, Item 11
Part III, Item 12
Part III, Item 13
Part III, Item 14
Part II, Item 5
 
 
 
 
Part IV, Item 16
Part IV, Item 15
 
 
 
 
 
 
 
 
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.


v



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 Montecito Mudslides and the Woolsey Fire, collectively
AFUDC
 
allowance for funds used during construction
ALJ
 
administrative law judge
ARO(s)
 
asset retirement obligation(s)
Bcf
 
billion cubic feet
bonus depreciation
 
Federal tax deduction of a percentage of the qualifying property placed in service during periods permitted under tax laws
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
DERs
 
distributed energy resources
DOE
 
U.S. Department of Energy
DRP
 
Distributed Resources Plan
Edison Energy
 
Edison Energy, LLC, a wholly-owned subsidiary of Edison Energy Group that provides energy services to commercial and industrial customers
Edison Energy Group
 
Edison Energy Group, Inc., a wholly-owned subsidiary of Edison International, is a holding company for Edison Energy, LLC
EME
 
Edison Mission Energy
EME Settlement Agreement
 
Settlement Agreement by and among Edison Mission Energy, Edison International and the Consenting Noteholders identified therein, dated February 18, 2014
Electric Service Provider
 
an entity that offers electric power and ancillary services to customers that take final delivery of electric power and do not resell the power

ERRA
 
Energy Resource Recovery Account
FASB
 
Financial Accounting Standards Board
FERC
 
Federal Energy Regulatory Commission
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
HLBV
 
hypothetical liquidation at book value
IRS
 
Internal Revenue Service
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 25, 2019
MD&A
 
Management's Discussion and Analysis of Financial Condition and Results
of Operations in this report
MHI
 
Mitsubishi Heavy Industries, Inc. and related companies
Montecito Mudslides
 
mudslides and flooding in Montecito, Santa Barbara County, that occurred in January 2018
Moody's
 
Moody's Investors Service, Inc.
MW
 
megawatts
MWdc
 
megawatts measured for solar projects representing the accumulated peak capacity of all the solar modules


vi



NDCTP
 
Nuclear Decommissioning Cost Triennial Proceeding
NEIL
 
Nuclear Electric Insurance Limited
NEM
 
net energy metering
NERC
 
North American Electric Reliability Corporation
NOL
 
net operating loss
NRC
 
Nuclear Regulatory Commission
OII
 
Order Instituting Investigation
OII Parties
 
SCE, SDG&E, The Alliance for Nuclear Responsibility, The California Large Energy Consumers Association, California State University, Citizens Oversight dba Coalition to Decommission San Onofre, the Coalition of California Utility Employees, the Direct Access Customer Coalition, Ruth Henricks, PAO, TURN, and Women's Energy Matters, all of whom are parties to the Revised San Onofre Settlement Agreement
Palo Verde
 
nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest
PAO
 
CPUC's Public Advocates Office (formerly known as the Office of Ratepayer Advocates or ORA)
PBOP(s)
 
postretirement benefits other than pension(s)
PCIA
 
Power Charge Indifference Adjustment
PG&E
 
Pacific Gas & Electric Company

Prior San Onofre Settlement Agreement
 
San Onofre OII Settlement Agreement by and among TURN, PAO, SDG&E, the Coalition of California Utility Employees, and Friends of the Earth, dated November 20, 2014
Revised San Onofre
Settlement Agreement
 
Revised San Onofre OII Settlement Agreement among OII Parties, dated January 30, 2018 and modified on August 2, 2018
ROE
 
return on common equity
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 Ventura County in December 2017
TOU
 
Time-Of-Use
TURN
 
The Utility Reform Network
US EPA
 
The U.S. Environmental Protection Agency
WMP
 
a wildfire mitigation plan required to be filed annually under California Senate Bill 901 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
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 and capital spending incurred prior to formal regulatory approval;
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;
decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities, including determinations of authorized rates of return or return on equity, the 2018 GRC, the GS&RP application, the recoverability of wildfire-related and mudslide- related costs, and delays in regulatory actions;
ability of Edison International or SCE to borrow funds and access the bank and capital markets on reasonable terms;
actions by credit rating agencies to downgrade Edison International or SCE's credit ratings or to place those ratings on negative watch or outlook;
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;
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;
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;
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 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);

1



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;
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 provide direct links to certain SCE and other parties' regulatory filings and documents with the CPUC and the FERC and certain agency rulings and notices in open proceedings at www.edisoninvestor.com (SCE Regulatory Highlights) so that such filings, rulings and notices are available to all investors. Edison International and SCE post or provide direct links to certain documents and information related to Southern California wildfires which may be of interest to investors at www.edisoninvestor.com (Southern California Wildfires) in order to publicly disseminate such information. Edison International and SCE also routinely post or provide direct links to presentations, documents and other information that may be of interest to investors at www.edisoninvestor.com (Events and Presentations) in order to publicly disseminate such information. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.
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.

2



MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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)
2018
 
2017
 
2018 vs 2017 Change
 
2016
Net (loss) income attributable to Edison International
 
 
 
 
 
 
 
Continuing operations
 
 
 
 
 
 
 
SCE
$
(310
)
 
$
1,012

 
$
(1,322
)
 
$
1,376

Edison International Parent and Other
(147
)
 
(447
)
 
300

 
(77
)
Discontinued operations
34

 

 
34

 
12

Edison International
(423
)
 
565

 
(988
)
 
1,311

Less: Non-core items
 
 
 
 
 
 
 
     SCE
 
 
 
 
 
 
 
Wildfire-related claims, net of recoveries
(1,825
)
 

 
(1,825
)
 

Impairment and other
9

 
(448
)
 
457

 

Settlement of 1994 – 2006 California tax audits
66

 

 
66

 

Re-measurement of deferred taxes

 
(33
)
 
33

 

     Edison International Parent and Other
 
 
 
 
 
 
 
Re-measurement of deferred taxes

 
(433
)
 
433

 

Sale of SoCore Energy and other
(46
)
 
13

 
(59
)
 
5

Settlement of 1994 – 2006 California tax audits
(12
)
 

 
(12
)
 

     Discontinued operations
34

 

 
34

 
12

Total non-core items
(1,774
)
 
(901
)
 
(873
)
 
17

Core earnings (losses)
 
 
 
 
 
 
 
SCE
1,440

 
1,493

 
(53
)
 
1,376

Edison International Parent and Other
(89
)
 
(27
)
 
(62
)
 
(82
)
Edison International
$
1,351

 
$
1,466

 
$
(115
)
 
$
1,294

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, income resulting from allocation of losses to tax equity investors under the HLBV accounting method (related to previous results of SoCore Energy which was sold in the second quarter of 2018) 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 gains and losses related to certain tax, regulatory or legal settlements or proceedings, and exit activities, including sale of certain assets and other activities that are no longer continuing.

3




Edison International's 2018 earnings decreased $988 million, driven by a decrease in SCE's earnings of $1,322 million, partially offset by a decrease in Edison International Parent and Other losses of $300 million, and $34 million income from discontinued operations. SCE's lower net income consisted of $1,269 million of higher non-core losses and $53 million of lower core earnings. The decrease in core earnings was due to the impact of the July 2017 cost of capital decision on GRC revenue, higher operation and maintenance expenses related to wildfire insurance premiums and vegetation management and higher net financing costs, partially offset by higher income tax benefits.
Edison International Parent and Other losses from continuing operations for 2018 consisted of $62 million of higher core losses and $362 million of lower non-core losses. The increase in core losses in 2018 was due to income tax benefits in 2017 related to stock option exercises, net operating loss carrybacks from the filing of the 2016 tax returns in 2017, the 2017 settlement of federal income tax audits for 2007 – 2012 and the impact of Tax Reform on pre-tax losses, partially offset by a California tax audit settlement and the absence of SoCore Energy losses due to its sale in April 2018.
In the fourth quarter of 2018, Edison International reached a settlement with the California Franchise Tax Board for tax years 1994 – 2006. Edison International and SCE also updated their uncertain tax positions to reflect the settlement. Certain components of the settlement related to ongoing business activity of Edison International and SCE and are reflected in core earnings. Other components of the settlement related to legacy businesses of Edison International with no ongoing operations or tax positions that are no longer indicative of Edison International or SCE's ongoing earnings and are reflected in discontinued operations and non-core earnings, respectively. Overall, the settlement of the 1994 – 2006 California tax audits resulted in total tax benefits of $103 million at Edison International ($15 million core earnings, $54 million non-core earnings and $34 million earnings from discontinued operations) and $70 million at SCE ($4 million core earnings and $66 million non-core earnings).
Consolidated non-core items for 2018 and 2017 for Edison International included:
Charge of $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.
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 and income of $21 million ($13 million after-tax) in 2017 related to losses (net of distributions) allocated to tax equity investors under the HLBV accounting method. For further information on HLBV, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."
Income of $12 million ($9 million after-tax) in 2018 and charge of $716 million ($448 million after-tax) in 2017 for SCE related to the Revised San Onofre Settlement Agreement. For further information, see "—Permanent Retirement of San Onofre" below.
Income tax expense of $12 million, an income tax benefit of $66 million and an income tax benefit of $34 million in 2018 for Edison International Parent and Other, SCE and discontinued operations, respectively, related to the settlement of the 1994 – 2006 California tax audits discussed above.
Charges of $433 million in 2017 for Edison International Parent and Other and $33 million for SCE from the re-measurement of deferred taxes as a result of the Tax Cuts and Jobs Act ("Tax Reform"). For further information, see "— Tax Reform" below.
See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations.
2018 General Rate Case
SCE's GRC proceeding, for the three-year period 2018 – 2020, is pending. SCE has requested a revenue requirement of $5.534 billion for its test year of 2018, a $106 million decrease from the 2017 GRC authorized revenue requirement, and revenue requirements for the post-test years of 2019 and 2020 of $5.965 billion and $6.468 billion, respectively.
In the absence of a 2018 GRC decision, SCE has recognized revenue in 2018 and is recognizing revenue in 2019 based on the 2017 authorized revenue requirement, adjusted for the July 2017 cost of capital decision and Tax Reform. The CPUC has approved the establishment of a GRC memorandum account and the 2018 and 2019 revenue requirements adopted by the CPUC will be effective as of January 1, 2018 and January 1, 2019, respectively.
SCE accounts for regulatory decisions in the discrete period in which they are received and, accordingly, will record the impact of the 2018 GRC decision when a decision is received. SCE cannot predict the revenue requirements the CPUC will authorize or provide assurance on the timing of a final decision.

4




Southern California Wildfires and Mudslides
Approximately 35% of SCE's service territory is in areas identified as high fire risk by SCE. Multiple factors have contributed to increased wildfires, faster progression of wildfires and the 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.
In December 2017 and November 2018, wind-driven wildfires impacted portions of SCE's service territory, causing substantial damage to both residential and business properties and service outages for SCE customers. The largest of the 2017 fires, known as the Thomas Fire, originated in Ventura County and burned acreage located in both Ventura and Santa Barbara Counties. The largest of the 2018 fires, known as the Woolsey Fire, originated in Ventura County and burned acreage in both Ventura and Los Angeles Counties. According to CAL FIRE information, the Thomas Fire burned over 280,000 acres, destroyed an estimated 1,063 structures, damaged an estimated 280 structures and resulted in two fatalities, while the Woolsey Fire burned almost 100,000 acres, destroyed an estimated 1,643 structures, damaged an estimated 364 structures and resulted in three fatalities.
Multiple lawsuits related to the Thomas Fire and the Woolsey Fire have been initiated against SCE and Edison International. Some of the Thomas Fire-related lawsuits claim that SCE and Edison International have responsibility for the damages caused by the Montecito Mudslides based on a theory that SCE has responsibility for the Thomas Fire and that the Thomas Fire proximately caused the Montecito Mudslides. According to Santa Barbara County initial reports, the Montecito Mudslides destroyed an estimated 135 structures, damaged an estimated 324 structures, and resulted in 21 fatalities, with two additional fatalities presumed.
Investigations into the causes of the 2017/2018 Wildfire/Mudslide Events are ongoing and final determinations of liability 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 charge to be accrued under accounting standards. Based on SCE's internal review into the facts and circumstances of each of the 2017/2018 Wildfire/Mudslide Events 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 and have accrued a charge, before recoveries and taxes, of $4.7 billion in the fourth quarter of 2018. This charge corresponds to the lower end of the reasonably estimated range of expected potential 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. In the fourth quarter of 2018, Edison International and SCE also recorded expected recoveries from insurance of $2.0 billion and expected recoveries through electric rates of $135 million, which is the FERC portion of the $4.7 billion charge it accrued. The net charge to earnings recorded was $1.8 billion after-tax. SCE believes that in light of the CPUC's decision in cost recovery proceedings involving SDG&E, arising from a 2007 wildfire 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. 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 legislative, regulatory and legal strategies to address the application of a strict liability standard to wildfire-related damages without the ability to recover resulting costs in electric rates. However, Edison International and SCE cannot predict whether or when there will be a comprehensive solution mitigating the significant risk faced by California investor-owned utilities related to wildfires.
For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" and "Legal Proceedings."

5



Permanent Retirement of San Onofre
An ongoing CPUC OII proceeding regarding the steam generator replacement project at San Onofre and the related outages and subsequent shutdown of San Onofre was resolved in 2018 through the execution of the Revised San Onofre Settlement Agreement. In connection with the Revised San Onofre Settlement Agreement, and in exchange for the release of certain San Onofre-related claims, SCE and SDG&E entered into a Utility Shareholder Agreement, in which SCE agreed to pay SDG&E the amounts SDG&E would have received in rates under the Prior San Onofre Settlement Agreement but will not receive upon the implementation of the Revised San Onofre Settlement Agreement. In the fourth quarter of 2017, SCE incurred a charge of $716 million ($448 million after-tax) to adjust regulatory assets and liabilities based on the probable approval of the Revised San Onofre Settlement Agreement and to record an accrued liability of $143 million for the estimated present value of the obligation due to SDG&E under the Utility Shareholder Agreement.
In July 2018, the CPUC approved all of the terms of the Revised San Onofre Settlement Agreement other than a provision under which SCE agreed to fund $10 million for a research, development and demonstration program intended to develop technologies and methodologies to reduce GHG emissions (the "Modification"). The Revised San Onofre Settlement Agreement with the Modification became effective on August 2, 2018, and SCE recorded a benefit related to the Modification during the third quarter of 2018.
For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Permanent Retirement of San Onofre."
Tax Reform
In December 2017, Tax Reform was signed into law. This comprehensive reform of tax law reduces the federal corporate income tax rate from 35% to 21% and is generally effective beginning January 1, 2018. Certain provisions of Tax Reform, such as full expensing of certain capital expenditures ("bonus depreciation") and limitations on the deductibility of interest expense are not applicable to regulated utilities, such as SCE. Edison International expects it will be exempt from the new interest disallowance provisions under de-minimis rules issued by the IRS in 2018.
GAAP requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, at December 31, 2017, the company's deferred taxes were re-measured based upon the new tax rate. Immediately prior to the enactment of Tax Reform, Edison International Parent and Other had approximately $2.6 billion of federal net operating loss carryforwards ("NOL") (excluding Capistrano Wind net operating loss carryforwards of approximately $400 million). The reduction in the federal corporate income tax rate does not change the gross dollar value of taxable income that may be offset by NOLs, however since future income will only be taxable at 21% the value of NOLs utilized after 2017 is reduced. The re-measurement of these NOLs along with the other deferred taxes, resulted in a non-core charge of $433 million reflected in "Income tax expense" for Edison International Parent and Other at December 31, 2017. Edison International Parent and Other also has $347 million of tax credit carryforwards (excluding Capistrano Wind tax credit carryforwards of approximately $112 million) which directly offset taxes due and are not re-measured in connection with Tax Reform.
The specific provisions of Tax Reform applicable to SCE allow for the continued deductibility of interest expense, eliminate bonus depreciation for property acquired after December 31, 2017, and continues rate normalization requirements for accelerated depreciation benefits. While the re-measurement of deferred taxes at Edison International Parent and Other were recorded to earnings, the re-measurement of deferred taxes at SCE was mainly recorded to regulatory liabilities or an offset to regulatory assets since pre-tax amounts giving rise to the deferred taxes were created through ratemaking activities. Since the majority of SCE's deferred taxes arise from property-related differences, SCE estimates that the amount to be refunded will be amortized over approximately 40 or more years. The specifics of how and when the amounts will be returned are expected to be approved in early 2019 as both the CPUC and FERC finalize rate proceedings addressing this issue, among other things.
In the absence of regulatory guidance specific to Tax Reform, SCE used judgment to interpret prior CPUC and FERC decisions to determine which re-measurement amounts will be refunded to customers. At December 31, 2017, the implementation of Tax Reform for SCE resulted in a reduction of deferred tax liabilities and an increase in regulatory liabilities of approximately $5.0 billion ("Excess Deferred Taxes"). A non-core charge of $33 million was recorded for the re-measurement of deferred taxes attributable to shareholder-funded activities in 2017 "Income tax expense."

6




Changes in the allocation of deferred tax re-measurement between customers and shareholders will be reflected in the financial statements and adjusted prospectively as information becomes available. The CPUC issued a resolution in February 2019 holding that customers are only entitled to excess deferred taxes that were included when setting rates, and that all other deferred tax re-measurement belongs to shareholders. As a result of the resolution, SCE will record a non-core income tax benefit of approximately $70 million in the first quarter of 2019.
In the near term, Tax Reform will lower rates charged to customers, but will not have a meaningful impact to SCE's earnings. Certain deferred tax liabilities reduce SCE's rate base. The re-measurement of deferred tax liabilities from the implementation of Tax Reform will not impact SCE's rate base initially. However, Tax Reform's elimination of bonus depreciation and lower corporate tax rates will reduce cash flow from operations and increase rate base over time. In addition, as new plant is placed in service the lower federal corporate tax rate will result in lower deferred tax liabilities and, therefore, higher rate base. See "—Capital Program." To the extent that Edison International Parent and Other continue to produce pre-tax losses, Tax Reform will result in lower tax benefits. Tax Reform will also impact Edison International's liquidity. See "Liquidity and Capital Resources—Edison International Parent and Other—Net Operating Loss and Tax Credit Carryforwards."
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 is 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 percent from 1990 levels by 2030 and 80 percent from the same baseline by 2050. State and local air quality plans call for substantial improvements, such as reducing smog-causing nitrogen oxides 90 percent 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. 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 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 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 "—Capital Program—Grid Development" below.
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 provide a broader 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.


7




Capital Program
Total capital expenditures (including accruals), were $4.4 billion in 2018 and $3.8 billion in 2017. SCE's year-end rate base was $29.6 billion at December 31, 2018 compared to $27.8 billion at December 31, 2017.
In the absence of a 2018 GRC decision, SCE has developed and is executing against a 2019 capital plan that will allow it to manage capital spending over the three year GRC period to meet what is ultimately authorized while minimizing the risk of unauthorized spending. A component of this approach is to focus initial grid modernization spending on capital that provides safety and reliability benefits while deferring most spending that is primarily focused on integration of DERs. The 2019 capital plan also includes spending associated with SCE's GS&RP and 2019 WMP which are incremental to amounts requested in the 2018 GRC. In September 2018, SCE filed an application with the CPUC requesting approval of a GS&RP to implement additional wildfire safety measures and in January 2019, the CPUC authorized the establishment of an interim memorandum account to track incremental GS&RP expenditures. In February 2019, SCE filed its 2019 WMP with the CPUC.
The table below reflects capital expenditures for 2019 based on planned CPUC jurisdictional spending, including $346 million of GS&RP- and WMP- related capital expenditures, and capital expenditures for 2020 based on amounts requested in the 2018 GRC. CPUC jurisdictional capital expenditures related to the GS&RP will be incorporated into the 2020 capital forecast after the receipt of the 2018 GRC decision, as part of the capital execution planning process. Given the significance of wildfire-related risks and the need for skilled resources to complete activities, SCE may reallocate spending authorized in the 2018 GRC to maximize the wildfire mitigation efforts. FERC jurisdictional capital expenditures are based on management's expectations. Forecasted expenditures for FERC capital projects are subject to change due to timeliness of permitting, licensing, regulatory approvals, and contractor bids. Capital spending in 2019 and 2020 will be dependent upon the amount approved in a final 2018 GRC decision. For further information, see "—Grid Development" below.
The CPUC has approved 81%, 89%, and 92% of the traditional capital expenditures requested in the 2009, 2012, and 2015 GRC decisions, respectively. While SCE cannot predict the level of traditional capital spending that will be approved in the 2018 GRC decision, management is not aware of factors that would cause the percentage of SCE's request that is approved to be materially different from what has been approved in recent GRC decisions. SCE does not have prior approval experience with grid modernization capital expenditures and, therefore, is unable to predict an expected outcome. Forecasted expenditures for capital projects are subject to change due to, among other things, timeliness of permitting, licensing, regulatory approvals, and contractor bids. For further information regarding the capital program, see "Liquidity and Capital Resources—SCE—Capital Investment Plan."
The following table sets forth a summary of capital expenditures for 2018 actual spend and a forecast for 2019 – 2020 on the basis described above:
(in millions)
 
2018
2019
2020
Total 2019 – 2020
Traditional capital expenditures1
 
 
 
 
 
Distribution2
 
$
3,499

$
3,565

$
3,109

$
6,674

Transmission
 
656

701

774

1,475

Generation
 
208

211

201

412

Total traditional capital expenditures1
 
$
4,363

$
4,477

$
4,084

$
8,561

Grid modernization capital expenditures2
 
$

$

$
608

$
608

Total capital expenditures
 
$
4,363

$
4,477

$
4,692

$
9,169

1
Includes 2018 – 2019 capital expenditures for GS&RP and 2019 WMP (see "Grid Development" below).
2
2018 and 2019 capital expenditures related to grid modernization are included in traditional capital expenditures.

8




SCE's CPUC-jurisdictional rate base is determined by the amount authorized by the CPUC. Differences between actual and authorized capital expenditures are addressed in subsequent GRC proceedings. Capital expenditure requests in CPUC filings made outside of the GRC process are not included in rate base until approved by the CPUC. FERC-jurisdictional rate base is generally determined based on actual capital expenditures. Reflected below is SCE's estimated weighted average annual rate base for 2018 – 2020 using CPUC capital expenditures as requested in the 2018 GRC and expected FERC capital expenditures.
(in millions)
 
2018
2019
2020
Rate base for requested traditional capital expenditures
 
$
28,792

$
31,073

$
33,428

Rate base for requested grid modernization capital expenditures
 
264

743

1,279

Total rate base
 
$
29,056

$
31,816

$
34,707

The rate base above does not reflect reductions from the amounts requested in the 2018 GRC that may be included in a final decision.
Grid Development
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.
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. The amounts requested for the 2018 to 2020 period are not included in SCE's 2018 GRC. In January 2019, the CPUC approved the establishment of an interim memorandum account to track GS&RP costs while the CPUC considers SCE's request for a balancing account, however there is no assurance that SCE will be allowed to ultimately recover these costs. The CPUC also imposed a monthly reporting requirement to enable monitoring of SCE's GS&RP spending. GS&RP capital expenditures for 2018 were $54 million and forecasted GS&RP capital expenditures for 2019 are $224 million. If SCE's proposed balancing account is approved, forecasted costs for GS&RP will be included in rates, with a subsequent reasonableness review through the annual ERRA proceeding.
Wildfire Mitigation Plan
In February 2019, SCE filed its 2019 WMP with the CPUC. The WMP describes strategies, programs and activities that are in place, being implemented or are under development by SCE to proactively address and mitigate the threat of electrical infrastructure-associated ignitions that could lead to wildfires. Many, but not all, of the programs and activities described in the 2019 WMP are part of SCE's 2018 GRC request or GS&RP application. Upon approval, SCE will establish a memorandum account to track incremental costs incurred to implement the WMP. The planned 2019 WMP spending not contemplated in the 2018 GRC and GS&RP proceedings is approximately $380 million of which $122 million is capital. SCE will track costs and seek recovery in future CPUC procedural forums for any incremental costs beyond those which are ultimately approved in the 2018 GRC decision and the GS&RP proceeding.
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

9




implement a supporting marketing, education, and outreach campaign. As of December 31, 2018, SCE had executed agreements and reserved funding for 79 sites to deploy 1,280 charge ports. 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 bridge funding to continue the Charge Ready Program Pilot until Charge Ready 2 is ultimately approved. SCE's 2019 capital plan contemplates $13 million of bridge Charge Ready Program Pilot spending. SCE is unable to estimate the amount of capital that will be approved, or the timing of any such approval, in connection with Charge Ready 2.
Distribution Resources Plan
In July 2015, SCE filed its DRP with the CPUC. The filing was made as part of a CPUC proceeding initiated to support California's climate change and GHG reduction targets, modernize the electric distribution system to accommodate two-way flows of energy associated with DERs, such as rooftop solar, and facilitate customer choice of new technologies and services that reduce emissions and improve resilience. SCE's DRP included an indicative forecast of capital investment in distribution automation, substation automation, communications systems, technology platforms and applications, and grid reinforcement. SCE's 2018 GRC includes operation and maintenance and capital expenditure requests consistent with SCE's DRP operation and maintenance and capital spending. Capital investments may be updated or revised based on developments and guidance received from the CPUC as a part of the 2018 GRC, DRP rule making, technology availability, pace of DER adoption, and other factors. In February 2018, the CPUC issued a decision that established a new distribution investment deferral framework and provided new guidance regarding DER adoption forecasting. In March 2018, the CPUC approved a decision that provides a grid modernization framework that will be used to support CPUC review of grid modernization investments that are proposed in a GRC. This grid modernization framework will not apply to SCE's 2018 GRC, unless otherwise ordered by the ALJ or Assigned Commissioner in the 2018 GRC. It will apply to subsequent GRCs.
RESULTS OF OPERATIONS
SCE
SCE's results of operations are derived mainly through two sources:
Earning activities – representing revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of authorized operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in 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.

10




The following table is a summary of SCE's results of operations for the periods indicated.
 
2018
2017
2016
(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
$
6,560

$
6,051

$
12,611

$
6,611

$
5,643

$
12,254

$
6,504

$
5,326

$
11,830

Purchased power and fuel

5,406

5,406


4,873

4,873


4,527

4,527

Operation and maintenance1
1,972

730

2,702

1,898

824

2,722

1,934

838

2,772

Wildfire-related claims, net of insurance recoveries
2,669


2,669







Depreciation and amortization
1,867


1,867

2,032


2,032

1,998


1,998

Property and other taxes
392


392

372


372

351


351

Impairment and other
(12
)

(12
)
716


716




Other operating income
(7
)

(7
)
(8
)

(8
)



Total operating expenses
6,881

6,136

13,017

5,010

5,697

10,707

4,283

5,365

9,648

Operating (loss) income
(321
)
(85
)
(406
)
1,601

(54
)
1,547

2,221

(39
)
2,182

Interest expense
(671
)
(2
)
(673
)
(588
)
(1
)
(589
)
(540
)
(1
)
(541
)
Other income and expenses
107

87

194

93

55

148

74

40

114

(Loss) income before income taxes
(885
)

(885
)
1,106


1,106

1,755


1,755

Income tax (benefit) expense
(696
)

(696
)
(30
)

(30
)
256


256

Net (loss) income
(189
)

(189
)
1,136


1,136

1,499


1,499

Preferred and preference stock dividend requirements
121


121

124


124

123


123

Net (loss) income available for common stock
$
(310
)
$

$
(310
)
$
1,012

$

$
1,012

$
1,376

$

$
1,376

Net (loss) income available for common stock
 
 
$
(310
)
 
 
$
1,012

 
 
$
1,376

Less: Non-core items
 
 
 
 
 
 
 
 
 
  Wildfire-related claims, net of recoveries
 
 
(1,825
)
 
 

 
 

    Impairment and other
 
 
9

 
 
(448
)
 
 

  Re-measurement of deferred taxes
 
 

 
 
(33
)
 
 

    Settlement of California tax audits
 
 
66

 
 

 
 

Core earnings2
 
 
$
1,440

 
 
$
1,493

 
 
$
1,376

1 
Expenses for the years ended December 31, 2017 and 2016, respectively, were updated to reflect the implementation of the accounting standard update for net periodic benefit costs related to the defined benefit pension and other postretirement plans. For further information, see Note 1 in the "Notes to Consolidated Financial Statements."
2 
See use of non-GAAP financial measures in "Management Overview—Highlights of Operating Results."
Earning Activities
2018 vs 2017
Earning activities were primarily affected by the following:
Lower operating revenue of $51 million is primarily due to:
A decrease of $164 million in CPUC revenue primarily from recognizing 2018 revenue based on the 2017 authorized revenue requirement, adjusted for the July 2017 cost of capital decision and the impact of Tax Reform, partially offset by the receipt of a $17 million reimbursement related to spent nuclear fuel storage costs recorded in 2018 and a $15 million refund to customers for prior overcollections of revenue recorded in 2017. See "Management Overview—

11




2018 General Rate Case" and "Notes to Consolidated Financial Statements—Note12. Commitments and Contingencies—Spent Nuclear Fuel" for further information.
An increase in FERC revenue of $44 million primarily due to $135 million of expected recoveries from customers for the FERC portion of wildfire-related claims, partially offset by a decrease in revenue due to the reduction in the federal corporate income tax rate resulting from Tax Reform.
A decrease in revenue related to San Onofre of $223 million primarily related to the recovery of amortization of the San Onofre regulatory asset in 2017 (offset in depreciation and amortization) and authorized return as provided by the Prior San Onofre Settlement Agreement. As a result of the Revised San Onofre Settlement Agreement, there was no revenue recorded in 2018 for San Onofre other than the previously disallowed costs. See "Management Overview—Permanent Retirement of San Onofre" for further information.
An increase in revenue of $338 million related to tax balancing account activities (offset in income taxes below), consisting of $216 million of lower customer refunds for incremental tax repair benefits and $122 million for tax benefits related to 2017 tax accounting method changes.
A decrease of $75 million resulting from the amortization of excess deferred tax assets as a result of Tax Reform.
Higher operation and maintenance expense of $74 million primarily due to higher wildfire insurance premiums and vegetation management costs (see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides—Current Wildfire Insurance Coverage" for further information).
Charge of $2.7 billion recorded in 2018 for wildfire-related claims, net of expected insurance recoveries.
Lower depreciation and amortization expense of $165 million primarily related to the amortization of the San Onofre regulatory asset in 2017 (offset in revenue above).
Higher property and other taxes of $20 million primarily due to higher property assessed values in 2018.
Lower impairment and other of $728 million primarily related to charges recorded in 2017 due to the Revised San Onofre Settlement Agreement. See "Management Overview—Permanent Retirement of San Onofre" for further information.
Higher interest expense of $83 million primarily due to increased borrowings and higher interest on balancing account overcollections in 2018.
Higher other income and expenses of $14 million primarily due to higher AFUDC equity income. See "Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses" for further information.
Lower income taxes of $666 million primarily due to the following:
Higher non-core income tax benefits of $540 million due to 2018 tax benefits of $709 million related to the charge for wildfire-related claims, $66 million related to the settlement of the 1994 – 2006 California tax audits and $33 million of 2017 tax expense related to the re-measurement of deferred taxes resulting from the implementation of Tax Reform, partially offset by tax benefits of $268 million recorded in 2017 due to charges related to the Revised San Onofre Settlement Agreement.
The impact of a lower federal income tax rate on pre-tax income and a true-up related to the filing of the federal income tax return of $208 million, partially offset by lower income tax benefits of $184 million due to the tax balancing account activities referred to above and the impact of Tax Reform on those activities.
Lower pre-tax income in 2018, excluding non-core items discussed above.
2017 vs 2016
Earning activities were primarily affected by the following:
Higher operating revenue of $107 million is primarily due to:
An increase in revenue of approximately $241 million related to the increase in authorized revenue from the escalation mechanism set forth in the 2015 GRC decision and $32 million of higher operating costs subject to balancing account treatment (primarily offset in depreciation expense below). These increases were partially offset by $33 million of

12




lower revenue related to the extension of bonus depreciation and a $15 million revenue reduction for the expected refund to customers of prior overcollections identified in 2017.
Energy efficiency incentive awards recognized in 2017 were $17 million compared to $5 million in 2016. During 2016, the CPUC approved a settlement agreement in which SCE agreed to refund $13 million related to incentive awards SCE received for savings achieved by its 2006 – 2008 energy efficiency programs.
A decrease in revenue of $118 million related to tax benefits refunded to customers (offset in income taxes below). The decrease in revenue resulted from $116 million of higher year-over-year incremental tax repair benefits recognized and $135 million of benefits recognized for tax accounting method changes. These decreases were partially offset by a 2016 revenue refund to customers of $133 million related to 2012 – 2014 incremental tax repair deductions.
A decrease in FERC-related revenue of $39 million primarily related to higher operating costs in 2016 including amortization of the regulatory asset associated with the Coolwater-Lugo transmission project and a $8 million reduction to FERC revenue due to a change in estimate under the FERC formula rate mechanism.
An increase of $20 million for other operating revenue resulting from refunds to customers recorded in 2016 due to the retroactive extension of bonus depreciation in the PATH Act of 2015.
Lower operation and maintenance expense of $36 million primarily due to the impact of SCE's operational and service excellence initiatives and lower legal costs, partially offset by higher transmission and distribution costs for line clearing and maintenance and information technology costs.
Higher depreciation and amortization expense of $34 million primarily related to depreciation and amortization on transmission and distribution investments, partially offset by amortization of the regulatory asset related to Coolwater-Lugo plant recorded in 2016.
Higher property and other taxes of $21 million primarily due to higher property assessed values in 2017.
Impairment charge of $716 million in 2017 due to the Revised San Onofre Settlement Agreement (see "Management Overview—Highlights of Operating Results" for further information).
Higher other operating income of $8 million due to the sale of utility property.
Higher interest expense of $48 million primarily due to increased borrowings and higher interest on balancing account overcollections in 2017.
Higher other income and expenses of $19 million primarily due to higher AFUDC equity income. See "Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses" for further information.
Lower income taxes of $286 million primarily due to the following:
Higher non-core income tax benefits in 2017 of $235 million due to the impairment and other charges related to the Revised San Onofre Settlement Agreement, partially offset by $33 million income tax expense related to the re-measurement of deferred taxes resulting from the implementation of Tax Reform.
Higher income tax benefits in 2017 of $70 million due to $149 million related to flow through of incremental tax repair benefits and for tax accounting method changes (offset in revenue above), partially offset by $79 million flow-through of 2012 – 2014 incremental income tax benefits in 2016.
Higher pre-tax income in 2017, excluding non-core items discussed above.
Cost-Recovery Activities
2018 vs 2017
Cost-recovery activities were primarily affected by the following:
Higher purchased power and fuel costs of $533 million primarily driven by higher power and gas prices and volume experienced in 2018 relative to 2017, partially offset by higher congestion revenue right credits, lower capacity costs, proceeds from contract amendments and the receipt of funds in 2018 from counterparties related to the California energy crisis.

13




Lower operation and maintenance expense subject to balancing accounts of $94 million primarily driven by reduced spending on energy efficiency programs and the timing of revenue recognition associated with costs tracked through memorandum accounts, partially offset by higher transmission access charges.
Higher other income and expenses of $32 million primarily driven by higher net periodic benefit income related to the non-service cost components in 2018 relative to 2017. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for further information.
2017 vs 2016
Higher purchased power and fuel costs of $346 million primarily driven by higher power and gas prices experienced in 2017 relative to 2016, partially offset by lower realized losses on hedging activities ($14 million in 2017 compared to $59 million in 2016) and lower capacity costs.
Lower operation and maintenance expense of $14 million primarily driven by lower employee benefit and other labor costs and lower spending on various public purpose programs, partially offset by an increase in transmission and distribution costs for line clearing and maintenance activities.
Higher other income and expenses of $15 million primarily driven by higher net periodic benefit income related to the non-service cost components in 2017 relative to 2016. 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 $11.7 billion, $11.4 billion and $10.9 billion for 2018, 2017 and 2016, respectively.
The 2018 revenue increase is primarily related to higher purchased power and fuel costs driven by higher power and gas prices and volume experienced in 2018 relative to 2017, partially offset by higher congestion revenue right credits and lower revenue for San Onofre resulting from the Revised San Onofre Settlement Agreement. See "—Cost-Recovery Activities" and "—Earnings Activities" for further details.
The 2017 revenue reflects an increase primarily due to the implementation of the 2017 ERRA rate increase.
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 $666 million in 2018 compared to 2017 and decreased by $286 million in 2017 compared to 2016. The effective tax rates were (78.6)%, (2.7)% and 14.6% for 2018, 2017 and 2016, respectively. SCE's effective tax rate is below the federal statutory rate of 21% for 2018 and 35% for 2017 and 2016 primarily due to 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 2018 was due to the settlement of the 1994 – 2006 California tax audits, the impact of Tax Reform and incremental tax benefits related to repair deductions, coupled with the large pre-tax loss created by the charge of $2.5 billion for wildfire-related claims, net of recoveries from insurance and customers. The effective tax rate decrease in 2017 was primarily due to an impairment charge of $716 million related to the Revised San Onofre Settlement Agreement. The decrease was also attributable to higher incremental repair tax benefits and benefits recognized for tax accounting method changes, all of which will be refunded to customers, partially offset by lower tax benefits related to a $133 million revenue refund to customers that was recorded in 2016.
See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for a reconciliation of the federal statutory rate to the effective income tax rates and "Management Overview—Permanent Retirement of San Onofre" above for more information.
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.

14




Loss from Continuing Operations
The following table summarizes the results of Edison International Parent and Other:
 
Years ended December 31,
(in millions)
2018
 
2017
 
2016
Edison Energy Group and subsidiaries
$
(78
)
 
$
(26
)
 
$
(38
)
Corporate expenses and other subsidiaries
(69
)
 
(421
)
 
(39
)
Total Edison International Parent and Other
$
(147
)
 
$
(447
)
 
$
(77
)
The loss from continuing operations of Edison International Parent and Other decreased $300 million in 2018 compared to 2017 primarily due to:
Lower income tax expense in 2018 primarily due to $433 million of tax expense recorded in 2017 related to the re-measurement of deferred taxes that resulted from Tax Reform, partially offset by income tax benefits of $44 million recorded in 2017 related to stock option exercises, $17 million of tax benefits recorded in 2017 related to net loss carrybacks from the filing of the 2016 tax returns, $6 million of tax benefits recorded in 2017 related to the settlement of 2007 – 2012 federal income tax audits and the impact of Tax Reform on pre-tax losses. In addition, income tax expense of $12 million of tax expense was recorded in 2018 related to the settlement of the 1994 – 2006 California tax audits, offset by a reduction in uncertain tax positions that resulted from this settlement.
Increase in losses of $44 million due to the impact from the April 2018 sale of SoCore Energy, partially offset by a goodwill impairment recorded in 2017 on the SoCore Energy reporting unit. The higher losses included lower HLBV income, partially offset by a reduction in losses due to the exit of this business activity in 2018. In addition, Edison Energy Group's 2018 results included a $13 million after-tax goodwill impairment charge on the Edison Energy reporting unit.
The loss from continuing operations of Edison International Parent and Other increased $370 million in 2017 compared to 2016 primarily due to:
Income tax expense of $433 million in 2017 from the re-measurement of deferred taxes as a result of Tax Reform.
Higher income tax benefits related to stock option exercises of $30 million for the year ended December 31, 2017, $17 million of tax benefits recorded in 2017 from net operating loss carrybacks that resulted from the filing of the 2016 tax returns and $6 million of tax benefits recorded in 2017 related to settlement with the IRS for taxable years 2007 – 2012.
Edison Energy Group's 2017 results included HLBV income of $13 million, a $10 million after-tax goodwill impairment charge on the SoCore Energy reporting unit and net tax expense of $5 million from a change in tax law partially offset by tax benefits primarily related to stock option exercises. Edison Energy Group's 2016 results included HLBV income of $5 million, $13 million after-tax charge in 2016 from a buy-out of an earn-out provision contained in one of the 2015 acquisitions and net tax benefits of $5 million primarily related to stock option exercises. Excluding these items, Edison Energy Group net losses were $24 million in 2017 and $35 million in 2016. The reduction in these losses was due to lower expenses related to new business activities. Revenue for the Edison Energy Group was $69 million and $42 million for the years ended December 31, 2017 and 2016, respectively. The increase in revenue was primarily due to higher build transfer projects from SoCore Energy in 2017.

15




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 Edison International and preferred and preference shareholders, and the outcome of tax and regulatory matters.
As discussed in "Management Overview," Tax Reform is expected to lower rates charged to customers which will result in less cash available to fund operations. In the next 12 months, SCE expects to fund its cash requirements through operating cash flows and capital market financings, as needed. SCE also has availability under its credit facilities to fund cash requirements.
SCE's long-term issuer credit ratings remain at investment grade levels after downgrade actions taken by the major credit agencies in 2018 and early 2019. 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
 
A3
BBB+
BBB
Outlook
 
Under Review for Downgrade
Negative
Watch Negative
SCE's credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters, including the outcome of the uncertainties and potential liabilities associated with the 2017/2018 Wildfire/Mudslide Events, and the reform of policies allocating liability to investor-owned utilities for damages caused by catastrophic wildfires substantially caused by utility equipment. 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 require SCE to pay related liabilities or post additional collateral if SCE's credit rating were to fall below investment grade rating from the major credit rating agencies. Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade is $22 million as of December 31, 2018. 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. For further details, see "—Margin and Collateral Deposits."
Available Liquidity
In May 2018, SCE amended its multi-year revolving credit facility to increase the facility from $2.75 billion to $3.0 billion.
At December 31, 2018, SCE had $2.1 billion available under its $3.0 billion credit facility. The credit facility is available for borrowing needs until May 2023, and contains two 1-year extension options. In February 2019, SCE issued a $750 million term loan and the proceeds of the loan were used to repay SCE's commercial paper borrowings and for general corporate purposes. For further details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
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. As necessary, SCE will utilize its available liquidity, capital market financings, other borrowings or parent company contributions to SCE equity in order to meet its obligations as they become due, including any potential costs related to the 2017/2018 Wildfire/Mudslide Events (see "Management Overview—Southern California Wildfires and Mudslides" for further information).
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, 2018, SCE's debt to total capitalization ratio was 0.50 to 1.
At December 31, 2018, SCE was in compliance with all financial covenants that affect access to capital.

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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
$848
$241
2021
Mesa Substation
Construction
$646
$268
2022
Alberhill System
Licensing
$486
$39
2
Riverside Transmission Reliability
Licensing
$441
$9
2023
Eldorado-Lugo-Mohave Upgrade
Licensing
$233
$59
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 
SCE is unable to predict the timing of a final CPUC decision, and the corresponding in-service date, in connection with the Alberhill System Project.
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. As a result of the delay in receipt of the Project's approval from the CPUC, SCE deferred the forecasted timing of project capital expenditures. PAO filed an Application for Rehearing in September 2016 stating that the August 2016 decision failed to follow the California Environmental Quality Act when it approved the Project and should have approved an alternative project with an amended scope. In March 2017, the CPUC issued a decision denying PAO's September 2016 Application for Rehearing and confirmed SCE's proposed project. During 2018, SCE started construction on the 220kV transmission line and expects to complete construction by 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. In October 2017, SCE awarded the competitive bid for the new 220kV portion of substation construction. SCE updated the expected cost of the Project due to schedule delays and scope changes. The remainder (500kV portion of substation construction) will be put out for bid by early 2019 and SCE expects that costs associated with the Project may change as a result of the competitive bidding process.
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. 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 directed SCE to submit supplemental information on the Alberhill System Project including details of demand and load forecasts and possible alternatives to the proposed project. Ongoing capital spending has been deferred as a result of the CPUC request for additional information and alternatives. Given the uncertainty

17




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 the Alberhill System Project is needed and is unable to predict the timing of a final CPUC decision in connection with the Alberhill System Project.
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 $42 million of capital expenditures, including overhead costs, as of December 31, 2018, of which approximately $31 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 April 2018, the CPUC issued a subsequent environmental impact report which included a new route alternative, different from SCE's proposed project, as the environmentally preferred project and proposed an additional underground section of the proposed 220-kV power line. In October 2018, the CPUC issued the final environmental report confirming the CPUC's new route alternative and additional underground section as the environmentally preferred project. SCE is assessing costs for its proposed project as well as new cost estimates for the alternatives included in the final environmental report. SCE anticipates a final CPUC decision on a certificate of public convenience and necessity in the first quarter of 2020.
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 communication wire on our transmission lines to allow for communication between existing SCE substations. SCE has proposed an expedited schedule and a non-standard review process with the regulatory permitting agencies in order to meet the current in-service date. During September 2017, SCE awarded the competitive bid for the Project which resulted in a decrease to the expected capital forecast for the Project. In January 2019, the CPUC directed SCE to file an amended application for a certificate of public convenience and necessity. SCE is currently assessing the impact of this decision on the timing and cost of the Project.
Regulatory Proceedings
Cost of Capital
In July 2017, the CPUC adopted a petition previously filed by SCE, PG&E, SDG&E, and SoCalGas (collectively, the "Investor-Owned Utilities"), PAO, and TURN to modify the prior CPUC decisions addressing the Investor-Owned Utilities' costs of capital. The decision reset SCE's authorized cost of long-term debt to 4.98% and preferred stock to 5.82% and established SCE's authorized ROE at 10.30%, both effective as of January 1, 2018. The decision also extended the deadline for the next Investor-Owned Utilities cost of capital application to April 2019.
FERC Formula Rate
In June 2018, SCE provided its preliminary 2019 annual transmission revenue requirement update to interested parties. The update provided support for a decrease in SCE's transmission revenue requirement of $131 million, or 11% from amounts currently authorized in rates, subject to settlement procedures and refund. The decrease is primarily due to lowering the federal tax rate as a result of Tax Reform. SCE filed its 2019 annual update with the FERC on November 29, 2018 with the proposed rates effective January 1, 2019, subject to settlement procedures and refund.

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In March 2019, SCE expects to file a new formula rate with FERC. Once the new formula rate is accepted by FERC, it will supersede the existing formula rate, including the 2019 annual update, and could become effective as early as 60 days from the filing date. FERC has the authority to, and may, suspend new rates for up to five months. If the new formula rate is suspended by FERC, the 2019 transmission revenue requirement rate established in the 2019 annual update will continue to be effective, subject to refund, from January 1, 2019 until the end of the suspension of the new formula rate. The new formula rate would likely be subject to refund from the end of the suspension until it is ultimately approved by FERC.
Energy Efficiency Incentive Mechanism
SCE has requested an award of approximately $11 million in incentives for activities in program years 2016 and 2017. SCE anticipates that the CPUC will consider SCE's requested award during the first or second quarter of 2019.
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. The initial activity phase of 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. However, 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. SCE cannot predict when fuel transfer operations at San Onofre will recommence. SCE is in the process of obtaining the environmental permits required to start major radiological decommissioning activities at San Onofre Units 2 and 3. SCE cannot predict when all of the necessary permits will be obtained.
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 2018 were $140 million.
SCE had nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $2.6 billion as of December 31, 2018. 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. In the event that 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.

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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. Under SCE's interpretation of CPUC regulations, the common equity component of SCE's capital structure must remain at or above 48% on a weighted average basis over the 37-month period that SCE's capital structure is in effect for ratemaking purposes. As allowed under the Revised San Onofre Settlement Agreement, which was approved by the CPUC in July 2018, SCE has excluded a $448 million after-tax charge resulting from the implementation of the Revised San Onofre Settlement Agreement from its ratemaking capital structure (see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Permanent Retirement of San Onofre" for further information on the Revised San Onofre Settlement Agreement). At December 31, 2018, SCE's 37-month average common equity component of total capitalization was 49.7% and the maximum additional dividend that SCE could pay to Edison International under this limitation after paying preferred and preference shareholders was $459 million, resulting in a restriction on net assets of approximately $13.3 billion.
Under SCE's interpretation of the CPUC's capital structure decisions, SCE is 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%. On February 28, 2019, SCE is submitting 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 is seeking 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. 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."
As a California corporation, SCE's ability to pay dividends is also governed by its obligations under 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 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 28, 2019, SCE declared a dividend to Edison International of $200 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, and its ability to access the capital markets, and generate operating cash flows and earnings. If SCE incurs significant costs related to the 2017/2018 Wildfire/Mudslide Events and is unable to recover such costs through insurance or electric rates or access capital markets on reasonable terms, SCE may be limited in its ability to pay future dividends to Edison International and to its preferred and preference shareholders.

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Margin and Collateral Deposits
Certain derivative instruments, power 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, 2018 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, 2018.
(in millions)
 
 
Collateral posted as of December 31, 20181
 
$
198

Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade2
 
22

Incremental collateral requirements for power procurement contracts resulting from adverse market price movement3
 
24

Posted and potential collateral requirements
 
$
244

1 
Net collateral provided to counterparties and other brokers consisted $191 million in letters of credit and surety bonds and $7 million of cash which was offset against net derivative liabilities on the consolidated balance sheets.
2 
If SCE's credit ratings were to fall below investment grade as of December 31, 2018, SCE may also be required to post up to $50 million in collateral by April 30, 2019 related to environmental remediation obligations.
3 
Incremental collateral requirements were based on potential changes in SCE's forward positions as of December 31, 2018 due to adverse market price movements over the remaining lives of the existing power contracts using a 95% confidence level.
Regulatory Balancing Accounts
SCE's cash flows are affected by regulatory balancing 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 accounts impact cash flows and can change rapidly. Undercollections and overcollections accrue interest based on a three-month commercial paper rate published by the Federal Reserve.
As of December 31, 2018, SCE had regulatory balancing account net overcollections of $1.3 billion, primarily consisting of overcollections related to public purpose-related and energy efficiency program costs and BRRBA. 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 2019. 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 bank and capital market financings, as needed. Edison International also has availability under its credit facilities to fund cash requirements. In December 2018, Edison International declared a $0.03 increase to the annual dividend rate from $2.42 per share to $2.45 per share. On February 28, 2019, Edison International declared a dividend of $0.6125 per share to be paid on April 30, 2019. Edison International Parent and Other's liquidity and its ability to pay operating expenses 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."

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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 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.
As a result of the sale of SoCore Energy, Edison Energy Group made dividend payments to Edison International Parent of
$101 million in 2018.
In May 2018, Edison International Parent amended its multi-year revolving credit facility to increase the facility from
$1.25 billion to $1.5 billion. At December 31, 2018, Edison International Parent had $97 million of cash and cash equivalents and $1.5 billion available under its credit facility. The credit facility is available for borrowing needs until May 2023 and contains two 1-year extension options. The 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, 2018, Edison International Parent's consolidated debt to total capitalization ratio was 0.55 to 1. For further details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
At December 31, 2018, 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. 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
 
Baa1
BBB+
BBB
Outlook
 
Under Review for Downgrade
Negative
Watch Negative
Edison International Parent's credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters, including the outcome of the uncertainties and potential liabilities associated with the 2017/2018 Wildfire/Mudslide Events, and the reform of policies allocating liability to investor-owned utilities for damages caused by catastrophic wildfires substantially caused by utility equipment. 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 $1.2 billion of tax effected net operating loss and tax credit carryforwards at December 31, 2018 (after offsetting $178 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. The net operating loss and tax credit carryforwards at December 31, 2017 reflected the impact of Tax Reform, which reduced the valuation of net operating loss carryforwards, but did not affect the amount of future taxable income that may be offset. Tax Reform also limited the utilization of NOLs arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward and places limitations on the ability of regulated utilities to qualify for immediate expensing of certain capital expenditures. Tax Reform did not impact the valuation of tax credit carryforwards, which directly offset taxes due. As a result of the forgoing, Edison International expects to realize its NOL and tax credit carryforward position through 2024.

22




Historical Cash Flows
SCE
(in millions)
2018
 
20171
 
20161
Net cash provided by operating activities
$
3,191

 
$
3,735

 
$
3,521

Net cash provided by (used in) financing activities
616

 
243

 
(219
)
Net cash used in investing activities
(4,300
)
 
(3,503
)
 
(3,294
)
Net (decrease) increase in cash, cash equivalents, and restricted cash
$
(493
)
 
$
475

 
$
8

1 
Net cash for the years ended December 31, 2017 and 2016 was updated to reflect the implementation of the accounting standards updates for cash flows related to cash receipts and restricted cash. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."
Net Cash 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 2018, 2017 and 2016.
 
Years ended December 31,
 
Change in cash flows
(in millions)
2018
20174
20164
 
2018/2017
2017/2016
Net (loss) income
$
(189
)
$
1,136

$
1,499

 

 
Non-cash items1
1,291

3,058

2,117

 
 
 
    Subtotal
$
1,102

$
4,194

$
3,616

 
$
(3,092
)
$
578

Changes in cash flow resulting from working capital2
(313
)
(148
)
243

 
(165
)
(391
)
Regulatory assets and liabilities, net
(92
)
4

(292
)
 
(96
)
296

Other noncurrent assets and liabilities, net3
2,494

(315
)
(46
)
 
2,809

(269
)
Net cash provided by operating activities
$
3,191

$
3,735

$
3,521

 
$
(544
)
$
214

1 
Non-cash items include depreciation and amortization, allowance for equity during construction, impairment and other, deferred income taxes and investment tax credits 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 an increase of $4.7 billion in liabilities for wildfire-related claims and an increase of $2.0 billion in insurance receivables in 2018 (offset in net loss above), and nuclear decommissioning trusts. See "Nuclear Decommissioning Activities" below for further information.
4 
Cash flow for the years ended December 31, 2017 and 2016 was updated to reflect the implementation of the accounting standards updates for cash flows related to cash receipts and restricted cash. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."
Net cash provided by operating activities was impacted by the following:
Net income and non-cash items decreased in 2018 by $3.1 billion from 2017 and increased in 2017 by $578 million from 2016. Excluding the $2.5 billion charge for wildfire-related claims, net of expected recoveries from insurance and FERC customers, the decrease in 2018 was due to the impact of the July 2017 cost of capital decision on GRC revenue, higher operation and maintenance expenses related to wildfire insurance premiums and vegetation management and higher net financing costs, partially offset by higher income tax benefits, and lower non-cash items. The increase in 2017 was primarily due to an increase in revenue from the escalation mechanism set forth in the 2015 GRC decision and lower operation and maintenance expenses, partially offset by higher financing costs, and higher non-cash items. The factors that impacted these items are discussed under "Results of Operations—SCE—Earning Activities." Non-cash items included changes in deferred income taxes and investment tax credits of $(552) million, $304 million and $88 million in 2018, 2017 and 2016, respectively, and impairment and other of $(12) million and $716 million in 2018 and 2017, respectively.
Net cash for working capital was $(313) million, $(148) million and $243 million in 2018, 2017 and 2016, respectively. The net cash for each period was primarily related to timing of disbursements of $(15) million, $125 million and $45 million in

23




2018, 2017 and 2016, respectively, and changes in receivables from customers of $(288) million, $163 million and $220 million in 2018, 2017 and 2016, respectively. Net cash for working capital also included insurance premium payments of $197 million and $121 million in 2018 and 2017, respectively, primarily for wildfire related coverage.
Net cash provided by regulatory assets and liabilities, including changes in (under) over collections of balancing accounts, was $(92) million, $4 million and $(292) million in 2018, 2017 and 2016, 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:
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 wildfire expense memorandum account ("WEMA") to track wildfire related costs including insurance premiums in excess of the amounts that will be ultimately approved in the 2018 GRC decision. For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."
2017
TAMA overcollections increased by $117 million during 2017 primarily due to higher tax repair deductions than forecasted in rates and $135 million of higher benefits recognized for tax accounting method changes, partially offset by a $226 million reclassification from TAMA to BRRBA to refund customers.
Higher cash due to $153 million of overcollections for the public purpose and energy efficiency programs. The increase in cash was due to lower spending than billed to customers and recovery of prior year undercollections.
Higher cash due to $136 million of overcollections related to FERC balancing accounts. The increase in cash was due to recovery of prior FERC undercollections and lower costs than previously forecasted.
Higher cash due to proceeds of approximately $34 million from the Department of Energy related to spent nuclear fuel. For further information on the spent nuclear fuel, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Spent Nuclear Fuel."
BRRBA overcollections decreased by $226 million during 2017 primarily due to the refunds of 2015 TAMA overcollections, a revenue refund to customers of $133 million for 2012 – 2014 incremental tax benefits related to repair deductions, and 2015 overcollections resulting from the implementation of the 2015 GRC decision, which was authorized to be refunded to customers over a two year period, partially offset by a $226 million reclassification from TAMA to BRRBA to refund customers in January 2018 as discussed above.
Net undercollections for ERRA and the new system generation program were $267 million at December 31, 2017 compared to net overcollections of $26 million at December 31, 2016. Lower cash due to $293 million of net undercollections in 2017 primarily due to a refund of prior year overcollections and an increase in costs due to higher than forecasted power and gas prices experienced in 2017 and higher load requirements than forecasted in rates.

24




2016
Lower cash due to a decrease in ERRA overcollections for fuel and purchased power of $419 million in 2016 primarily due to the implementation of the 2016 ERRA rate decrease in January 2016, partially offset by lower than forecasted power and gas prices experienced in 2016.
The public purpose and energy efficiency programs track differences between amounts authorized by the CPUC and amounts incurred to fund programs established by the CPUC. Overcollections increased by $309 million in 2016 due to higher funding and lower spending for these programs.
SCE had a decrease in cash of approximately $182 million primarily due to a 2016 refund of 2015 overcollections resulting from the implementation of the 2015 GRC decision which was authorized to be refunded to customers over a two year period.
Cash flows used in other noncurrent assets and liabilities were primarily related to net earnings from nuclear decommissioning trust investments ($41 million, $55 million and $45 million in 2018, 2017 and 2016, respectively) and SCE's payments of decommissioning costs ($140 million, $236 million and $168 million in 2018, 2017 and 2016, respectively). See "Nuclear Decommissioning Activities" below for further discussion.
Net Cash Provided by (Used in) Financing Activities
The following table summarizes cash provided by (used in) financing activities for 2018, 2017 and 2016. Issuances of debt and preference stock are discussed in "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "—Note 13. Preferred and Preference Stock of Utility."
(in millions)
2018
 
2017
 
2016
Issuances of first and refunding mortgage bonds, net of (discount) premium and issuance costs
$
2,692

 
$
1,011

 
$

Issuance of term loan

 
300

 

Remarketing and issuances of pollution control bonds, net of issuance costs

 
134

 

Long-term debt matured or repurchased
(639
)
 
(882
)
 
(217
)
Issuances of preference stock, net of issuance costs

 
462

 
294

Redemptions of preference stock

 
(475
)
 
(125
)
Short-term debt (repayments), net of borrowings and discount
(520
)
 
469

 
719

Payments of common stock dividends to Edison International
(788
)
 
(573
)
 
(701
)
Payments of preferred and preference stock dividends
(121
)
 
(124
)
 
(123
)
Other
(8
)
 
(79
)
 
(66
)
Net cash provided by (used in) financing activities
$
616

 
$
243

 
$
(219
)
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 $4.5 billion for 2018, $3.8 billion for 2017 and $3.6 billion for 2016, primarily related to transmission and generation investments. SCE had a net redemption of nuclear decommissioning trust investments of $109 million, $197 million and $179 million in 2018, 2017 and 2016, respectively. See "Nuclear Decommissioning Activities" below for further discussion. In addition, during 2018, 2017 and 2016, SCE received proceeds of $38 million, $26 million and $140 million, respectively, for loans on cash surrender value of life insurance policies. The proceeds were used for general corporate purposes.

25




Nuclear Decommissioning Activities
SCE's statement of cash flows includes nuclear decommissioning activities, which are reflected in the following line items:
(in millions)
2018
 
2017
 
2016
Net cash used in operating activities:
   Net earnings from nuclear decommissioning trust investments
$
41

 
$
55

 
$
45

SCE's decommissioning costs
(140
)
 
(236
)
 
(168
)
Net cash provided by investing activities:
   Proceeds from sale of investments
4,340

 
5,239

 
3,212

   Purchases of investments
(4,231
)
 
(5,042
)
 
(3,033
)
Net cash impact
$
10

 
$
16

 
$
56

Net cash used in operating activities relate to interest and dividends less administrative expenses, taxes, and SCE's decommissioning costs. See "Notes to Consolidated Financial Statements—Note 10. Investments" for further information. 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 ($140 million, $236 million and $168 million in 2018, 2017 and 2016, respectively) and reimbursements to SCE from the nuclear decommissioning trust ($150 million, $252 million and $224 million in 2018, 2017 and 2016, respectively). The 2016 net cash impact included reimbursements for 2016 and a portion of 2015, 2014, and 2013 decommissioning costs.
Edison International Parent and Other
The table below sets forth condensed historical cash flow from operations for Edison International Parent and Other.
(in millions)
2018
 
20171
 
20161
Net cash used in operating activities
$
(14
)
 
$
(138
)
 
$
(267
)
Net cash (used in) provided by financing activities
(534
)
 
764

 
314

Net cash provided by (used in) investing activities
61

 
(83
)
 
(109
)
Net (decrease) increase in cash, cash equivalents and restricted cash
$
(487
)
 
$
543

 
$
(62
)
1 
Net cash for the years ended 2017 and 2016 was updated to reflect the implementation of the accounting standards updates for cash flows related to cash receipts and restricted cash. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."
Net Cash Used in Operating Activities
Net cash used in operating activities decreased in 2018 by $124 million from 2017 and decreased in 2017 by $129 million from 2016 due to:
$92 million, $138 million and $32 million cash outflow from operating activities in 2018, 2017 and 2016, respectively, due to payments and receipts relating to interest and operating costs. In addition, the cash outflow in 2017 included higher pension payments related to executive retirement plans.
$78 million inflow in 2018 primarily related to federal income tax refunds.
$214 million of cash payments made to the Reorganization Trust in September 2016 related to the EME Settlement Agreement.

26




Net Cash (Used in) Provided by Financing Activities
Net cash (used in) provided by financing activities were as follows:
(in millions)
 
2018
 
2017
 
2016
Dividends paid to Edison International common shareholders
 
$
(788
)
 
$
(707
)
 
$
(626
)
Dividends received from SCE
 
788

 
573

 
701

Payment for stock-based compensation, net of receipt from stock option exercises
 
(10
)
 
(140
)
 
(51
)
Long-term debt issuance, net of discount and issuance costs
 
545

 
788

 
397

Long-term debt repayments
 
(15
)
 
(403
)
 
(3
)
Short-term debt (repayments), net of borrowings and discount
 
(1,091
)
 
615

 
(108
)
Other
 
37

 
38

 
4

Net cash (used in) provided by financing activities
 
$
(534
)
 
$
764

 
$
314

Net Cash Provided by (Used in) Investing Activities
Net cash provided by (used in) investing activities includes a cash inflow of $78 million from the sale of SoCore Energy in 2018 and Edison Energy Group's capital expenditures primarily for commercial solar installations ($16 million, $88 million and $101 million in 2018, 2017 and 2016, respectively).
Contractual Obligations and Contingencies
Contractual Obligations
Edison International Parent and Other and SCE's contractual obligations as of December 31, 2018, for the years 2019 through 2023 and thereafter are estimated below.
(in millions)
Total
 
Less than
1 year
 
1 to 3 years
 
3 to 5 years
 
More than
5 years
SCE:
 
 
 
 
 
 
 
 
 
Long-term debt maturities and interest1
$
23,510

 
$
652

 
$
2,228

 
$
2,312

 
$
18,318

Power purchase agreements:2
36,189

 
2,562

 
5,172

 
4,600

 
23,855

Other operating lease obligations3
234

 
41

 
56

 
37

 
100

Purchase obligations:4
 
 
 
 
 
 
 
 
 
Other contractual obligations
480

 
79

 
113

 
79

 
209

Total SCE5,6,7,8
$
60,413

 
$
3,334

 
$
7,569

 
$
7,028

 
$
42,482

Edison International Parent and Other:
 
 
 
 
 
 
 
 
 
Long-term debt maturities and interest1
2,055

 
53

 
491

 
866

 
645

   Other operating lease obligations
6

 
1

 
2

 
2

 
1

Total Edison International Parent and Other5
$
2,061

 
$
54

 
$
493

 
$
868

 
$
646

Total Edison International6,7,8
$
62,474

 
$
3,388

 
$
8,062

 
$
7,896

 
$
43,128

1 
For additional details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Amount includes interest payments totaling $10.4 billion and $305 million over applicable period of the debt for SCE and Edison International Parent and Other, respectively.
2 
Certain power purchase agreements entered into with independent power producers are treated as operating or capital leases. For further discussion, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."
3 
At December 31, 2018, SCE's minimum other operating lease payments were primarily related to vehicles, office space and other equipment. For further discussion, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."
4 
For additional details, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies." At December 31, 2018, other commitments were primarily related to maintaining reliability and expanding SCE's transmission and distribution system and nuclear fuel supply contracts.

27




5 
At December 31, 2018, Edison International Parent and Other and SCE had estimated contributions to the pension and PBOP plans. SCE estimated contributions are $80 million, $76 million, $76 million, $88 million and $169 million in 2019, 2020, 2021, 2022 and 2023, respectively, which are excluded from the table above. Edison International Parent and Other estimated contributions are $27 million, $20 million, $26 million, $26 million and $23 million for the same respective periods and are excluded from the table above. These amounts represent estimates that are based on assumptions that are subject to change. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for further information.
6 
At December 31, 2018, Edison International and SCE had a total net liability recorded for uncertain tax positions of $338 million and $249 million, respectively, which is excluded from the table. Edison International and SCE cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the tax authorities.
7 
The contractual obligations table does not include derivative obligations and asset retirement obligations, which are discussed in "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments," and "—Note 1. Summary of Significant Accounting Policies", respectively.
8 
At December 31, 2018, SCE is required to make early termination payments for two amended power purchase agreements. SCE's termination payments are $100 million, $77 million and $29 million in 2019, 2020, and 2021, respectively, which are excluded from the table above. See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies" for further information.
Contingencies
SCE has contingencies related to the 2017/2018 Wildfire/Mudslide Events, wildfire insurance, San Onofre Related Matters, Nuclear Insurance, and Spent Nuclear Fuel, which are discussed in "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies."
Environmental Remediation
For a discussion of SCE's environmental remediation liabilities, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Environmental Remediation."
Off-Balance Sheet Arrangements
SCE has variable interests in power purchase contracts with variable interest entities and a variable interest in unconsolidated Trust II, Trust III, Trust IV, Trust V and Trust VI that issued $400 million (aggregate liquidation preference) of 5.10%, $275 million (aggregate liquidation preference) of 5.75%, $325 million (aggregate liquidation preference) of 5.375%, $300 million (aggregate liquidation preference) of 5.45% and $475 million (aggregate liquidation preference) of 5.00%, trust securities, respectively, to the public, see "Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities."
Environmental Developments
For a discussion of environmental developments, see "Business—Environmental Considerations."
MARKET RISK EXPOSURES
Edison International's and SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Derivative instruments are used to manage market risks including market risks of SCE's customers. For a further discussion of market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments" and "—Note 4. Fair Value Measurements."

28




Interest Rate Risk
Edison International and SCE are exposed to changes in interest rates primarily as a result of its financing, investing and borrowing activities used for liquidity purposes, and to fund business operations and capital investments. The nature and amount of Edison International and SCE's long-term and short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. Fluctuations in interest rates can affect earnings and cash flows. Changes in interest rates may impact SCE's authorized rate of return for the period beyond 2018, see "Business—SCE—Overview of Ratemaking Process" for further discussion. The following table summarizes the increase or decrease to the fair value of long-term debt including the current portion, if the market interest rates were changed while leaving all other assumptions the same:
(in millions)
Carrying Value
 
Fair Value
 
10% Increase
 
10% Decrease
Edison International:
 
 
 
 
 
 
 
December 31, 2018
$
14,711

 
$
14,844

 
$
14,188

 
$
15,556

December 31, 2017
12,123

 
13,760

 
13,239

 
14,308

SCE:
 
 
 
 
 
 
 
December 31, 2018
$
12,971

 
$
13,180

 
$
12,556

 
$
13,858

December 31, 2017
10,907

 
12,547

 
12,039

 
13,082

Commodity Price Risk
SCE and its customers are exposed to the risk of a change in the market price of natural gas, electric power and transmission congestion. SCE's hedging program is designed to reduce exposure to variability in market prices related to SCE's purchases and sales of electric power and natural gas. SCE expects recovery of its related hedging costs through the ERRA balancing account or CPUC-approved procurement plans, and as a result, exposure to commodity price is not expected to impact earnings, but may impact timing of cash flows. As part of this program, SCE enters into energy options, swaps, forward arrangements, and congestion revenue rights ("CRRs"). The transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans.
Fair Value of Derivative Instruments
The fair value of derivative instruments is included in the consolidated balance sheets unless subject to an exception under the applicable accounting guidance. Realized gains and losses from derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, accordingly, changes in SCE's fair value have no impact on earnings. SCE does not use hedge accounting for these transactions due to this regulatory accounting treatment. For further discussion on fair value measurements and the fair value hierarchy, see "Notes to Consolidated Financial StatementsNote 4. Fair Value Measurements."
The fair value of outstanding derivative instruments used to mitigate exposure to commodity price risk was a net asset of $167 million and $109 million at December 31, 2018 and 2017, respectively.
The following table summarizes the increase or decrease to the fair values of the net asset of derivative instruments included in the consolidated balance sheets, if the electricity prices or gas prices were changed while leaving all other assumptions constant:
 
December 31,
(in millions)
2018
2017
Increase in electricity prices by 10%
$
23

$
11

Decrease in electricity prices by 10%
(23
)
(11
)
Increase in gas prices by 10%
2

10

Decrease in gas prices by 10%
(2
)
(5
)

29




Credit Risk
For information related to credit risks, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments."
Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements.
As of December 31, 2018 and 2017, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:
 
December 31, 2018
 
December 31, 2017

(in millions)
Exposure2
 
Collateral
 
Net Exposure
 
Exposure2
 
Collateral
 
Net Exposure
S&P Credit Rating1
 
 
 
 
 
 
 
 
 
 
 
A or higher
$
161

 
$

 
$
161

 
$
110

 
$

 
$
110

A- and BBB+
4

 

 
4

 

 

 

Total
$
165

 
$

 
$
165

 
$
110

 
$

 
$
110

1 
SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the credit ratings from S&P or Moody's. The 2017 credit rating reflects the lower of the ratings from the three major credit rating agencies (S&P, Moody's and Fitch).
2 
Exposure excludes amounts related to contracts classified as normal purchases and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
The accounting policies described below are considered critical to obtaining an understanding of Edison International and SCE's consolidated financial statements because their application requires the use of significant estimates and judgments by management in preparing the consolidated financial statements. Management estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the estimate requires significant assumptions and changes in the estimate or, the use of alternative estimates, could have a material impact on Edison International's results of operations or financial position. For more information on Edison International's accounting policies, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."
Rate Regulated Enterprises
Nature of Estimate Required.    SCE follows the accounting principles for rate-regulated enterprises which are required for entities whose rates are set by regulators at levels intended to recover the estimated costs of providing service, plus a return on net investment, or rate base. Regulators may also impose penalties or grant incentives. Due to timing and other differences in the collection of revenue, these principles allow a cost that would otherwise be charged as an expense by an unregulated entity to be capitalized as a regulatory asset if it is probable that such cost is recoverable through future rates; conversely the principles allow creation of a regulatory liability for amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers. In addition, SCE recognizes revenue and regulatory assets from alternative revenue programs, which enables the utility to adjust future rates in response to past activities or completed events, if certain criteria are met, even for programs that do not qualify for recognition of "traditional" regulatory assets and liabilities.
Accounting principles for rate-regulated enterprises also require recognition of an impairment loss if it becomes probable that the regulated utility will abandon a plant investment, or if it becomes probable that the cost of a recently completed plant will be disallowed, either directly or indirectly, for ratemaking purposes and a reasonable estimate of the amount of the disallowance can be made.


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Key Assumptions and Approach Used.    SCE's management assesses at the end of each reporting period whether regulatory assets are probable of future recovery by considering factors such as the current regulatory environment, the issuance of rate orders on recovery of the specific or a similar incurred cost to SCE or other rate-regulated entities, and other factors that would indicate that the regulator will treat an incurred cost as allowable for ratemaking purposes. Using these factors, management has determined that existing regulatory assets and liabilities are probable of future recovery or settlement. This determination reflects the current regulatory climate and is subject to change in the future. SCE also considers whether any plant investments are probable of abandonment or disallowance.
Effect if Different Assumptions Used.    Significant management judgment is required to evaluate the anticipated recovery of regulatory assets and plant investments, the recognition of incentives and revenue subject to refund, as well as the anticipated cost of regulatory liabilities or penalties. If future recovery of costs ceases to be probable, all or part of the regulatory assets, plant investments and/or liabilities would have to be written off against current period earnings. At December 31, 2018, the consolidated balance sheets included regulatory assets of $6.5 billion and regulatory liabilities of $9.9 billion. If different judgments were reached on recovery of costs and timing of income recognition, SCE's earnings may vary from the amounts reported. SCE has incurred approximately $42 million of capital expenditures related to the Alberhill System Project, including overhead costs, as of December 31, 2018, of which approximately $31 million may not be recoverable if the project is cancelled (refer to "Liquidity and Capital Resources—SCE—Capital Investment Plan").
Application to Tax Reform
As discussed in "Management Overview—Tax Reform," in December 2017, Tax Reform was signed into law. This comprehensive reform of tax law reduces the federal corporate income tax rate from 35% to 21% and is generally effective beginning January 1, 2018. US GAAP requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, at the date of enactment, the deferred taxes were re-measured based upon the new tax rate. The re-measurement of SCE's deferred taxes was recorded against regulatory assets and liabilities when the pre-tax amounts giving rise to deferred tax assets and liabilities were funded by customers and were recorded to earnings when amounts were funded by shareholders.
In the absence of regulatory guidance, judgment is required to estimate which deferred tax re-measurements will be refunded to customers and are subject to change based on the outcome of the regulatory processes. Amounts to be refunded to customers are expected to generally be refunded over the life of the underlying asset or liability that gave rise to the deferred taxes. At December 31, 2017, the implementation of Tax Reform at SCE resulted in a reduction of deferred tax liabilities and an increase in regulatory liabilities of approximately $5.0 billion.
In 2018, SCE made filings with the CPUC and FERC to obtain regulatory guidance to address how to return excess deferred taxes applicable to customers. Changes in the allocation to customers of the deferred tax re-measurement is reflected in the financial statements and is adjusted prospectively as information becomes available through the regulatory process.
Income Taxes
Nature of Estimates Required.    As part of the process of preparing its consolidated financial statements, Edison International and SCE are required to estimate income taxes for each jurisdiction in which they operate. This process involves estimating actual current period tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within Edison International and SCE's consolidated balance sheets, including net operating loss and tax credit carryforwards that can be used to reduce liabilities in future periods.
Edison International and SCE take certain tax positions they believe are in accordance with the applicable tax laws. However, these tax positions are subject to interpretation by the IRS, state tax authorities and the courts. Edison International and SCE determine uncertain tax positions in accordance with the authoritative guidance.
Key Assumptions and Approach Used.    Accounting for tax obligations requires management judgment. Edison International and SCE's management use judgment in determining whether the evidence indicates it is more likely than not, based solely on the technical merits, that a tax position will be sustained, and to determine the amount of tax benefits to be recognized. Judgment is also used in determining the likelihood a tax position will be settled and possible settlement outcomes. In assessing uncertain tax positions Edison International and SCE consider, among others, the following factors: the facts and circumstances of the position, regulations, rulings, and case law, opinions or views of legal counsel and other advisers, and the experience gained from similar tax positions. Edison International and SCE's management evaluates uncertain tax positions at the end of each reporting period and makes adjustments when warranted based on changes in fact or law.

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Effect if Different Assumptions Used.    Actual income taxes may differ from the estimated amounts which could have a significant impact on the liabilities, revenue and expenses recorded in the financial statements. Edison International and SCE continue to be under audit or subject to audit for multiple years in various jurisdictions. Significant judgment is required to determine the tax treatment of particular tax positions that involve interpretations of complex tax laws. Such liabilities are based on judgment and a final determination could take many years from the time the liability is recorded. Furthermore, settlement of tax positions included in open tax years may be resolved by compromises of tax positions based on current factors and business considerations that may result in material adjustments to income taxes previously estimated.
Nuclear Decommissioning – Asset Retirement Obligation
Key Assumptions and Approach Used.    San Onofre Units 1, 2 and 3 decommissioning cost estimates are updated in each NDTCP and when there are material changes to the timing or amount of estimated future cash flows. Palo Verde decommissioning cost estimates are updated by the operating agent, Arizona Public Services, every three years and when there are material changes to the timing or amount of estimated future cash flows. SCE estimates that it will spend approximately $7.2 billion undiscounted through 2079 to decommission its nuclear facilities.
The current ARO estimates for San Onofre and Palo Verde are based on:
Decommissioning Costs. The estimated costs for labor, "material, equipment and other," and low-level radioactive waste costs are included in each of the NRC decommissioning stages; license termination, site restoration, and spent fuel storage. The liability to decommission SCE's nuclear power facilities is based on a 2017 decommissioning study that was filed as part of the 2018 NDTCP for San Onofre Units 1, 2, and 3, with revisions to the cost estimate in 2018 for San Onofre Units 2 and 3 and a 2016 decommissioning study for Palo Verde, with revisions to the cost estimate in 2017. SCE revised the ARO for San Onofre Units 2 and 3 due to increases in decommissioning cost estimates in 2018, related to the impact of operational uncertainties, and in 2017, related to changes to onboarding the general contractor at San Onofre.
Escalation Rates. Annual escalation rates are used to convert the decommissioning cost estimates in base year dollars to decommissioning cost estimates in future-year dollars. Escalation rates are primarily used for labor, material, equipment, and low-level radioactive waste burial costs. SCE's current estimates are based upon SCE's decommissioning cost methodology used for ratemaking purposes. Average escalation rates range from 2.2% to 7.5% (depending on the cost element) annually.
Timing. Cost estimates for Palo Verde are based on an assumption that decommissioning will commence promptly after the current NRC operating licenses expire. The Palo Verde 1, 2, 3 operating licenses currently expire in 2045, 2046 and 2047, respectively. Initial decommissioning activities at San Onofre Unit 1 started in 1999 and at Units 2 and 3 in 2013. Cost estimates for San Onofre Units are currently based on completion of decommissioning activities by 2051.
Spent Fuel Dry Storage Costs. Cost estimates are based on an assumption that the DOE will begin to take spent fuel from the nuclear industry in 2028, and will remove the last spent fuel from the San Onofre and Palo Verde sites by 2049 and 2078, respectively.
Changes in Decommissioning Technology, Regulation, and Economics. The current cost studies assume the use of current technologies under current regulations and at current cost levels.
See "Liquidity and Capital Resources—SCE—Decommissioning of San Onofre" for further discussion of the plans for decommissioning of San Onofre.
Effect if Different Assumptions Used.   The ARO for decommissioning SCE's nuclear facilities was $2.8 billion as of December 31, 2018, based on the decommissioning studies performed and the subsequent cost estimate updates. Changes in the estimated costs, execution strategy or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission these facilities which could have a material effect on the recorded liability. The spent fuel transfer operations for San Onofre Units 2 and 3 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. SCE cannot predict when fuel transfer operations at San Onofre will recommence.

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The following table illustrates the increase to the ARO liability if the cost escalation rate was adjusted while leaving all other assumptions constant:
(in millions)
Increase to ARO and Regulatory Asset at
December 31, 2018
Uniform increase in escalation rate of 1 percentage point
$
578

The increase in the ARO liability driven by an increase in the escalation rate would result in a decrease in the regulatory liability for recoveries in excess of ARO liabilities.
Pensions and Postretirement Benefits Other than Pensions
Nature of Estimate Required.    Authoritative accounting guidance requires companies to recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets and liabilities in the balance sheet; the assets and/or liabilities are normally offset through other comprehensive income (loss). In accordance with authoritative guidance for rate-regulated enterprises, regulatory assets and liabilities are recorded instead of charges and credits to other comprehensive income (loss) for its postretirement benefit plans that are recoverable in utility rates. Edison International and SCE have a fiscal year-end measurement date for all of its postretirement plans.
Key Assumptions of Approach Used.    Pension and other postretirement benefit obligations and the related effects on results of operations are calculated using actuarial models. Two critical assumptions, discount rate and expected return on assets, are important elements of plan expense, and the discount rate is important to liability measurement. Additionally, health care cost trend rates are critical assumptions for postretirement health care plans. These critical assumptions are evaluated at least annually. Other assumptions, which require management judgment, such as rate of compensation increases and rates of retirement and turnover, are evaluated periodically and updated to reflect actual experience.
As of December 31, 2018, Edison International's and SCE's pension plans had a $3.9 billion and $3.4 billion benefit obligation, respectively, and total 2018 expense for these plans was $65 million and $61 million, respectively. As of December 31, 2018, the benefit obligation for both Edison International's and SCE's PBOP plans were $2.0 billion, and total 2018 expense for Edison International's and SCE's plans was $19 million and $18 million, respectively. Annual contributions made to most of SCE's pension plans are currently recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the related annual expense.
Pension expense is recorded for SCE based on the amount funded to the trusts, as calculated using an actuarial method required for ratemaking purposes, in which the impact of market volatility on plan assets is recognized in earnings on a more gradual basis. Any difference between pension expense calculated in accordance with ratemaking methods and pension expense calculated in accordance with authoritative accounting guidance for pension is accumulated as a regulatory asset or liability, and is expected, over time, to be recovered from or returned to customers. As of December 31, 2018, this cumulative difference amounted to a regulatory asset of $107 million, meaning that the accounting method has recognized more in expense than the ratemaking method since implementation of authoritative guidance for employers' accounting for pensions in 1987.
Edison International and SCE used the following critical assumptions to determine expense for pension and other postretirement benefit for 2018:
(in millions)
Pension
Plans
Postretirement
Benefits Other
than Pensions
Discount rate1
3.46
%
3.70
%
Expected long-term return on plan assets2
6.50
%
5.30
%
Assumed health care cost trend rates3
*

6.75
%
* 
Not applicable to pension plans.
1 
The discount rate enables Edison International and SCE to state expected future cash flows at a present value on the measurement date. Edison International and SCE select its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. The AON-Hewitt yield curve is considered in determining the discount rate.

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2 
To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns on plan assets. A portion of PBOP trusts asset returns are subject to taxation, so the 5.3% rate of return on plan assets above is determined on an after-tax basis. Actual time-weighted, annualized (losses) returns on the pension plan assets were (2.4)%, 5.9% and 10.1% for the one-year, five-year and ten-year periods ended December 31, 2018, respectively. Actual time-weighted, annualized (losses) returns on the PBOP plan assets were (4.78)%, 4.86% and 9.2% over these same periods. Accounting principles provide that differences between expected and actual returns are recognized over the average future service of employees.
3 
The health care cost trend rate gradually declines to 5.0% for 2029 and beyond.
As of December 31, 2018, Edison International and SCE had unrecognized pension costs of $353 million and $288 million, and unrecognized PBOP gains of $184 million and $185 million, respectively. The unrecognized pension costs and PBOP gains primarily consisted of the cumulative impact of the reduced discount rates on the respective benefit obligations and the cumulative difference between the expected and actual rate of return on plan assets. Of these deferred costs (gains), $271 million of SCE's pension costs and $(185) million of SCE's PBOP gains are recorded as regulatory assets and regulatory liabilities, respectively, and are expected to be recovered (refunded) over the average expected future service of employees.
Edison International's and SCE's pension and PBOP plans are subject to limits established for federal tax deductibility. SCE funds its pension and PBOP plans in accordance with amounts allowed by the CPUC. Executive pension plans have no plan assets.
Effect if Different Assumptions Used.    Changes in the estimated costs or timing of pension and other postretirement benefit obligations, or the assumptions and judgments used by management underlying these estimates, could have a material effect on the recorded expenses and liabilities.
The following table summarizes the increase or (decrease) to projected benefit obligation for pension and the accumulated benefit obligation for PBOP if the discount rate were changed while leaving all other assumptions constant:
 
Edison International
 
SCE
(in millions)
Increase in discount rate by 1%
 
Decrease in discount rate by 1%
 
Increase in discount rate by 1%
 
Decrease in discount rate by 1%
Change to projected benefit obligation for pension
$
(342
)
 
$
412

 
$
(306
)
 
$
369

Change to accumulated benefit obligation for PBOP
(261
)
 
300

 
(260
)
 
299

A one percentage point increase in the expected rate of return on pension plan assets would decrease Edison International's and SCE's current year expense by $35 million and $33 million, respectively, and a one percentage point increase in the expected rate of return on PBOP plan assets would decrease both Edison International's and SCE's current year expense by $23 million.
The following table summarizes the increase or (decrease) to accumulated benefit obligation and annual aggregate service and interest costs for PBOP if the health care cost trend rate was changed while leaving all other assumptions constant:
 
Edison International
&