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(Mark One)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2018
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
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Commission
File Number
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Exact Name of Registrant
as specified in its charter
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State or Other Jurisdiction of
Incorporation or Organization
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IRS Employer
Identification Number
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1-9936
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EDISON INTERNATIONAL
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California
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95-4137452
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1-2313
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SOUTHERN CALIFORNIA EDISON COMPANY
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California
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95-1240335
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EDISON INTERNATIONAL
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SOUTHERN CALIFORNIA EDISON COMPANY
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2244 Walnut Grove Avenue
(P.O. Box 976)
Rosemead, California 91770
(Address of principal executive offices)
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2244 Walnut Grove Avenue
(P.O. Box 800)
Rosemead, California 91770
(Address of principal executive offices)
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(626) 302-2222
(Registrant's telephone number, including area code)
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(626) 302-1212
(Registrant's telephone number, including area code)
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Title of each class
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Name of each exchange on which registered
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Edison International:
Common Stock, no par value
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NYSE LLC
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Southern California Edison Company:
Cumulative Preferred Stock
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NYSE American LLC
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4.08% Series, 4.24% Series, 4.32% Series, 4.78% Series
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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.
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Edison International
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o
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Southern California Edison Company
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Common Stock outstanding as of February 26, 2019:
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Edison International
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325,811,206 shares
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Southern California Edison Company
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434,888,104 shares (wholly owned by Edison International)
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SEC Form 10-K Reference Number
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Part II, Item 7
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Part I, Item 1A
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Part II, Item 7A
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Part II, Item 8
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Note 15.
Other Income and Expenses
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Part II, Item 6
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Part II, Item 9A
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Part II, Item 9B
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Part II, Item 9
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Part I, Item 1
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Part I, Item 1B
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Part I, Item 2
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Part I, Item 3
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Montecito Mudslides
Litigation
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Part I, Item 4
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Part III, Item 10
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Part III, Item 10
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Part III, Item 10
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Part III, Item 11
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Part III, Item 12
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Part III, Item 13
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Part III, Item 14
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Part II, Item 5
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Part IV, Item 16
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Part IV, Item 15
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2017/2018 Wildfire/Mudslide Events
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the Thomas Fire, the Montecito Mudslides and the Woolsey Fire, collectively
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AFUDC
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allowance for funds used during construction
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ALJ
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administrative law judge
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ARO(s)
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asset retirement obligation(s)
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Bcf
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billion cubic feet
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bonus depreciation
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Federal tax deduction of a percentage of the qualifying property placed in service during periods permitted under tax laws
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BRRBA
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Base Revenue Requirement Balancing Account
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CAISO
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California Independent System Operator
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CAL FIRE
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California Department of Forestry and Fire Protection
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CCAs
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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
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CPUC
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California Public Utilities Commission
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DERs
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distributed energy resources
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DOE
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U.S. Department of Energy
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DRP
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Distributed Resources Plan
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Edison Energy
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Edison Energy, LLC, a wholly-owned subsidiary of Edison Energy Group that provides energy services to commercial and industrial customers
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Edison Energy Group
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Edison Energy Group, Inc., a wholly-owned subsidiary of Edison International, is a holding company for Edison Energy, LLC
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EME
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Edison Mission Energy
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EME Settlement Agreement
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Settlement Agreement by and among Edison Mission Energy, Edison International and the Consenting Noteholders identified therein, dated February 18, 2014
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Electric Service Provider
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an entity that offers electric power and ancillary services to customers that take final delivery of electric power and do not resell the power
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ERRA
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Energy Resource Recovery Account
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FASB
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Financial Accounting Standards Board
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FERC
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Federal Energy Regulatory Commission
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Fitch
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Fitch Ratings, Inc.
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GAAP
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generally accepted accounting principles
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GHG
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greenhouse gas
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GRC
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general rate case
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GS&RP
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Grid Safety and Resiliency Program
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GWh
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gigawatt-hours
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HLBV
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hypothetical liquidation at book value
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IRS
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Internal Revenue Service
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Joint Proxy Statement
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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
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MD&A
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Management's Discussion and Analysis of Financial Condition and Results
of Operations in this report
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MHI
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Mitsubishi Heavy Industries, Inc. and related companies
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Montecito Mudslides
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mudslides and flooding in Montecito, Santa Barbara County, that occurred in January 2018
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Moody's
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Moody's Investors Service, Inc.
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MW
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megawatts
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MWdc
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megawatts measured for solar projects representing the accumulated peak capacity of all the solar modules
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NDCTP
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Nuclear Decommissioning Cost Triennial Proceeding
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NEIL
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Nuclear Electric Insurance Limited
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NEM
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net energy metering
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NERC
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North American Electric Reliability Corporation
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NOL
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net operating loss
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NRC
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Nuclear Regulatory Commission
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OII
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Order Instituting Investigation
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OII Parties
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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
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Palo Verde
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nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest
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PAO
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CPUC's Public Advocates Office (formerly known as the Office of Ratepayer Advocates or ORA)
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PBOP(s)
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postretirement benefits other than pension(s)
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PCIA
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Power Charge Indifference Adjustment
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PG&E
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Pacific Gas & Electric Company
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Prior San Onofre Settlement Agreement
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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
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Revised San Onofre
Settlement Agreement
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Revised San Onofre OII Settlement Agreement among OII Parties, dated January 30, 2018 and modified on August 2, 2018
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ROE
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return on common equity
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S&P
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Standard & Poor's Financial Services LLC
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San Onofre
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retired nuclear generating facility located in south
San Clemente, California in which SCE holds a 78.21% ownership interest
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SCE
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Southern California Edison Company, a wholly-owned subsidiary of Edison International
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SDG&E
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San Diego Gas & Electric
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SEC
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U.S. Securities and Exchange Commission
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SED
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Safety and Enforcement Division of the CPUC
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SoCalGas
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Southern California Gas Company
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SoCore Energy
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SoCore Energy LLC, a former subsidiary of Edison Energy Group that was sold in April 2018
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TAMA
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Tax Accounting Memorandum Account
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Tax Reform
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Tax Cuts and Jobs Act signed into law on December 22, 2017
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Thomas Fire
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a wind-driven fire that originated in Ventura County in December 2017
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TOU
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Time-Of-Use
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TURN
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The Utility Reform Network
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US EPA
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The U.S. Environmental Protection Agency
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WMP
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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
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Woolsey Fire
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a wind-driven fire that originated in Ventura County in November 2018
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•
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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;
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•
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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;
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•
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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;
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•
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ability of Edison International or SCE to borrow funds and access the bank and capital markets on reasonable terms;
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•
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actions by credit rating agencies to downgrade Edison International or SCE's credit ratings or to place those ratings on negative watch or outlook;
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•
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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;
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•
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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;
|
•
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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;
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•
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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;
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•
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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;
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•
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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;
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•
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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;
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•
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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;
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•
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changes in the fair value of investments and other assets;
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•
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changes in interest rates and rates of inflation, including escalation rates (which may be adjusted by public utility regulators);
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•
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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;
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•
|
availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;
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•
|
cost and availability of labor, equipment and materials;
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•
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potential for penalties or disallowance for non-compliance with applicable laws and regulations; and
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•
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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.
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(in millions)
|
2018
|
|
2017
|
|
2018 vs 2017 Change
|
|
2016
|
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Net (loss) income attributable to Edison International
|
|
|
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Continuing operations
|
|
|
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||||||||
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
|
)
|
|
—
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|
||||
Discontinued operations
|
34
|
|
|
—
|
|
|
34
|
|
|
12
|
|
||||
Total non-core items
|
(1,774
|
)
|
|
(901
|
)
|
|
(873
|
)
|
|
17
|
|
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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
|
|
•
|
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.
|
(in millions)
|
|
2018
|
2019
|
2020
|
Total 2019 – 2020
|
||||||||
Traditional capital expenditures
1
|
|
|
|
|
|
||||||||
Distribution
2
|
|
$
|
3,499
|
|
$
|
3,565
|
|
$
|
3,109
|
|
$
|
6,674
|
|
Transmission
|
|
656
|
|
701
|
|
774
|
|
1,475
|
|
||||
Generation
|
|
208
|
|
211
|
|
201
|
|
412
|
|
||||
Total traditional capital expenditures
1
|
|
$
|
4,363
|
|
$
|
4,477
|
|
$
|
4,084
|
|
$
|
8,561
|
|
Grid modernization capital expenditures
2
|
|
$
|
—
|
|
$
|
—
|
|
$
|
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.
|
(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
|
|
•
|
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.
|
|
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 maintenance
1
|
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 earnings
2
|
|
|
$
|
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."
|
•
|
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—
|
•
|
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.
|
•
|
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
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
|
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
|
)
|
•
|
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.
|
•
|
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.
|
|
|
Moody's
|
Fitch
|
S&P
|
Credit Rating
|
|
A3
|
BBB+
|
BBB
|
Outlook
|
|
Under Review for Downgrade
|
Negative
|
Watch Negative
|
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.
|
(in millions)
|
|
|
||
Collateral posted as of December 31, 2018
1
|
|
$
|
198
|
|
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade
2
|
|
22
|
|
|
Incremental collateral requirements for power procurement contracts resulting from adverse market price movement
3
|
|
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.
|
|
|
Moody's
|
Fitch
|
S&P
|
Credit Rating
|
|
Baa1
|
BBB+
|
BBB
|
Outlook
|
|
Under Review for Downgrade
|
Negative
|
Watch Negative
|
(in millions)
|
2018
|
|
2017
1
|
|
2016
1
|
||||||
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."
|
|
Years ended December 31,
|
|
Change in cash flows
|
|||||||||||||
(in millions)
|
2018
|
2017
4
|
2016
4
|
|
2018/2017
|
2017/2016
|
||||||||||
Net (loss) income
|
$
|
(189
|
)
|
$
|
1,136
|
|
$
|
1,499
|
|
|
|
|
||||
Non-cash items
1
|
1,291
|
|
3,058
|
|
2,117
|
|
|
|
|
|||||||
Subtotal
|
$
|
1,102
|
|
$
|
4,194
|
|
$
|
3,616
|
|
|
$
|
(3,092
|
)
|
$
|
578
|
|
Changes in cash flow resulting from working capital
2
|
(313
|
)
|
(148
|
)
|
243
|
|
|
(165
|
)
|
(391
|
)
|
|||||
Regulatory assets and liabilities, net
|
(92
|
)
|
4
|
|
(292
|
)
|
|
(96
|
)
|
296
|
|
|||||
Other noncurrent assets and liabilities, net
3
|
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."
|
•
|
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."
|
•
|
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.
|
•
|
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.
|
(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
|
)
|
(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
|
|
(in millions)
|
2018
|
|
2017
1
|
|
2016
1
|
||||||
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."
|
•
|
$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.
|
(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
|
|
(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 interest
1
|
$
|
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 obligations
3
|
234
|
|
|
41
|
|
|
56
|
|
|
37
|
|
|
100
|
|
|||||
Purchase obligations:
4
|
|
|
|
|
|
|
|
|
|
||||||||||
Other contractual obligations
|
480
|
|
|
79
|
|
|
113
|
|
|
79
|
|
|
209
|
|
|||||
Total SCE
5,6,7,8
|
$
|
60,413
|
|
|
$
|
3,334
|
|
|
$
|
7,569
|
|
|
$
|
7,028
|
|
|
$
|
42,482
|
|
Edison International Parent and Other:
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt maturities and interest
1
|
2,055
|
|
|
53
|
|
|
491
|
|
|
866
|
|
|
645
|
|
|||||
Other operating lease obligations
|
6
|
|
|
1
|
|
|
2
|
|
|
2
|
|
|
1
|
|
|||||
Total Edison International Parent and Other
5
|
$
|
2,061
|
|
|
$
|
54
|
|
|
$
|
493
|
|
|
$
|
868
|
|
|
$
|
646
|
|
Total Edison International
6,7,8
|
$
|
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.
|
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.
|
(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
|
|
|
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
|
)
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
(in millions)
|
Exposure
2
|
|
Collateral
|
|
Net Exposure
|
|
Exposure
2
|
|
Collateral
|
|
Net Exposure
|
||||||||||||
S&P Credit Rating
1
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
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 o
f
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.
|
•
|
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.
|
(in millions)
|
Increase to ARO and Regulatory Asset at
December 31, 2018
|
||
Uniform increase in escalation rate of 1 percentage point
|
$
|
578
|
|