0000827052 eix:CommonOrCollectiveFundsMember us-gaap:FairValueInputsLevel1Member us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2019-12-31
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K |
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| (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, 20182019 |
o☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | For the transition period from to |
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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 |
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EDISON INTERNATIONAL | | SOUTHERN CALIFORNIA EDISON COMPANY |
2244 Walnut Grove Avenue | | | | | | | | | EDISON INTERNATIONAL | | SOUTHERN CALIFORNIA EDISON COMPANY | | 2244 Walnut Grove Avenue | | 2244 Walnut Grove Avenue | | (P.O. Box 976) | | (P.O. Box 800) | | Rosemead, | California | 91770 | | Rosemead, | California | 91770 | | (Address of principal executive offices) | | (Address of principal executive offices) | | (626) | 302-2222 | | | (626) | 302-1212 | | | (Registrant's telephone number, including area code) | | (Registrant's telephone number, including area code) |
(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)
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(626) 302-2222
(Registrant's telephone number, including area code)
| | (626) 302-1212
(Registrant's telephone number, including area code)
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| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| Common Stock, no par value | EIX | NYSE | LLC |
Southern California Edison Company:
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| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Edison International: Common Stock, no par value
| | NYSE LLC |
Southern California Edison Company:Cumulative Preferred Stock,
4.08% Series | SCEpB | NYSE American LLC |
4.08% Series,Cumulative Preferred Stock, 4.24% Series | SCEpC | NYSE American LLC |
| Cumulative Preferred Stock, 4.32% Series | SCEpD | NYSE American LLC
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| Cumulative Preferred Stock, 4.78% Series | SCEpE | NYSE American LLC
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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 Yesþ☑ No o☐Southern California Edison Company Yesþ☑ 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☐Noþ☑Southern California Edison Company Yes o☐Noþ☑
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 Yesþ☑ No o☐Southern California Edison Company Yesþ☑ 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 Yesþ☑ No o☐Southern California Edison Company Yesþ☑ 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 þSouthern California Edison Company þ |
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| 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 Filerþ | Accelerated Filero | Non-accelerated Filero | Smaller Reporting Companyo | Emerging growth companyo |
| ☑ | ☐ | ☐ | ☐ | ☐ |
| Southern California Edison Company | Large Accelerated Filero | Accelerated Filero | Non-accelerated Filerþ | Smaller Reporting Companyo | Emerging growth companyo |
| ☐ | ☐ | ☑ | ☐ | ☐ |
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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. |
| 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, 2018,28, 2019, the last business day of the most recently completed second fiscal quarter:
Edison International Approximately $20.6$22.0 billion Southern California Edison Company Wholly owned by Edison International |
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| Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: |
Common Stock outstanding as of February 26, 2019: | 20, 2020: | |
| Edison International | | 325,811,206 362,570,075 |
| shares |
| Southern California Edison Company | | 434,888,104 |
| shares (wholly owned by Edison International) |
DOCUMENTS INCORPORATED BY REFERENCE
Designated portions of the Proxy Statement relating to registrants' joint 20192020 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.
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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 I, Item 1A |
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| | Part II, Item 7A |
| | Part II, Item 8 |
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| | Part II, Item 6 |
| | Part II, Item 9A |
| | Part II, Item 9B |
| | Part II, Item 9 |
| | Part I, Item 1 |
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| | Part I, Item 1B |
| | Part I, Item 2 |
| | Part I, Item 31 |
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| | Part I, Item 1B |
| | Part I, Item 2 |
| | Part I, Item 3 |
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| | Part I, Item 4 |
| | Part I |
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| | 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 |
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| | Part IV, Item 16 |
| | Part IV, Item 15 |
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This is a combined Form 10-K separately filed by Edison International and Southern California Edison Company. Information contained herein relating to an individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.
GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
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| 2017/2018 Wildfire/Mudslide Events | | the Thomas Fire, the Koenigstein Fire, the Montecito Mudslides and the Woolsey Fire, collectively |
AFUDCAB 1054 | | allowance for funds used during constructionCalifornia Assembly Bill 1054, executed by the Governor of California on July 12, 2019 |
ALJAB 1054 Liability Cap | | administrative law judgeIf the insurance fund allowed under AB 1054 is established, and subject to certain other conditions, a cap on the aggregate requirement to reimburse the insurance fund over a trailing three calendar year period equal to 20% of the equity portion of the utility’s transmission and distribution rate base in the year of the prudency determination |
| ARO(s) | | asset retirement obligation(s) |
| Bcf | | billion cubic feet |
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 |
| CSRP | | Customer Service Re-platform, a SCE project to implement a new customer service system |
| 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 advises and provides energy servicessolutions to commercial and industrial customerslarge energy users |
| Edison Energy Group | | Edison Energy Group, Inc., a wholly-owned subsidiary of Edison International, is a holding company for Edison Energy, LLCsubsidiaries engaged in competitive businesses that provide energy services to commercial and industrial customers |
| 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 retail customers, that take final delivery of electric powerother than electrical corporations (like SCE) and do not resell the power
CCAs |
| ERRA | | Energy Resource Recovery Account |
FASB | | Financial Accounting Standards Board |
| FERC | | Federal Energy Regulatory Commission |
| FERC 2018 Settlement Period | | January 1, 2018 through November 11, 2019 |
| FHPMA | | Fire Hazard Prevention Memorandum Account |
| Fitch | | Fitch Ratings, Inc. |
| GAAP | | generally accepted accounting principles |
| GHG | | greenhouse gas |
| GRC | | general rate case |
| GS&RP | | Grid Safety and Resiliency Program |
| GWh | | gigawatt-hours |
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, 201923, 2020 |
| Koenigstein Fire | | a wind-driven fire that originated near Koenigstein Road in the City of Santa Paula in Ventura County on December 4, 2017 |
| kV | | unit of electrical potential equal to 1000 volts |
| MD&A | | Management's Discussion and Analysis of Financial Condition and Results of Operations in this report |
MHI | | Mitsubishi Heavy Industries, Inc. and related companies |
| Montecito Mudslides | | the 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 |
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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 |
OIIPABA | | 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 AgreementPortfolio Allocation Balancing Account |
| 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
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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 |
| RPS | | Renewables portfolio standard |
| S&P | | Standard & Poor's Financial Services LLC |
| San Onofre | | retired nuclear generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest |
| SCE | | Southern California Edison Company, a wholly-owned subsidiary of Edison International |
| SDG&E | | San Diego Gas & Electric |
| SEC | | U.S. Securities and Exchange Commission |
| SED | | Safety and Enforcement Division of the CPUC |
| SoCalGas | | Southern California Gas Company |
| SoCore Energy | | SoCore Energy LLC, a former subsidiary of Edison Energy Group that was sold in April 2018 |
| TAMA | | Tax Accounting Memorandum Account |
| Tax Reform | | Tax Cuts and Jobs Act signed into law on December 22, 2017 |
| Thomas Fire | | a wind-driven fire that originated in the Anlauf Canyon area Ventura County inon December 4, 2017 |
| TOU | | Time-Of-Use |
TURN | | The Utility Reform Network |
| US EPA | | The U.S. Environmental Protection Agency |
| VCFD | | The Ventura County Fire Department |
| WEMA | | Wildfire Expense Memorandum Account |
| WMP | | a wildfire mitigation plan required to be filed annuallyevery three years under California SenateAssembly Bill 9011054 to describe a utility's plans to construct, operate, and maintain electrical lines and equipment that will help minimize the risk of catastrophic wildfires caused by such electrical lines and equipment |
| Wildfire Insurance Fund | | The insurance fund established pursuant to AB 1054 |
| Woolsey Fire | | a wind-driven fire that originated in Ventura County in November 2018 |
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International's and SCE's current expectations and projections about future events based on Edison International's and SCE's knowledge of present facts and circumstances and assumptions about future events and include any statements that do not directly relate to a historical or current fact. Other information distributed by Edison International and SCE that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact Edison International and SCE, include, but are not limited to the:
ability of SCE to recover its costs through regulated rates, including costs related to uninsured wildfire-related and mudslide-related liabilities, costs incurred to mitigate the risk of utility equipment causing future wildfires and capital spendingcosts incurred prior to formal regulatory approval;implement SCE's new customer service system;
ability of SCE to implement its WMP, including effectively implementing Public Safety Power Shut-Offs when appropriate;
ability to obtain sufficient insurance at a reasonable cost, including insurance relating to SCE's nuclear facilities and wildfire-related claims, and to recover the costs of such insurance or, in the event liabilities exceed insured amounts, the ability to recover uninsured losses from customers or other parties;
risks associated with AB 1054 effectively mitigating the significant risk faced by California investor-owned utilities related to liability for damages arising from catastrophic wildfires where utility facilities are alleged to be a substantial cause, including SCE's ability to maintain a valid safety certification, SCE's ability to recover uninsured wildfire-related costs from the Wildfire Insurance Fund, the longevity of the Wildfire Insurance Fund, and the CPUC's interpretation of and actions under AB 1054, including their interpretation of the new prudency standard established under AB 1054;
decisions and other actions by the CPUC, the FERC, the NRC and other regulatory and legislative authorities, including decisions and actions related to determinations of authorized rates of return or return on equity, the 2018 GRC, the GS&RP application, the recoverability of wildfire-related and mudslide- relatedmudslide-related costs, issuance of SCE's wildfire safety certification, wildfire mitigation efforts, and delays in regulatory and legislative actions;
ability of Edison International or SCE to borrow funds and access 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;
physical security of Edison International's and SCE's critical assets and personnel and the cybersecurity of Edison International's and SCE's critical information technology systems for grid control, and business, employee and customer data;
risks associated with cost allocation resulting in higher rates for utility bundled service customers because of possible customer bypass or departure for other electricity providers such as CCAs and Electric Service Providers;
risks inherent in SCE's transmission and distribution infrastructure investment program, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable acceptance of power delivery), changes in the CAISO's transmission plans, and governmental approvals;
risks associated with the operation of transmission and distribution assets and power generating facilities, including public and employee safety issues, the risk of utility assets causing or contributing to wildfires, failure, availability, efficiency, and output of equipment and facilities, and availability and cost of spare parts;
physical security of
actions by credit rating agencies to downgrade Edison International's andInternational or 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;credit ratings or to place those ratings on negative watch or outlook;
ability of Edison International to develop competitive businesses, manage new business risks, and recover and earn a return on its investment in newly developed or acquired businesses;
changes in tax laws and regulations, at both the state and federal levels, or changes in the application of those laws, that could affect recorded deferred tax assets and liabilities and effective tax rate;
changes in future taxable income, or changes in tax law, that would limit Edison International's and SCE's realization of expected net operating loss and tax credit carryover benefits prior to expiration;
changes in the fair value of investments and other assets;
changes in interest rates and rates of inflation, including escalation rates (which may be adjusted by public utility regulators);
governmental, statutory, regulatory, or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market adopted by the NERC, CAISO, Western Electricity Council, and similar regulatory bodies in adjoining regions;regions, and changes in California's environmental priorities that lessen the importance the state places on GHG reduction;
availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;
cost and availability of labor, equipment and materials;
potential for penalties or disallowance for non-compliance with applicable laws and regulations; and
cost of fuel for generating facilities and related transportation, which could be impacted by, among other things, disruption of natural gas storage facilities, to the extent not recovered through regulated rate cost escalation provisions or balancing accounts.
Additional information about risks and uncertainties, including more detail about the factors described in this report, is contained throughout this report. Readers are urged to read this entire report, including information incorporated by reference, and carefully consider the risks, uncertainties, and other factors that affect Edison International's and SCE's businesses. Forward-looking statements speak only as of the date they are made and neither Edison International nor SCE are obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International and SCE with the SEC. Edison International and SCE post or provide direct links to (i) certain SCE and other parties' regulatory filings and documents with the CPUC and the FERC and certain agency rulings and notices in open proceedings at www.edisoninvestor.com (SCEin a section titled "SCE Regulatory Highlights) so that such filings, rulings and notices are available to all investors. Edison International and SCE post or provide direct links toHighlights," (ii) certain documents and information related to Southern California wildfires which may be of interest to investors at www.edisoninvestor.com (Southernin a section titled "Southern California Wildfires) in order to publicly disseminate such information. Edison InternationalWildfires," and SCE also routinely post or provide direct links to(iii) presentations, documents and other information that may be of interest to investors in a section titled "Events and Presentations" 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion related to the results of operations and changes in financial condition for 2018 compared to 2017 is incorporated by reference to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in Edison International's and SCE's combined Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC in February 2019. MANAGEMENT OVERVIEW
Highlights of Operating Results
Edison International is the parent holding company of SCE and Edison Energy Group. SCE is an investor-owned public utility primarily engaged in the business of supplying and delivering electricity to an approximately 50,000 square mile area of southern California. Edison Energy Group is a holding company for Edison Energy which is engaged in the competitive business of providing energy services to commercial and industrial customers. Edison Energy's business activities are currently not material to report as a separate business segment. References to Edison International refer to the consolidated group of Edison International and its subsidiaries. References to Edison International Parent and Other refer to Edison International Parent and its competitive subsidiaries. Unless otherwise described, all the information contained in this report relates to both filers.
| | | (in millions) | 2018 | | 2017 | | 2018 vs 2017 Change | | 2016 | 2019 | | 2018 | | 2019 vs 2018 Change | | 2017 |
| Net (loss) income attributable to Edison International | | | | | | | | |
| Net income (loss) attributable to Edison International | | | | | | | | |
| Continuing operations | | | | | | | | | | | | | | |
| SCE | $ | (310 | ) | | $ | 1,012 |
| | $ | (1,322 | ) | | $ | 1,376 |
| $ | 1,409 |
| | $ | (310 | ) | | $ | 1,719 |
| | $ | 1,012 |
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| Edison International Parent and Other | (147 | ) | | (447 | ) | | 300 |
| | (77 | ) | (125 | ) | | (147 | ) | | 22 |
| | (447 | ) |
| Discontinued operations | 34 |
| | — |
| | 34 |
| | 12 |
| — |
| | 34 |
| | (34 | ) | | — |
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| Edison International | (423 | ) | | 565 |
| | (988 | ) | | 1,311 |
| 1,284 |
| | (423 | ) | | 1,707 |
| | 565 |
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| Less: Non-core items | | | | | | | | | | | | | | |
| SCE | | | | | | | | | | | | | | |
| Wildfire-related claims, net of recoveries | (1,825 | ) | | — |
| | (1,825 | ) | | — |
| (157 | ) | | (1,825 | ) | | 1,668 |
| | — |
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| Impairment and other | 9 |
| | (448 | ) | | 457 |
| | — |
| (115 | ) | | 9 |
| | (124 | ) | | (448 | ) |
| Wildfire insurance fund expense | | (109 | ) | | — |
| | (109 | ) | | — |
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| Re-measurement of deferred taxes | | 88 |
| | — |
| | 88 |
| | (33 | ) |
| Settlement of 1994 – 2006 California tax audits | | — |
| | 66 |
| | (66 | ) | | — |
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| Edison International Parent and Other | | | | | | | | |
| Goodwill impairment | | (18 | ) | | — |
| | (18 | ) | | — |
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| Sale of SoCore Energy and other | | — |
| | (46 | ) | | 46 |
| | 13 |
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| Settlement of 1994 – 2006 California tax audits | 66 |
| | — |
| | 66 |
| | — |
| — |
| | (12 | ) | | 12 |
| | — |
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| Re-measurement of deferred taxes | — |
| | (33 | ) | | 33 |
| | — |
| — |
| | — |
| | — |
| | (433 | ) |
| Edison International Parent and Other | | | | | | | | |
| Re-measurement of deferred taxes | — |
| | (433 | ) | | 433 |
| | — |
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| Sale of SoCore Energy and other | (46 | ) | | 13 |
| | (59 | ) | | 5 |
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| Settlement of 1994 – 2006 California tax audits | (12 | ) | | — |
| | (12 | ) | | — |
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| Discontinued operations | 34 |
| | — |
| | 34 |
| | 12 |
| — |
| | 34 |
| | (34 | ) | | — |
|
| Total non-core items | (1,774 | ) | | (901 | ) | | (873 | ) | | 17 |
| (311 | ) | | (1,774 | ) | | 1,463 |
| | (901 | ) |
| Core earnings (losses) | | | | | | | | | | | | | | |
| SCE | 1,440 |
| | 1,493 |
| | (53 | ) | | 1,376 |
| 1,702 |
| | 1,440 |
| | 262 |
| | 1,493 |
|
| Edison International Parent and Other | (89 | ) | | (27 | ) | | (62 | ) | | (82 | ) | (107 | ) | | (89 | ) | | (18 | ) | | (27 | ) |
| Edison International | $ | 1,351 |
| | $ | 1,466 |
| | $ | (115 | ) | | $ | 1,294 |
| $ | 1,595 |
| | $ | 1,351 |
| | $ | 244 |
| | $ | 1,466 |
|
Edison International's earnings are prepared in accordance with GAAP. Management uses core earnings (losses) internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the company's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as earnings attributable to Edison International shareholders less non-core
items. Non-core items include income or loss from discontinued operations 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 gainsincome and lossesexpense related to certainchanges in law, outcomes in tax, regulatory or legal settlements or proceedings, and exit activities, including sale of certain assets and other activities that are no longer continuing.
Edison International's 20182019 earnings decreased $988increased $1,707 million, driven by a decreasean increase in SCE's earnings of $1,322$1,719 million partially offset byand a decrease in Edison International Parent and Other losses of $300$22 million, andpartially offset by $34 million of income from discontinued operations.operations in 2018. SCE's lowerhigher net income consisted of $1,269$1,457 million of lower non-core losses and $262 million of higher non-core losses and $53 million of lower core earnings.
The decreaseincrease in core earnings was due to the impactadoption of the July 20172018 GRC final decision in 2019, higher FERC revenue due to the settlement of SCE's 2018 Formula Rate proceeding and rate base growth, and the timing of regulatory deferral and cost recovery of capital decision on GRC revenue, higher operation and maintenance expenses related toincremental wildfire insurance premiums and vegetation management and higher net financing costs,expenses. These increases were partially offset by higher income tax benefits.inspection, preventive maintenance and vegetation management costs that were not deferred as regulatory assets.
Edison International Parent and Other losses from continuing operations for 20182019 consisted of $62$18 million of higher core losses and $362$40 million of lower non-core losses. The increase in core losses in 20182019 was primarily due to higher interest expense and lower 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 andlower losses from the absence of SoCorecompetitive businesses under Edison 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).Group.
Consolidated non-core items for 20182019 and 20172018 for Edison International included:
ChargeCharges of $218 million ($157 million after-tax) in 2019 and $2.5 billion ($1.8 billion after-tax) in 2018 for SCE's wildfire-related claims, net of expected recoveries from insurance and FERC customers.
LossAn impairment charge of $170 million ($123 million after-tax) recorded in 2019 for SCE related to disallowed historical capital expenditures in SCE's 2018 GRC final decision.
A charge of $152 million ($109 million after-tax) recorded in 2019 from the amortization of SCE's contributions to the Wildfire Insurance Fund. See "Notes to Consolidated Financial Statements— Note 12. Commitments and Contingencies" for further information.
| |
| • | Income tax benefit of $88 million recorded in 2019 for SCE related to changes in the allocation of deferred tax re-measurement between customers and shareholders as a result of a CPUC resolution issued in February 2019. The resolution determined that customers are only entitled to excess deferred taxes which were included when setting rates and other deferred tax re-measurements belong to shareholders. |
An impairment charge of $25 million ($18 million after-tax) in 2019 for Edison Energy following a goodwill assessment.
A loss of $56 million ($46 million after-tax) in 2018 for Edison International Parent and Other primarily related to sale of SoCore Energy in April 2018 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."2018.
Income of $12 million ($9 million after-tax) in 2018 and charge of $716 million ($448 million after-tax) in 2017 for SCE relateddue to the elimination of the GHG Reduction Funding Program as a result of the Revised San Onofre Order Instituting Investigation Settlement Agreement. For further information, see "—Permanent Retirement of San Onofre" below.Agreement among SCE, SDG&E and various intervening parties, dated January 30, 2018 and modified on August 2, 2018.
Income tax expense of $12 million, an income tax benefit of $66 million and an income tax benefit of $34 million inThe 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.
Chargeswhich resulted in income tax expense of $433$12 million in 2017 for Edison International Parent and Other and $33income tax benefits of $66 million and $34 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.discontinued operations, respectively.
See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations.
Wildfire Mitigation and Wildfire Insurance Expenses
In response to the increase in wildfire activity, and faster progression of and increased damage from wildfires across SCE's service territory and throughout California, SCE is currently incurring wildfire mitigation and wildfire insurance related spending at levels significantly exceeding amounts authorized in its 2018 GRC. Several regulatory mechanisms, including but not limited to the GS&RP memorandum account, the FHPMA, the WMP memorandum account and the WEMA, exist to allow SCE to track and seek recovery of these incremental costs. In accordance with the accounting standards applicable to rate-regulated enterprises, SCE defers costs as regulatory assets that are probable of future recovery from customers and has recorded regulatory assets for these incremental costs. As of December 31, 2019, SCE has recognized $400 million of regulatory assets related to incremental wildfire mitigation expenses and $341 million of regulatory assets related to incremental wildfire insurance expenses. While SCE believes such costs are probable of future recovery, there is no assurance that SCE will collect all amounts currently deferred as regulatory assets. SCE has recorded a further $754 million of wildfire mitigation capital expenditures that could be subject to reasonableness review through the GS&RP and separate tracks of the 2021 GRC proceeding.
Grid Safety and Resiliency Program
In September 2018, SCE filed an application with the CPUC requesting approval of a GS&RP to implement additional wildfire safety measures, including measures to further harden SCE's infrastructure to significantly reduce potential fire ignition sources, bolster SCE's situational awareness capabilities to more fully assess and respond to potential wildfire conditions, and enhance SCE's operational practices to further strengthen fire safety measures and system resiliency. In its GS&RP application, SCE proposed to spend approximately $582 million ($407 million capital) in 2018 dollars between 2018 and 2020 in excess of amounts authorized in SCE's 2018 GRC and requested a balancing account to recover the incremental costs of implementing the program. In January 2019, the CPUC approved the establishment of an interim memorandum account to track GS&RP costs while the CPUC considers SCE's application. There is no assurance that SCE will be allowed to ultimately recover these costs.
In July 2019, SCE and certain parties to SCE's GS&RP proceeding submitted a motion to the CPUC requesting approval of a settlement agreement. If the CPUC approves the settlement agreement, SCE will be authorized to spend approximately $526 million ($407 million capital) in 2018 dollars between 2018 and 2020. If approved by the CPUC, SCE will include the authorized revenue requirement in rates and establish a balancing account to track the difference between actual GS&RP costs and amounts authorized. If spending is less than authorized, SCE will refund those amounts to customers. If spending is in excess of forecasted amounts, or in excess of 115% of forecasted amounts for certain activities, SCE will present those costs for reasonableness review in a later track of the 2021 GRC.
GS&RP capital expenditures for 2019 and 2018 were $370 million and $49 million, respectively. Forecasted GS&RP capital expenditures for 2020 are $564 million excluding capitalized indirect costs. In 2019, $37 million of expenses were recorded to the interim memorandum account.
Wildfire Mitigation Plans
Under AB 1054, SCE is required to submit a wildfire mitigation plan to the CPUC annually for review and approval. SCE's WMPs describe strategies, programs and activities that are in place, being implemented or are under development by SCE, including associated cost estimates, to proactively address and mitigate the threat of electrical infrastructure-associated ignitions that could lead to wildfires. Beginning in 2020, each WMP is required to cover at least a three-year period.
SCE filed its 2019 and 2020 WMPs with the CPUC in February 2019 and February 2020, respectively. Many, but not all, of the programs and activities described in SCE's 2019 and 2020 WMPs are part of SCE's 2018 and 2021 GRC requests or GS&RP application. As required by the CPUC, SCE's 2020 WMP includes updates in the areas of inspection and maintenance, vegetation management, system hardening, and situational awareness.
In May 2019, the CPUC approved SCE's 2019 WMP, however, such approval does not authorize the associated spending. The CPUC decision required SCE to meet certain reporting requirements, capture data, and improve its metrics for evaluating performance. During 2019 SCE recorded $307 million of expenses in the WMP memorandum account. During 2019, WMP capital expenditures not authorized in the 2018 GRC or contemplated in the GS&RP proceedings were $335 million. Forecasted 2020 WMP direct costs not authorized in the 2018 GRC or contemplated in the GS&RP proceedings are $557 million, of which $244 million is capital.
The WMP memorandum account will be subject to a subsequent reasonableness review through separate tracks of the 2021 GRC.
Fire Hazard Prevention Memorandum Account
The FHPMA was established to record the costs incurred related to fire hazard prevention in compliance with decisions from the CPUC. SCE has used the FHPMA to track incremental vegetation management activities to reduce the risk of fires. As of December 31, 2019, operation and maintenance expenses of $198 million have been recorded to the FHPMA.
The FHPMA is expected to be subject to a subsequent reasonableness review through separate tracks of the 2021 GRC.
Wildfire Expense Memorandum Account
SCE tracks insurance premium costs related to wildfire liability insurance policies as well as other wildfire-related costs in its WEMA. In July 2019, SCE filed a WEMA application with the CPUC to seek recovery of $478 million in wildfire insurance premium costs incurred in excess of premiums approved in the 2018 GRC. As of December 31, 2019, SCE has recognized $341 million of regulatory assets in the WEMA related to incremental wildfire insurance costs.
2018 General Rate Case
In May 2019, the CPUC approved a final decision in SCE's GRC proceeding, for the three-year period 2018 – 2020, is pending. SCE has requestedGRC. The final decision authorized a revenue requirement of $5.534$5.1 billion for its test2018 and identified changes to certain balancing accounts, including the expansion of the TAMA to include the impacts of all differences between forecast and recorded tax expense. The final decision also disallowed certain historical spending, largely related to specific pole replacements the CPUC determined were performed prematurely.
The final decision allows a post-test year of 2018, a $106 million decrease from the 2017 GRC authorized revenue requirement,rate making mechanism that escalates capital additions by 2.49% for both 2019 and revenue requirements2020. It also allows operation and maintenance expenses to be escalated for the post-test years of 2019 and 2020 through the use of $5.965various escalation factors for labor, non-labor and medical expenses. The methodology set forth in the final decision results in a revenue requirement of $5.5 billion in 2019 and $6.468$5.9 billion respectively.in 2020.
InThe revenue requirements in the absence of a 2018 GRC final 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 ofare retroactive to January 1, 2018 and January 1, 2019, respectively.
2018. SCE accounts for regulatory decisions inrecorded the discreteprior period in which they are received and, accordingly, will record the impact of the 2018 GRC final decision whenin 2019, including an increase to core earnings of $131 million from the application of the decision to revenue, depreciation expense and income tax expense and a non-core impairment of utility property, plant and equipment of $170 million ($123 million after-tax) related to disallowed historical capital expenditures. See "Results of Operations—SCE" and "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies" for further information.
2020 Cost of Capital Application
In April 2019, SCE filed an application with the CPUC for authority to establish its authorized cost of capital for utility operations for a three-year term, beginning January 1, 2020. In December 2019, the CPUC issued a final decision increasing the common equity component of SCE's capital structure from its current authorized level of 48% to 52% in 2020 and correspondingly reducing its preferred equity component from 9% to 5%. The final decision maintains SCE's CPUC ROE for the three-year period beginning January 1, 2020 at 10.3%.Under the decision, SCE's annual cost of capital adjustment mechanism also remains unchanged. Under the final decision, SCE's 2020 authorized cost of long-term debt and preferred equity are 4.74% and 5.70%, respectively. Based on the approved capital structure and costs, SCE's weighted average return on rate base for 2020 will be 7.68%.
Based on the revenue requirement approved in SCE's 2018 GRC, SCE’s cost of capital and capital structure approved in the final decision will result in a projected revenue requirement increase in 2020 of approximately $38 million from revenue currently included in CPUC electric rates of $5.9 billion.
2018 and 2019 FERC Formula Rate
In December 2019, the FERC approved a settlement on SCE's formula rates for the 2018 Formula Rate case that established SCE's FERC transmission revenue requirement for the FERC 2018 Settlement Period. The settlement provides for a weighted average ROE of 11.2%, which includes a previously authorized 50 basis point incentive for CAISO participation and individual and previously authorized project incentives. Under the settlement, if the FERC issues a final, unappealable ruling that finds SCE is not eligible for the 50 basis point incentive for CAISO participation, then the ROE for the FERC 2018 Settlement Period will be reduced to 10.7%. Prior to the settlement, SCE had been recognizing revenue during the FERC 2018 Settlement Period based on its expectations of the outcome of the 2018 Formula Rate case. Regulatory assets and liabilities were adjusted based on the settlement of the 2018 Formula Rate case, which resulted in an increase in net income of $29 million related to 2018, being recorded in 2019. The transmission revenue requirement and rates that have been billed to customers for the FERC 2018 Settlement Period were based on a total FERC weighted average ROE of 11.58%, and SCE expects to refund excess amounts billed to customers during 2020. In the 2019 Formula Rate case, SCE's requested base
return on equity, as modified by a partial settlement approved by the FERC, is 11.97% ("FERC Base ROE"). This ROE request reflects a conventional ROE of 11.12% and an additional ROE of 0.85% to compensate investors for current wildfire risk. As with SCE's requested ROE in its 2020 CPUC Cost of Capital proceeding, this request reflects the anticipated impact of AB 1054 on SCE's requested ROE. SCE's total ROE request, inclusive of project incentives and a 0.5% incentive for CAISO participation, would be approximately 13.25%. The 2019 Formula Rate was implemented in rates in November 2019 and remains subject to hearing and settlement procedures. Amounts billed to customers under the 2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved.
In November 2019, the FERC issued a decision is received. SCE cannot predictin a pending Midcontinent Independent System Operator Transmission Owners ("MISO TO") proceeding which significantly revised the revenue requirementsmethodology used to determine MISO TO's just and reasonable ROE levels by restricting the valuation methodologies that would be recognized by the FERC in establishing a zone of reasonableness for ROE. The decision also reiterated that authorized ROE, including FERC-authorized project incentives, could not exceed the established zone of reasonableness. The updated methodology led to an authorized ROE for MISO TO of 9.88%, compared to their previously authorized ROE of 12.38%. Numerous parties requested rehearing of the MISO decision on various grounds and, in January 2020, the FERC granted rehearing requests for the limited purpose of allowing the FERC additional time for consideration of the concerns raised.
In December 2019, the CPUC will authorize or provide assurance onfiled a protest with the timingFERC alleging that $419 million of a final decision.costs associated with SCE's Tehachapi Transmission Project are imprudent and should be disallowed from SCE's FERC rate base because these costs exceeded the maximum reasonable costs identified by the CPUC when it granted the project’s certificate of public convenience and necessity. The CPUC requested that the FERC set this issue for hearings and consolidate the protest with the settlement proceedings of the 2019 Formula Rate case.
Southern California Wildfires and Mudslides
Approximately 35% of SCE's service territory is in areas identified as high fire risk by SCE. Multiple factors have contributed to increased wildfires,wildfire activity, and 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. SCE has determined that approximately 27% of its service territory is in areas identified as high fire risk.
In December 2017 and November 2018,Over the past several years, wind-driven wildfires impacted portions of SCE's service territory, with wildfires in December 2017 and November 2018 causing loss of life, substantial damage to both residential and business properties, and service outages for SCE customers. In 2019, several wind-driven wildfires originated in Southern California. SCE does not expect any of these 2019 fires to have a material adverse effect on its financial condition, results of operations or cash flows.
Edison International and SCE recorded a charge of $255 million as of December 31, 2019 for wildfire-related claims, net of expected insurance recoveries. The 2019 charge consists of an increase in estimated losses for claims related to the 2017/2018 Wildfire/Mudslide Events of $232 million, against which SCE has recorded expected recoveries through FERC electric rates of $14 million. The resulting charge was $218 million ($157 million after-tax). The fourth quarter 2019 charge also includes $23 million ($17 million after-tax) of expenses primarily associated with self-insured retention for fires that occurred in Southern California in 2019.
2017/2018 Wildfire/Mudslide Events
The investigating government agencies, the VCFD and CAL FIRE, have determined that the largest of the 2017 fires knownoriginated on December 4, 2017, in the Anlauf Canyon area of Ventura County (the investigating agencies refer to this fire as the Thomas Fire, originated in Ventura County and"Thomas Fire"), followed shortly thereafter by the Koenigstein Fire. While the progression of these two fires remains under review, the December 4, 2017 fires eventually burned substantial acreage located in both Ventura and Santa Barbara Counties. The largest of the November 2018 fires, known as the Woolsey Fire, originated in Ventura County and burned acreage in both Ventura and Los Angeles Counties. According to
In March 2019, the VCFD and CAL FIRE information,jointly issued separate reports finding that the Thomas Fire burned over 280,000 acres, destroyed an estimated 1,063 structures, damaged an estimated 280 structures and resultedthe Koenigstein Fire were each caused by SCE equipment. At this time, based on available information, SCE has not determined whether its equipment caused the Thomas Fire. Based on publicly available radar data showing a smoke plume in two fatalities, whilethe Anlauf Canyon area emerging in advance of the start time of the Thomas Fire indicated in the Thomas Fire report, SCE believes that the Thomas Fire started at least 12 minutes prior to any issue involving SCE's system and at least 15 minutes prior to the start time indicated in the report. SCE has previously disclosed that SCE believed its equipment was associated with the ignition
of the Koenigstein Fire. SCE is continuing to assess the progression of the Thomas and Koenigstein Fires and the extent of damages that may be attributable to each fire.
SCE has received a non-final redacted draft of a report from the VCFD subject to a protective order in the litigation related to the Woolsey Fire burned almost 100,000 acres, destroyed an estimated 1,643 structures, damaged an estimated 364 structuresfire and, resultedother than the information disclosed in three fatalities.this Form 10-K, is not authorized to release the report or its contents to the public at this time. The draft report states that the VCFD investigation team determined that electrical equipment owned and operated by SCE was the cause of the Woolsey Fire. Absent additional evidence, SCE believes that it is likely that its equipment was associated with the ignition of the Woolsey Fire.
Multiple lawsuits related to the Thomas Fireand Koenigstein Fires and the Woolsey Fire have been initiated against SCE and Edison International. Some of the Thomas Fire-relatedand Koenigstein Fires lawsuits claim that SCE and Edison International have responsibility for the damages caused by the Montecito Mudslides based on a theory alleging that SCE has responsibility for the Thomas Fireand/or Koenigstein Fires and that the Thomas Fireand/or Koenigstein Fires 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.
InvestigationsSCE's internal review into the causesfacts and circumstances of each of the 2017/2018 Wildfire/Mudslide Events areis ongoing, and finalSCE expects to obtain and review additional information and materials in the possession of third parties during the course of its internal reviews and the litigation processes.Final determinations of liability for the Thomas Fire, the Koenigstein Fire, the Montecito Mudslides and the Woolsey Fire (each a "2017/2018 Wildfire/Mudslide Event," and, collectively, the "2017/2018 Wildfire/Mudslide Events"), including determinations of whether SCE was negligent, would only be made during lengthy and complex litigation processes. Even when investigations are still pending or liability is disputed, an assessment of likely outcomes, including through future settlement of disputed claims, may require a chargeliability 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 Eventsinformation available to SCE and consideration of the risks associated with litigation, Edison International and SCE expect to incur a material loss in connection with the 2017/2018 Wildfire/Mudslide Events and have accrued a charge, before recoveries and taxes, of $4.7 billion inEvents.
In the fourth quarter of 2018. This charge2018, SCE recorded a liability for estimated losses of $4.7 billion related to the 2017/2018 Wildfire/Mudslide Events. In the fourth quarter of 2019, SCE paid $360 million to a number of local public entities to resolve those parties' collective claims arising from the 2017/2018 Wildfire/Mudslide Events (the "Local Public Entity Settlements"). After the Local Public Entity Settlements, the liability accrued for estimated losses as of December 31, 2019 was reduced by the $360 million paid in the Local Public Entity Settlements.
Each reporting period, management reviews its loss estimates for remaining alleged and potential claims related to the 2017/2018 Wildfire/Mudslide Events. The process for estimating losses associated with wildfire litigation claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including, but not limited to: estimates of known and expected claims by third parties based on currently available information, opinions of counsel regarding litigation risk, the status of and developments in the course of litigation, and prior experience litigating and settling wildfire litigation claims. While the low end of the reasonably estimated range of expected losses for the 2017/2018 Wildfire/Mudslide Events is estimated on an aggregate basis, some of the factors evaluated by management in connection with its fourth quarter 2019 review contributed to a significant increase in certain loss estimates, while others contributed to a significant decrease in certain other loss estimates. The net result of management's fourth quarter 2019 review was an increase in estimated losses of $232 million for total estimated losses of $4.5 billion as of December 31, 2019 for unpaid claims related to the 2017/2018 Wildfire Mudslide Events. The accrued liability as of December 31, 2019 corresponds to the lower end of the reasonably estimated range of expected 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 quarterAs of 2018,December 31, 2019, Edison International and SCE also recordedhave remaining expected recoveries from insurance of $2.0$1.7 billion and expected recoveries through FERC electric rates of $135$149 million which ison their consolidated balance sheets related to the FERC portion of the $4.7 billion charge it accrued. The net charge to earnings recorded was $1.8 billion after-tax.2017/2018 Wildfire/Mudslide Events. SCE believes that, in light of the CPUC's decision in a cost recovery proceedingsproceeding involving SDG&E arising from aseveral 2007 wildfirewildfires 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.proceedings for fires ignited prior to July 12, 2019. Accordingly, while the CPUC has not made a determination regarding SCE's prudency relative to any of the 2017/2018 Wildfire/Mudslide Events, SCE is unable to conclude, at this time, that uninsured CPUC-jurisdictional wildfire-related costs are probable of recovery through electric rates.
Edison International and SCE continue to pursue legislative, regulatory and legal strategies, and anticipate pursuing legislative strategies in the longer term, to address the application of a strict liability standard to wildfire-related property damages without the guaranteed ability to recover resulting costs in electric rates. However,
2019 Wildfire Legislation
In July 2019, AB 1054 was signed by the Governor of California and became effective immediately. The summary of the wildfire legislation in this report is based on SCE's interpretation of the legislation and is qualified in its entirety by, and should be read together with, AB 1054 and companion Assembly Bill 111.
Wildfire Insurance Fund
AB 1054 provided for the Wildfire Insurance Fund to reimburse utilities for payment of third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1.0 billion or the utility's insurance coverage. The Wildfire Insurance Fund was established in September 2019 when both SCE and SDG&E made their initial contributions to the fund. The Wildfire Insurance Fund is available for claims related to wildfires ignited after July 12, 2019 that are determined to have been caused by a utility by the responsible government investigatory agency.
SCE and SDG&E have collectively made their initial contributions totaling approximately $2.7 billion to the Wildfire Insurance Fund. While PG&E has committed to make an initial contribution of approximately $4.8 billion to the Wildfire Insurance Fund upon emergence from bankruptcy, its participation in, and contributions to the fund are subject to it resolving its bankruptcy proceeding and meeting certain other conditions prior to June 30, 2020. SCE, SDG&E and PG&E are also collectively expected to make aggregate contributions of $3.0 billion to the Wildfire Insurance Fund through annual contributions to the fund over a 10-year period, of which SCE and SDG&E have made their initial annual contributions totaling approximately $107 million. If PG&E is unable to participate in the Wildfire Insurance Fund, then SCE and SDG&E are collectively expected to make aggregate contributions of approximately $1.0 billion to the fund through annual contributions over the 10-year period. In addition to PG&E's, SCE's and SDG&E's contributions to the Wildfire Insurance Fund, $13.5 billion is expected to be collected over a 15-year period from their ratepayers through a dedicated rate component. The amount collected from ratepayers may be directly contributed to the Wildfire Insurance Fund or used to support the issuance of up to $10.5 billion in bonds by the California Department of Water Resources, the proceeds of which would be contributed to the fund. In addition to funding contributions to the Wildfire Insurance Fund, the amount collected from utility ratepayers will pay for, among other things, any interest and financing costs related to any bonds that are issued by the California Department of Water Resources to support the contributions to the Wildfire Insurance Fund. Based on a decision adopted by the CPUC in October 2019 in the Order Instituting Rulemaking to Consider Authorization of a Non-Bypassable Charge to Support the Wildfire Insurance Fund, PG&E's ratepayers will not be required to contribute to the fund if PG&E does not participate in the Wildfire Insurance Fund. In that case, $7.5 billion will be collected from SCE's and SDG&E's ratepayers through the dedicated rate component to support a contribution to the Wildfire Insurance Fund.
SCE made an initial contribution of approximately $2.4 billion to the Wildfire Insurance Fund in September 2019 and has committed to make ten annual contributions of approximately $95 million per year to the fund, by no later than January 1 of each year. SCE made its first annual contribution to the Wildfire Insurance Fund in December 2019. Edison International andsupported SCE's initial contribution to the Wildfire Insurance Fund by raising $1.2 billion from the issuance of Edison International equity. SCE cannot predict whether or when thereraised the remaining $1.2 billion from the issuance of long-term debt. SCE's contributions to the Wildfire Insurance Fund will not be recoverable through electric rates and will be a comprehensive solution mitigatingexcluded from the significant risk faced by Californiameasurement of SCE's CPUC-jurisdictional authorized capital structure. SCE will also not be entitled to cost recovery for any borrowing costs incurred in connection with its contributions to the Wildfire Insurance Fund.
Participating investor-owned utilities will be reimbursed from the Wildfire Insurance Fund for eligible claims, subject to the fund administrator's review, and will be required to reimburse the fund for withdrawn amounts that the CPUC disallows subject, in some instances, to the AB 1054 Liability Cap. A utility will not be eligible for the AB 1054 Liability Cap if it does not maintain a valid safety certification or its actions or inactions that resulted in the wildfire are found to constitute conscious or willful disregard of the rights and safety of others. On July 25, 2019, SCE obtained its initial safety certification that will be valid for twelve months. Based on SCE's 2020 rate base and assuming the equity portion of SCE's capital structure is 52% (SCE's CPUC authorized capital structure), SCE's requirement to reimburse the Wildfire Insurance Fund for eligible claims disallowed in 2020 would be capped at approximately $3.0 billion. SCE will not be allowed to recover borrowing costs incurred to reimburse the fund for amounts that the CPUC disallows. The Wildfire Insurance Fund and, consequently, the AB 1054 Liability Cap will terminate when the administrator determines that the fund has been exhausted.
AB 1054 Prudency Standard
As a result of the establishment of the Wildfire Insurance Fund, AB 1054 created a new standard that the CPUC must apply when assessing the prudency of a utility in connection with a request for recovery of wildfire costs for wildfires ignited after July 12, 2019. Under AB 1054, the CPUC is required to find a utility to be prudent if the utility's conduct related to wildfires.the ignition was consistent with actions that a reasonable utility would have undertaken under similar circumstances, at the
relevant point in time, and based on the information available at that time. Utilities with a valid safety certification will be presumed to have acted prudently related to a wildfire ignition unless a party in the cost recovery proceeding creates serious doubt as to the reasonableness of the utility's conduct, at which time, the burden shifts back to the utility to prove its conduct was reasonable. If a utility does not have a valid safety certification, it will have the burden to prove, based on a preponderance of evidence, that its conduct was prudent. The new prudency standard will survive the termination of the Wildfire Insurance Fund.
Utilities participating in the Wildfire Insurance Fund that are found to be prudent are not required to reimburse the fund for amounts withdrawn from the fund and can recover wildfire costs through electric rates if the fund has been exhausted.
Capital Expenditure Requirement
Under AB 1054, approximately $1.6 billion spent by SCE on wildfire risk mitigation capital expenditures made after August 1, 2019 cannot be included in the equity portion of SCE's rate base. SCE can apply for an irrevocable order from the CPUC to finance these capital expenditures, including through the issuance of securitized bonds, and can recover any prudently incurred financing costs. SCE expects to finance this capital requirement by issuing securitized bonds.
For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Initial and annual contributions to the wildfire insurance fund established pursuant to California Assembly Bill 1054," "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" and "Legal Proceedings."
2021 General Rate Case
Permanent RetirementIn August 2019, SCE filed its 2021 GRC application for the three-year period 2021-2023. Following amendments and other revisions to the application in November 2019 and February 2020, SCE’s 2021 revenue requirement is $7.6 billion. SCE's request excludes the revenue requirement associated with the approximately $1.6 billion in wildfire risk mitigation capital expenditures that SCE will exclude from the equity portion of San Onofrerate base as required under AB 1054.
An ongoing CPUC OII proceeding regardingIn the steam generator replacement project at San Onofre andamendment of February 2020, SCE removed its CSRP implementation costs from the related outages and subsequent shutdown of San Onofre was resolved in 2018 through2021 GRC. SCE will continue to track the executioncost of the Revised San Onofre Settlement Agreement. In connection withCSRP program in a memorandum account previously approved in the Revised San Onofre Settlement Agreement,2018 GRC 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 implementationreview of the Revised San Onofre Settlement Agreement. InCSRP implementation costs will be deferred to a future application to the CPUC.
The 2021 revenue requirement represents an increase of $1.1 billion over the 2020 revenue requirement authorized in the 2018 GRC and updated for anticipated post test-year ratemaking changes. Including the impact of anticipated lower kilowatt-hour sales in 2021 and one-time memorandum account recoveries, this represents an 11.4% increase over 2020 rates. SCE's 2021 GRC request also includes proposed revenue requirement increases of $423 million in 2022 and $514 million in 2023. The updated revenue requirements were requested based on the ROE and capital structure authorized at the time of the initial filing. A new capital structure has since been authorized. See "—2020 Cost of Capital Application."
SCE's requested increase to its revenue requirement in the 2021 GRC application is largely due to SCE's efforts to reduce wildfire risk. Certain of SCE's key wildfire mitigation forecast expenditures are subject to significant potential volatility. As a result, SCE has proposed establishing two-way balancing accounts for wildfire mitigation-related enhanced vegetation management, inspection activities and grid hardening, as well as for insurance premiums.
The capital programs requested in SCE's 2021 GRC include the infrastructure and programs necessary to implement California's ambitious public policy goals, including wildfire mitigation, de-carbonization of the economy through electrification and integration of distributed energy resources across a rapidly modernizing grid. See "—Capital Program" for further details.
The schedule established in the proceeding includes CPUC issuance of a proposed decision in the fourth quarter of 2017,2020, or during the first quarter of 2021. If the final decision is issued in 2021, SCE incurred a charge of $716 million ($448 million after-tax)will, consistent with CPUC practice in prior GRCs, request the CPUC to adjust regulatory assets and liabilities based onissue an order directing that the probable approval ofauthorized revenue requirement changes be effective January 1, 2021.
Historically, the Revised San Onofre Settlement Agreement and to recordCPUC has set an accrued liability of $143 millionannual revenue requirement for the estimated present value ofbase year and then set the obligation due to SDG&E underremaining two years by a methodology established in the Utility Shareholder Agreement.
GRC proceeding. In July 2018,January 2020, the CPUC approved all of the terms of the Revised San Onofre Settlement Agreement other than a provision under which SCE agreedchange from a triennial GRC cycle to fund $10 milliona quadrennial GRC cycle 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 regulatedlarge energy utilities such as SCE. Edison International expects it will be exemptSCE is required to file an amendment to its application for the three-year period 2021 – 2023 to add an attrition year for 2024. The timing of the amendment is subject to further direction from the new interest disallowance provisions under de-minimis rules issued by the IRS in 2018.CPUC.
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."
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 vehiclesGrid Safety 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.
CapitalResiliency 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, including measures to further harden SCE's infrastructure to significantly reduce potential fire ignition sources, bolster SCE's situational awareness capabilities to more fully assess and respond to potential wildfire conditions, and enhance SCE's operational practices to further strengthen fire safety measures and system resiliency. In its GS&RP application, SCE proposed to spend approximately $582 million ($407 million capital) in 2018 dollars between 2018 and 2020 in excess of amounts authorized in SCE's 2018 GRC and requested a balancing account to recover the incremental costs of implementing the program. In January 2019, the CPUC authorizedapproved the establishment of an interim memorandum account to track incremental GS&RP expenditures. costs while the CPUC considers SCE's application. There is no assurance that SCE will be allowed to ultimately recover these costs.
In FebruaryJuly 2019, SCE and certain parties to SCE's GS&RP proceeding submitted a motion to the CPUC requesting approval of a settlement agreement. If the CPUC approves the settlement agreement, SCE will be authorized to spend approximately $526 million ($407 million capital) in 2018 dollars between 2018 and 2020. If approved by the CPUC, SCE will include the authorized revenue requirement in rates and establish a balancing account to track the difference between actual GS&RP costs and amounts authorized. If spending is less than authorized, SCE will refund those amounts to customers. If spending is in excess of forecasted amounts, or in excess of 115% of forecasted amounts for certain activities, SCE will present those costs for reasonableness review in a later track of the 2021 GRC.
GS&RP capital expenditures for 2019 and 2018 were $370 million and $49 million, respectively. Forecasted GS&RP capital expenditures for 2020 are $564 million excluding capitalized indirect costs. In 2019, $37 million of expenses were recorded to the interim memorandum account.
Wildfire Mitigation Plans
Under AB 1054, SCE is required to submit a wildfire mitigation plan to the CPUC annually for review and approval. SCE's WMPs describe strategies, programs and activities that are in place, being implemented or are under development by SCE, including associated cost estimates, to proactively address and mitigate the threat of electrical infrastructure-associated ignitions that could lead to wildfires. Beginning in 2020, each WMP is required to cover at least a three-year period.
SCE filed its 2019 WMPand 2020 WMPs with the CPUC.CPUC in February 2019 and February 2020, respectively. Many, but not all, of the programs and activities described in SCE's 2019 and 2020 WMPs are part of SCE's 2018 and 2021 GRC requests or GS&RP application. As required by the CPUC, SCE's 2020 WMP includes updates in the areas of inspection and maintenance, vegetation management, system hardening, and situational awareness.
In May 2019, the CPUC approved SCE's 2019 WMP, however, such approval does not authorize the associated spending. The table below reflectsCPUC decision required SCE to meet certain reporting requirements, capture data, and improve its metrics for evaluating performance. During 2019 SCE recorded $307 million of expenses in the WMP memorandum account. During 2019, WMP capital expenditures 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 spendingnot authorized in the 2018 GRC to maximizeor contemplated in the wildfire mitigation efforts. FERC jurisdictional capital expendituresGS&RP proceedings were $335 million. Forecasted 2020 WMP direct costs not authorized in the 2018 GRC or contemplated in the GS&RP proceedings are based on management's expectations. Forecasted expenditures for FERC capital projects are$557 million, of which $244 million is capital.
The WMP memorandum account will be subject to change due to timelinessa subsequent reasonableness review through separate tracks 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.2021 GRC.
Fire Hazard Prevention Memorandum Account
The CPUCFHPMA was established to record the costs incurred related to fire hazard prevention in compliance with decisions from the CPUC. SCE has approved 81%, 89%,used the FHPMA to track incremental vegetation management activities to reduce the risk of fires. As of December 31, 2019, operation and 92%maintenance expenses of $198 million have been recorded to the FHPMA.
The FHPMA is expected to be subject to a subsequent reasonableness review through separate tracks of the traditional capital expenditures requested2021 GRC.
Wildfire Expense Memorandum Account
SCE tracks insurance premium costs related to wildfire liability insurance policies as well as other wildfire-related costs in its WEMA. In July 2019, SCE filed a WEMA application with the 2009, 2012, and 2015 GRC decisions, respectively. While SCE cannot predict the levelCPUC to seek recovery of traditional capital spending that will be$478 million in wildfire insurance premium costs incurred in excess of premiums approved in the 2018 GRCGRC. As of December 31, 2019, SCE has recognized $341 million of regulatory assets in the WEMA related to incremental wildfire insurance costs.
2018 General Rate Case
In May 2019, the CPUC approved a final decision management is not awarein SCE's 2018 GRC. The final decision authorized a revenue requirement of factors$5.1 billion for 2018 and identified changes to certain balancing accounts, including the expansion of the TAMA to include the impacts of all differences between forecast and recorded tax expense. The final decision also disallowed certain historical spending, largely related to specific pole replacements the CPUC determined were performed prematurely.
The final decision allows a post-test year rate making mechanism that would cause the percentage of SCE's request that is approvedescalates capital additions by 2.49% for both 2019 and 2020. It also allows operation and maintenance expenses to be materially different from what has been approvedescalated for 2019 and 2020 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology set forth in recent GRC decisions. SCE does not have prior approval experience with grid modernization capital expendituresthe final decision results in a revenue requirement of $5.5 billion in 2019 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."$5.9 billion in 2020.
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. |
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 requestedrevenue requirements 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 fromfinal decision are retroactive to January 1, 2018. SCE recorded the amounts requested inprior period impact of the 2018 GRC that may be includedfinal decision in 2019, including an increase to core earnings of $131 million from the application of the decision to revenue, depreciation expense and income tax expense and a final decision.non-core impairment of utility property, plant and equipment of $170 million ($123 million after-tax) related to disallowed historical capital expenditures. See "Results of Operations—SCE" and "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies" for further information.
Medium- and Heavy-Duty Vehicle Transportation Electrification2020 Cost of Capital Application
In January 2017,April 2019, SCE filed an application with the CPUC requesting approvalfor authority to establish its authorized cost 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 proposedcapital for utility operations for 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.three-year term, beginning January 1, 2020. In January 2018,December 2019, the CPUC issued a final decision approving five pilot projectsincreasing the common equity component of SCE's capital structure from its current authorized level of 48% to 52% in 2020 and correspondingly reducing its preferred equity component from 9% to 5%. The final decision maintains SCE's CPUC ROE for the three-year period beginning January 1, 2020 at 10.3%.Under the decision, SCE's annual cost of capital adjustment mechanism also remains unchanged. Under the final decision, SCE's 2020 authorized cost of long-term debt and preferred equity are 4.74% and 5.70%, respectively. Based on the approved capital structure and costs, SCE's weighted average return on rate base for 2020 will be 7.68%.
Based on the revenue requirement approved in SCE's 2018 GRC, SCE’s cost of capital and capital structure approved in the final decision will result in a projected revenue requirement increase in 2020 of approximately $38 million from revenue currently included in CPUC electric rates of $5.9 billion.
2018 and 2019 FERC Formula Rate
In December 2019, the FERC approved a settlement on SCE's formula rates for the 2018 Formula Rate case that established SCE's FERC transmission revenue requirement for the FERC 2018 Settlement Period. The settlement provides for a weighted average ROE of 11.2%, which includes a previously authorized 50 basis point incentive for CAISO participation and individual and previously authorized project incentives. Under the settlement, if the FERC issues a final, unappealable ruling that finds SCE is not eligible for the 50 basis point incentive for CAISO participation, then the ROE for the FERC 2018 Settlement Period will be reduced to 10.7%. Prior to the settlement, SCE had been recognizing revenue during the FERC 2018 Settlement Period based on its expectations of the outcome of the 2018 Formula Rate case. Regulatory assets and liabilities were adjusted based on the settlement of the 2018 Formula Rate case, which resulted in an increase in net income of $29 million related to 2018, being recorded in 2019. The transmission revenue requirement and rates that have been billed to customers for the FERC 2018 Settlement Period were based on a total FERC weighted average ROE of 11.58%, and SCE expects to refund excess amounts billed to customers during 2020. In the 2019 Formula Rate case, SCE's requested base
return on equity, as modified by a partial settlement approved by the FERC, is 11.97% ("FERC Base ROE"). This ROE request reflects a conventional ROE of 11.12% and an additional ROE of 0.85% to compensate investors for current wildfire risk. As with SCE's requested ROE in its 2020 CPUC Cost of Capital proceeding, this request reflects the anticipated impact of AB 1054 on SCE's requested ROE. SCE's total ROE request, inclusive of project incentives and a budget0.5% incentive for CAISO participation, would be approximately 13.25%. The 2019 Formula Rate was implemented in rates in November 2019 and remains subject to hearing and settlement procedures. Amounts billed to customers under the 2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved.
In November 2019, the FERC issued a decision in a pending Midcontinent Independent System Operator Transmission Owners ("MISO TO") proceeding which significantly revised the methodology used to determine MISO TO's just and reasonable ROE levels by restricting the valuation methodologies that would be recognized by the FERC in establishing a zone of $16 million ($10 million capital)reasonableness for ROE. The decision also reiterated that authorized ROE, including FERC-authorized project incentives, could not exceed the established zone of reasonableness. The updated methodology led to an authorized ROE for MISO TO of 9.88%, compared to their previously authorized ROE of 12.38%. Numerous parties requested rehearing of the MISO decision on various grounds and, in 2016 dollars. January 2020, the FERC granted rehearing requests for the limited purpose of allowing the FERC additional time for consideration of the concerns raised.
In May 2018,December 2019, the CPUC filed a protest with the FERC alleging that $419 million of costs associated with SCE's Tehachapi Transmission Project are imprudent and should be disallowed from SCE's FERC rate base because these costs exceeded the maximum reasonable costs identified by the CPUC when it granted the project’s certificate of public convenience and necessity. The CPUC requested that the FERC set this issue for hearings and consolidate the protest with the settlement proceedings of the 2019 Formula Rate case.
Southern California Wildfires and Mudslides
Multiple factors have contributed to increased wildfire activity, and faster progression of and increased damage from wildfires across SCE's service territory and throughout California. These include the buildup of dry vegetation in areas severely impacted by years of historic drought, lack of adequate clearing of hazardous fuels by responsible parties, higher temperatures, lower humidity, and strong Santa Ana winds. At the same time that wildfire risk has been increasing in Southern California, residential and commercial development has occurred and is occurring in some of the highest-risk areas. Such factors can increase the likelihood and extent of wildfires. SCE has determined that approximately 27% of its service territory is in areas identified as high fire risk.
Over the past several years, wind-driven wildfires impacted portions of SCE's service territory, with wildfires in December 2017 and November 2018 causing loss of life, substantial damage to both residential and business properties, and service outages for SCE customers. In 2019, several wind-driven wildfires originated in Southern California. SCE does not expect any of these 2019 fires to have a material adverse effect on its financial condition, results of operations or cash flows.
Edison International and SCE recorded a charge of $255 million as of December 31, 2019 for wildfire-related claims, net of expected insurance recoveries. The 2019 charge consists of an increase in estimated losses for claims related to the 2017/2018 Wildfire/Mudslide Events of $232 million, against which SCE has recorded expected recoveries through FERC electric rates of $14 million. The resulting charge was $218 million ($157 million after-tax). The fourth quarter 2019 charge also includes $23 million ($17 million after-tax) of expenses primarily associated with self-insured retention for fires that occurred in Southern California in 2019.
2017/2018 Wildfire/Mudslide Events
The investigating government agencies, the VCFD and CAL FIRE, have determined that the largest of the 2017 fires originated on December 4, 2017, in the Anlauf Canyon area of Ventura County (the investigating agencies refer to this fire as the "Thomas Fire"), followed shortly thereafter by the Koenigstein Fire. While the progression of these two fires remains under review, the December 4, 2017 fires eventually burned substantial acreage in both Ventura and Santa Barbara Counties. The largest of the November 2018 fires, known as the Woolsey Fire, originated in Ventura County and burned acreage in both Ventura and Los Angeles Counties.
In March 2019, the VCFD and CAL FIRE jointly issued separate reports finding that the Thomas Fire and the Koenigstein Fire were each caused by SCE equipment. At this time, based on available information, SCE has not determined whether its equipment caused the Thomas Fire. Based on publicly available radar data showing a finalsmoke plume in the Anlauf Canyon area emerging in advance of the start time of the Thomas Fire indicated in the Thomas Fire report, SCE believes that the Thomas Fire started at least 12 minutes prior to any issue involving SCE's system and at least 15 minutes prior to the start time indicated in the report. SCE has previously disclosed that SCE believed its equipment was associated with the ignition
of the Koenigstein Fire. SCE is continuing to assess the progression of the Thomas and Koenigstein Fires and the extent of damages that may be attributable to each fire.
SCE has received a non-final redacted draft of a report from the VCFD subject to a protective order in the litigation related to the Woolsey fire and, other than the information disclosed in this Form 10-K, is not authorized to release the report or its contents to the public at this time. The draft report states that the VCFD investigation team determined that electrical equipment owned and operated by SCE was the cause of the Woolsey Fire. Absent additional evidence, SCE believes that it is likely that its equipment was associated with the ignition of the Woolsey Fire.
Multiple lawsuits related to the Thomas and Koenigstein Fires and the Woolsey Fire have been initiated against SCE and Edison International. Some of the Thomas and Koenigstein Fires lawsuits claim that SCE and Edison International have responsibility for the damages caused by the Montecito Mudslides based on a theory alleging that SCE has responsibility for the Thomas and/or Koenigstein Fires and that the Thomas and/or Koenigstein Fires proximately caused the Montecito Mudslides.
SCE's internal review into the facts and circumstances of each of the 2017/2018 Wildfire/Mudslide Events is ongoing, and SCE expects to obtain and review additional information and materials in the possession of third parties during the course of its internal reviews and the litigation processes.Final determinations of liability for the Thomas Fire, the Koenigstein Fire, the Montecito Mudslides and the Woolsey Fire (each a "2017/2018 Wildfire/Mudslide Event," and, collectively, the "2017/2018 Wildfire/Mudslide Events"), including determinations of whether SCE was negligent, would only be made during lengthy and complex litigation processes. Even when investigations are still pending or liability is disputed, an assessment of likely outcomes, including through future settlement of disputed claims, may require a liability to be accrued under accounting standards. Based on information available to SCE and consideration of the risks associated with litigation, Edison International and SCE expect to incur a material loss in connection with the 2017/2018 Wildfire/Mudslide Events.
In the fourth quarter of 2018, SCE recorded a liability for estimated losses of $4.7 billion related to the 2017/2018 Wildfire/Mudslide Events. In the fourth quarter of 2019, SCE paid $360 million to a number of local public entities to resolve those parties' collective claims arising from the 2017/2018 Wildfire/Mudslide Events (the "Local Public Entity Settlements"). After the Local Public Entity Settlements, the liability accrued for estimated losses as of December 31, 2019 was reduced by the $360 million paid in the Local Public Entity Settlements.
Each reporting period, management reviews its loss estimates for remaining alleged and potential claims related to the 2017/2018 Wildfire/Mudslide Events. The process for estimating losses associated with wildfire litigation claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including, but not limited to: estimates of known and expected claims by third parties based on currently available information, opinions of counsel regarding litigation risk, the status of and developments in the course of litigation, and prior experience litigating and settling wildfire litigation claims. While the low end of the reasonably estimated range of expected losses for the 2017/2018 Wildfire/Mudslide Events is estimated on an aggregate basis, some of the factors evaluated by management in connection with its fourth quarter 2019 review contributed to a significant increase in certain loss estimates, while others contributed to a significant decrease in certain other loss estimates. The net result of management's fourth quarter 2019 review was an increase in estimated losses of $232 million for total estimated losses of $4.5 billion as of December 31, 2019 for unpaid claims related to the 2017/2018 Wildfire Mudslide Events. The accrued liability as of December 31, 2019 corresponds to the lower end of the reasonably estimated range of expected losses that may be incurred in connection with the 2017/2018 Wildfire/Mudslide Events and is subject to change as additional information becomes available.
Edison International and SCE will seek to offset any actual losses realized in connection with the 2017/2018 Wildfire/Mudslide Events with recoveries from insurance policies in place at the time of the events and, to the extent actual losses exceed insurance, through electric rates. As of December 31, 2019, Edison International and SCE have remaining expected recoveries from insurance of $1.7 billion and expected recoveries through FERC electric rates of $149 million on their consolidated balance sheets related to the 2017/2018 Wildfire/Mudslide Events. SCE believes that, in light of the CPUC's decision approvingin a cost recovery proceeding involving SDG&E arising from several 2007 wildfires in SDG&E's service area, there is substantial uncertainty regarding how the five-year program,CPUC will interpret and apply its prudency standard to an investor-owned utility in future wildfire cost-recovery proceedings for fires ignited prior to July 12, 2019. Accordingly, while the CPUC has not made a determination regarding SCE's prudency relative to any of the 2017/2018 Wildfire/Mudslide Events, SCE is unable to conclude, at this time, that uninsured CPUC-jurisdictional wildfire-related costs are probable of recovery through electric rates.
Edison International and SCE continue to pursue regulatory and legal strategies, and anticipate pursuing legislative strategies in the longer term, to address the application of a strict liability standard to wildfire-related property damages without the guaranteed ability to recover resulting costs in electric rates.
2019 Wildfire Legislation
In July 2019, AB 1054 was signed by the Governor of California and became effective immediately. The summary of the wildfire legislation in this report is based on SCE's interpretation of the legislation and is qualified in its entirety by, and should be read together with, AB 1054 and companion Assembly Bill 111.
Wildfire Insurance Fund
AB 1054 provided for the Wildfire Insurance Fund to reimburse utilities for payment of third-party damage claims arising from certain modifications,wildfires that exceed, in aggregate in a calendar year, the greater of $1.0 billion or the utility's insurance coverage. The Wildfire Insurance Fund was established in September 2019 when both SCE and SDG&E made their initial contributions to install charging infrastructurethe fund. The Wildfire Insurance Fund is available for claims related to wildfires ignited after July 12, 2019 that are determined to have been caused by a utility by the responsible government investigatory agency.
SCE and SDG&E have collectively made their initial contributions totaling approximately $2.7 billion to the Wildfire Insurance Fund. While PG&E has committed to make an initial contribution of approximately $4.8 billion to the Wildfire Insurance Fund upon emergence from bankruptcy, its participation in, and contributions to the fund are subject to it resolving its bankruptcy proceeding and meeting certain other conditions prior to June 30, 2020. SCE, SDG&E and PG&E are also collectively expected to make aggregate contributions of $3.0 billion to the Wildfire Insurance Fund through annual contributions to the fund over a 10-year period, of which SCE and SDG&E have made their initial annual contributions totaling approximately $107 million. If PG&E is unable to participate in the Wildfire Insurance Fund, then SCE and SDG&E are collectively expected to make aggregate contributions of approximately $1.0 billion to the fund through annual contributions over the 10-year period. In addition to PG&E's, SCE's and SDG&E's contributions to the Wildfire Insurance Fund, $13.5 billion is expected to be collected over a 15-year period from their ratepayers through a dedicated rate component. The amount collected from ratepayers may be directly contributed to the Wildfire Insurance Fund or used to support the electrificationissuance of 8,490 medium-up to $10.5 billion in bonds by the California Department of Water Resources, the proceeds of which would be contributed to the fund. In addition to funding contributions to the Wildfire Insurance Fund, the amount collected from utility ratepayers will pay for, among other things, any interest and heavy-dutyfinancing costs related to any bonds that are issued by the California Department of Water Resources to support the contributions to the Wildfire Insurance Fund. Based on a decision adopted by the CPUC in October 2019 in the Order Instituting Rulemaking to Consider Authorization of a Non-Bypassable Charge to Support the Wildfire Insurance Fund, PG&E's ratepayers will not be required to contribute to the fund if PG&E does not participate in the Wildfire Insurance Fund. In that case, $7.5 billion will be collected from SCE's and SDG&E's ratepayers through the dedicated rate component to support a contribution to the Wildfire Insurance Fund.
SCE made an initial contribution of approximately $2.4 billion to the Wildfire Insurance Fund in September 2019 and has committed to make ten annual contributions of approximately $95 million per year to the fund, by no later than January 1 of each year. SCE made its first annual contribution to the Wildfire Insurance Fund in December 2019. Edison International supported SCE's initial contribution to the Wildfire Insurance Fund by raising $1.2 billion from the issuance of Edison International equity. SCE raised the remaining $1.2 billion from the issuance of long-term debt. SCE's contributions to the Wildfire Insurance Fund will not be recoverable through electric vehiclesrates and will be excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. SCE will also not be entitled to cost recovery for any borrowing costs incurred in connection with its contributions to the Wildfire Insurance Fund.
Participating investor-owned utilities will be reimbursed from the Wildfire Insurance Fund for eligible claims, subject to the fund administrator's review, and will be required to reimburse the fund for withdrawn amounts that the CPUC disallows subject, in some instances, to the AB 1054 Liability Cap. A utility will not be eligible for the AB 1054 Liability Cap if it does not maintain a valid safety certification or its actions or inactions that resulted in the wildfire are found to constitute conscious or willful disregard of the rights and safety of others. On July 25, 2019, SCE obtained its initial safety certification that will be valid for twelve months. Based on SCE's 2020 rate base and assuming the equity portion of SCE's capital structure is 52% (SCE's CPUC authorized capital structure), SCE's requirement to reimburse the Wildfire Insurance Fund for eligible claims disallowed in 2020 would be capped at 870 sites,approximately $3.0 billion. SCE will not be allowed to recover borrowing costs incurred to reimburse the fund for amounts that the CPUC disallows. The Wildfire Insurance Fund and, consequently, the AB 1054 Liability Cap will terminate when the administrator determines that the fund has been exhausted.
AB 1054 Prudency Standard
As a result of the establishment of the Wildfire Insurance Fund, AB 1054 created a new standard that the CPUC must apply when assessing the prudency of a utility in connection with a request for recovery of wildfire costs for wildfires ignited after July 12, 2019. Under AB 1054, the CPUC is required to find a utility to be prudent if the utility's conduct related to the ignition was consistent with actions that a reasonable utility would have undertaken under similar circumstances, at the
relevant point in time, and based on the information available at that time. Utilities with a valid safety certification will be presumed to have acted prudently related to a wildfire ignition unless a party in the cost recovery proceeding creates serious doubt as to the reasonableness of the utility's conduct, at which musttime, the burden shifts back to the utility to prove its conduct was reasonable. If a utility does not have a valid safety certification, it will have the burden to prove, based on a preponderance of evidence, that its conduct was prudent. The new prudency standard will survive the termination of the Wildfire Insurance Fund.
Utilities participating in the Wildfire Insurance Fund that are found to be fully contractedprudent are not required to reimburse the fund for amounts withdrawn from the fund and can recover wildfire costs through electric rates if the fund has been exhausted.
Capital Expenditure Requirement
Under AB 1054, approximately $1.6 billion spent by 2024. The final decision includesSCE on wildfire risk mitigation capital expenditures made after August 1, 2019 cannot be included in the equity portion of SCE's rate base. SCE can apply for an approved five-year budgetirrevocable order from the CPUC to finance these capital expenditures, including through the issuance of $356 million ($242 million capital) in nominal dollars.securitized bonds, and can recover any prudently incurred financing costs. SCE expects to propose additional programsfinance this capital requirement by issuing securitized bonds.
For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Initial and pilotsannual contributions to the wildfire insurance fund established pursuant to California Assembly Bill 1054," "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" and "Legal Proceedings."
2021 General Rate Case
In August 2019, SCE filed its 2021 GRC application for the three-year period 2021-2023. Following amendments and other revisions to the application in November 2019 and February 2020, SCE’s 2021 revenue requirement is $7.6 billion. SCE's request excludes the revenue requirement associated with the approximately $1.6 billion in wildfire risk mitigation capital expenditures that SCE will exclude from the equity portion of rate base as required under AB 1054.
In the amendment of February 2020, SCE removed its CSRP implementation costs from the 2021 GRC. SCE will continue to track the cost of the CSRP program in a memorandum account previously approved in the future.2018 GRC and review of the CSRP implementation costs will be deferred to a future application to the CPUC.
The 2021 revenue requirement represents an increase of $1.1 billion over the 2020 revenue requirement authorized in the 2018 GRC and updated for anticipated post test-year ratemaking changes. Including the impact of anticipated lower kilowatt-hour sales in 2021 and one-time memorandum account recoveries, this represents an 11.4% increase over 2020 rates. SCE's 2021 GRC request also includes proposed revenue requirement increases of $423 million in 2022 and $514 million in 2023. The updated revenue requirements were requested based on the ROE and capital structure authorized at the time of the initial filing. A new capital structure has since been authorized. See "—2020 Cost of Capital Application."
SCE's requested increase to its revenue requirement in the 2021 GRC application is largely due to SCE's efforts to reduce wildfire risk. Certain of SCE's key wildfire mitigation forecast expenditures are subject to significant potential volatility. As a result, SCE has proposed establishing two-way balancing accounts for wildfire mitigation-related enhanced vegetation management, inspection activities and grid hardening, as well as for insurance premiums.
The capital programs requested in SCE's 2021 GRC include the infrastructure and programs necessary to implement California's ambitious public policy goals, including wildfire mitigation, de-carbonization of the economy through electrification and integration of distributed energy resources across a rapidly modernizing grid. See "—Capital Program" for further details.
The schedule established in the proceeding includes CPUC issuance of a proposed decision in the fourth quarter of 2020, or during the first quarter of 2021. If the final decision is issued in 2021, SCE will, consistent with CPUC practice in prior GRCs, request the CPUC to issue an order directing that the authorized revenue requirement changes be effective January 1, 2021.
Historically, the CPUC has set an annual revenue requirement for the base year and then set the remaining two years by a methodology established in the GRC proceeding. In January 2020, the CPUC approved a change from a triennial GRC cycle to a quadrennial GRC cycle for large energy utilities such as SCE. SCE is required to file an amendment to its application for the three-year period 2021 – 2023 to add an attrition year for 2024. The timing of the amendment is subject to further direction from the CPUC.
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. The2020 in excess of amounts requested for the 2018 to 2020 period are not includedauthorized in SCE's 2018 GRC.GRC and requested a balancing account to recover the incremental costs of implementing the program. In January 2019, the CPUC approved the establishment of an interim memorandum account to track GS&RP costs while the CPUC considers SCE's request for a balancing account, however thereapplication. There is no assurance that SCE will be allowed to ultimately recover these costs. The CPUC also imposed a monthly reporting requirement
In July 2019, SCE and certain parties to enable monitoring of SCE's GS&RP spending.proceeding submitted a motion to the CPUC requesting approval of a settlement agreement. If the CPUC approves the settlement agreement, SCE will be authorized to spend approximately $526 million ($407 million capital) in 2018 dollars between 2018 and 2020. If approved by the CPUC, SCE will include the authorized revenue requirement in rates and establish a balancing account to track the difference between actual GS&RP capital expenditurescosts and amounts authorized. If spending is less than authorized, SCE will refund those amounts to customers. If spending is in excess of forecasted amounts, or in excess of 115% of forecasted amounts for 2018 were $54 million and forecasted certain activities, SCE will present those costs for reasonableness review in a later track of the 2021 GRC.
GS&RP capital expenditures for 2019 are $224 million. If SCE's proposed balancing account is approved, forecasted costs forand 2018 were $370 million and $49 million, respectively. Forecasted GS&RP will be included in rates, with a subsequent reasonableness review throughcapital expenditures for 2020 are $564 million excluding capitalized indirect costs. In 2019, $37 million of expenses were recorded to the annual ERRA proceeding.interim memorandum account.
Wildfire Mitigation PlanPlans
In February 2019,Under AB 1054, SCE filed its 2019 WMP withis required to submit a wildfire mitigation plan to the CPUC. The WMP describesCPUC annually for review and approval. SCE's WMPs describe strategies, programs and activities that are in place, being implemented or are under development by SCE, including associated cost estimates, to proactively address and mitigate the threat of electrical infrastructure-associated ignitions that could lead to wildfires. Beginning in 2020, each WMP is required to cover at least a three-year period.
SCE filed its 2019 and 2020 WMPs with the CPUC in February 2019 and February 2020, respectively. Many, but not all, of the programs and activities described in theSCE's 2019 WMPand 2020 WMPs are part of SCE's 2018 and 2021 GRC requestrequests or GS&RP application. UponAs required by the CPUC, SCE's 2020 WMP includes updates in the areas of inspection and maintenance, vegetation management, system hardening, and situational awareness.
In May 2019, the CPUC approved SCE's 2019 WMP, however, such approval does not authorize the associated spending. The CPUC decision required SCE to meet certain reporting requirements, capture data, and improve its metrics for evaluating performance. During 2019 SCE recorded $307 million of expenses in the WMP memorandum account. During 2019, WMP capital expenditures not authorized in the 2018 GRC or contemplated in the GS&RP proceedings were $335 million. Forecasted 2020 WMP direct costs not authorized in the 2018 GRC or contemplated in the GS&RP proceedings are $557 million, of which $244 million is capital.
The WMP memorandum account will be subject to a subsequent reasonableness review through separate tracks of the 2021 GRC.
Fire Hazard Prevention Memorandum Account
The FHPMA was established to record the costs incurred related to fire hazard prevention in compliance with decisions from the CPUC. SCE has used the FHPMA to track incremental vegetation management activities to reduce the risk of fires. As of December 31, 2019, operation and maintenance expenses of $198 million have been recorded to the FHPMA.
The FHPMA is expected to be subject to a subsequent reasonableness review through separate tracks of the 2021 GRC.
Wildfire Expense Memorandum Account
SCE tracks insurance premium costs related to wildfire liability insurance policies as well as other wildfire-related costs in its WEMA. In July 2019, SCE filed a WEMA application with the CPUC to seek recovery of $478 million in wildfire insurance premium costs incurred in excess of premiums approved in the 2018 GRC. As of December 31, 2019, SCE has recognized $341 million of regulatory assets in the WEMA related to incremental wildfire insurance costs.
2018 General Rate Case
In May 2019, the CPUC approved a final decision in SCE's 2018 GRC. The final decision authorized a revenue requirement of $5.1 billion for 2018 and identified changes to certain balancing accounts, including the expansion of the TAMA to include the impacts of all differences between forecast and recorded tax expense. The final decision also disallowed certain historical spending, largely related to specific pole replacements the CPUC determined were performed prematurely.
The final decision allows a post-test year rate making mechanism that escalates capital additions by 2.49% for both 2019 and 2020. It also allows operation and maintenance expenses to be escalated for 2019 and 2020 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology set forth in the final decision results in a revenue requirement of $5.5 billion in 2019 and $5.9 billion in 2020.
The revenue requirements in the 2018 GRC final decision are retroactive to January 1, 2018. SCE recorded the prior period impact of the 2018 GRC final decision in 2019, including an increase to core earnings of $131 million from the application of the decision to revenue, depreciation expense and income tax expense and a non-core impairment of utility property, plant and equipment of $170 million ($123 million after-tax) related to disallowed historical capital expenditures. See "Results of Operations—SCE" and "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies" for further information.
2020 Cost of Capital Application
In April 2019, SCE filed an application with the CPUC for authority to establish its authorized cost of capital for utility operations for a three-year term, beginning January 1, 2020. In December 2019, the CPUC issued a final decision increasing the common equity component of SCE's capital structure from its current authorized level of 48% to 52% in 2020 and correspondingly reducing its preferred equity component from 9% to 5%. The final decision maintains SCE's CPUC ROE for the three-year period beginning January 1, 2020 at 10.3%.Under the decision, SCE's annual cost of capital adjustment mechanism also remains unchanged. Under the final decision, SCE's 2020 authorized cost of long-term debt and preferred equity are 4.74% and 5.70%, respectively. Based on the approved capital structure and costs, SCE's weighted average return on rate base for 2020 will be 7.68%.
Based on the revenue requirement approved in SCE's 2018 GRC, SCE’s cost of capital and capital structure approved in the final decision will result in a projected revenue requirement increase in 2020 of approximately $38 million from revenue currently included in CPUC electric rates of $5.9 billion.
2018 and 2019 FERC Formula Rate
In December 2019, the FERC approved a settlement on SCE's formula rates for the 2018 Formula Rate case that established SCE's FERC transmission revenue requirement for the FERC 2018 Settlement Period. The settlement provides for a weighted average ROE of 11.2%, which includes a previously authorized 50 basis point incentive for CAISO participation and individual and previously authorized project incentives. Under the settlement, if the FERC issues a final, unappealable ruling that finds SCE is not eligible for the 50 basis point incentive for CAISO participation, then the ROE for the FERC 2018 Settlement Period will be reduced to 10.7%. Prior to the settlement, SCE had been recognizing revenue during the FERC 2018 Settlement Period based on its expectations of the outcome of the 2018 Formula Rate case. Regulatory assets and liabilities were adjusted based on the settlement of the 2018 Formula Rate case, which resulted in an increase in net income of $29 million related to 2018, being recorded in 2019. The transmission revenue requirement and rates that have been billed to customers for the FERC 2018 Settlement Period were based on a total FERC weighted average ROE of 11.58%, and SCE expects to refund excess amounts billed to customers during 2020. In the 2019 Formula Rate case, SCE's requested base
return on equity, as modified by a partial settlement approved by the FERC, is 11.97% ("FERC Base ROE"). This ROE request reflects a conventional ROE of 11.12% and an additional ROE of 0.85% to compensate investors for current wildfire risk. As with SCE's requested ROE in its 2020 CPUC Cost of Capital proceeding, this request reflects the anticipated impact of AB 1054 on SCE's requested ROE. SCE's total ROE request, inclusive of project incentives and a 0.5% incentive for CAISO participation, would be approximately 13.25%. The 2019 Formula Rate was implemented in rates in November 2019 and remains subject to hearing and settlement procedures. Amounts billed to customers under the 2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved.
In November 2019, the FERC issued a decision in a pending Midcontinent Independent System Operator Transmission Owners ("MISO TO") proceeding which significantly revised the methodology used to determine MISO TO's just and reasonable ROE levels by restricting the valuation methodologies that would be recognized by the FERC in establishing a zone of reasonableness for ROE. The decision also reiterated that authorized ROE, including FERC-authorized project incentives, could not exceed the established zone of reasonableness. The updated methodology led to an authorized ROE for MISO TO of 9.88%, compared to their previously authorized ROE of 12.38%. Numerous parties requested rehearing of the MISO decision on various grounds and, in January 2020, the FERC granted rehearing requests for the limited purpose of allowing the FERC additional time for consideration of the concerns raised.
In December 2019, the CPUC filed a protest with the FERC alleging that $419 million of costs associated with SCE's Tehachapi Transmission Project are imprudent and should be disallowed from SCE's FERC rate base because these costs exceeded the maximum reasonable costs identified by the CPUC when it granted the project’s certificate of public convenience and necessity. The CPUC requested that the FERC set this issue for hearings and consolidate the protest with the settlement proceedings of the 2019 Formula Rate case.
Southern California Wildfires and Mudslides
Multiple factors have contributed to increased wildfire activity, and faster progression of and increased damage from wildfires across SCE's service territory and throughout California. These include the buildup of dry vegetation in areas severely impacted by years of historic drought, lack of adequate clearing of hazardous fuels by responsible parties, higher temperatures, lower humidity, and strong Santa Ana winds. At the same time that wildfire risk has been increasing in Southern California, residential and commercial development has occurred and is occurring in some of the highest-risk areas. Such factors can increase the likelihood and extent of wildfires. SCE has determined that approximately 27% of its service territory is in areas identified as high fire risk.
Over the past several years, wind-driven wildfires impacted portions of SCE's service territory, with wildfires in December 2017 and November 2018 causing loss of life, substantial damage to both residential and business properties, and service outages for SCE customers. In 2019, several wind-driven wildfires originated in Southern California. SCE does not expect any of these 2019 fires to have a material adverse effect on its financial condition, results of operations or cash flows.
Edison International and SCE recorded a charge of $255 million as of December 31, 2019 for wildfire-related claims, net of expected insurance recoveries. The 2019 charge consists of an increase in estimated losses for claims related to the 2017/2018 Wildfire/Mudslide Events of $232 million, against which SCE has recorded expected recoveries through FERC electric rates of $14 million. The resulting charge was $218 million ($157 million after-tax). The fourth quarter 2019 charge also includes $23 million ($17 million after-tax) of expenses primarily associated with self-insured retention for fires that occurred in Southern California in 2019.
2017/2018 Wildfire/Mudslide Events
The investigating government agencies, the VCFD and CAL FIRE, have determined that the largest of the 2017 fires originated on December 4, 2017, in the Anlauf Canyon area of Ventura County (the investigating agencies refer to this fire as the "Thomas Fire"), followed shortly thereafter by the Koenigstein Fire. While the progression of these two fires remains under review, the December 4, 2017 fires eventually burned substantial acreage in both Ventura and Santa Barbara Counties. The largest of the November 2018 fires, known as the Woolsey Fire, originated in Ventura County and burned acreage in both Ventura and Los Angeles Counties.
In March 2019, the VCFD and CAL FIRE jointly issued separate reports finding that the Thomas Fire and the Koenigstein Fire were each caused by SCE equipment. At this time, based on available information, SCE has not determined whether its equipment caused the Thomas Fire. Based on publicly available radar data showing a smoke plume in the Anlauf Canyon area emerging in advance of the start time of the Thomas Fire indicated in the Thomas Fire report, SCE believes that the Thomas Fire started at least 12 minutes prior to any issue involving SCE's system and at least 15 minutes prior to the start time indicated in the report. SCE has previously disclosed that SCE believed its equipment was associated with the ignition
of the Koenigstein Fire. SCE is continuing to assess the progression of the Thomas and Koenigstein Fires and the extent of damages that may be attributable to each fire.
SCE has received a non-final redacted draft of a report from the VCFD subject to a protective order in the litigation related to the Woolsey fire and, other than the information disclosed in this Form 10-K, is not authorized to release the report or its contents to the public at this time. The draft report states that the VCFD investigation team determined that electrical equipment owned and operated by SCE was the cause of the Woolsey Fire. Absent additional evidence, SCE believes that it is likely that its equipment was associated with the ignition of the Woolsey Fire.
Multiple lawsuits related to the Thomas and Koenigstein Fires and the Woolsey Fire have been initiated against SCE and Edison International. Some of the Thomas and Koenigstein Fires lawsuits claim that SCE and Edison International have responsibility for the damages caused by the Montecito Mudslides based on a theory alleging that SCE has responsibility for the Thomas and/or Koenigstein Fires and that the Thomas and/or Koenigstein Fires proximately caused the Montecito Mudslides.
SCE's internal review into the facts and circumstances of each of the 2017/2018 Wildfire/Mudslide Events is ongoing, and SCE expects to obtain and review additional information and materials in the possession of third parties during the course of its internal reviews and the litigation processes.Final determinations of liability for the Thomas Fire, the Koenigstein Fire, the Montecito Mudslides and the Woolsey Fire (each a "2017/2018 Wildfire/Mudslide Event," and, collectively, the "2017/2018 Wildfire/Mudslide Events"), including determinations of whether SCE was negligent, would only be made during lengthy and complex litigation processes. Even when investigations are still pending or liability is disputed, an assessment of likely outcomes, including through future settlement of disputed claims, may require a liability to be accrued under accounting standards. Based on information available to SCE and consideration of the risks associated with litigation, Edison International and SCE expect to incur a material loss in connection with the 2017/2018 Wildfire/Mudslide Events.
In the fourth quarter of 2018, SCE recorded a liability for estimated losses of $4.7 billion related to the 2017/2018 Wildfire/Mudslide Events. In the fourth quarter of 2019, SCE paid $360 million to a number of local public entities to resolve those parties' collective claims arising from the 2017/2018 Wildfire/Mudslide Events (the "Local Public Entity Settlements"). After the Local Public Entity Settlements, the liability accrued for estimated losses as of December 31, 2019 was reduced by the $360 million paid in the Local Public Entity Settlements.
Each reporting period, management reviews its loss estimates for remaining alleged and potential claims related to the 2017/2018 Wildfire/Mudslide Events. The process for estimating losses associated with wildfire litigation claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including, but not limited to: estimates of known and expected claims by third parties based on currently available information, opinions of counsel regarding litigation risk, the status of and developments in the course of litigation, and prior experience litigating and settling wildfire litigation claims. While the low end of the reasonably estimated range of expected losses for the 2017/2018 Wildfire/Mudslide Events is estimated on an aggregate basis, some of the factors evaluated by management in connection with its fourth quarter 2019 review contributed to a significant increase in certain loss estimates, while others contributed to a significant decrease in certain other loss estimates. The net result of management's fourth quarter 2019 review was an increase in estimated losses of $232 million for total estimated losses of $4.5 billion as of December 31, 2019 for unpaid claims related to the 2017/2018 Wildfire Mudslide Events. The accrued liability as of December 31, 2019 corresponds to the lower end of the reasonably estimated range of expected losses that may be incurred in connection with the 2017/2018 Wildfire/Mudslide Events and is subject to change as additional information becomes available.
Edison International and SCE will establishseek to offset any actual losses realized in connection with the 2017/2018 Wildfire/Mudslide Events with recoveries from insurance policies in place at the time of the events and, to the extent actual losses exceed insurance, through electric rates. As of December 31, 2019, Edison International and SCE have remaining expected recoveries from insurance of $1.7 billion and expected recoveries through FERC electric rates of $149 million on their consolidated balance sheets related to the 2017/2018 Wildfire/Mudslide Events. SCE believes that, in light of the CPUC's decision in a cost recovery proceeding involving SDG&E arising from several 2007 wildfires in SDG&E's service area, there is substantial uncertainty regarding how the CPUC will interpret and apply its prudency standard to an investor-owned utility in future wildfire cost-recovery proceedings for fires ignited prior to July 12, 2019. Accordingly, while the CPUC has not made a determination regarding SCE's prudency relative to any of the 2017/2018 Wildfire/Mudslide Events, SCE is unable to conclude, at this time, that uninsured CPUC-jurisdictional wildfire-related costs are probable of recovery through electric rates.
Edison International and SCE continue to pursue regulatory and legal strategies, and anticipate pursuing legislative strategies in the longer term, to address the application of a strict liability standard to wildfire-related property damages without the guaranteed ability to recover resulting costs in electric rates.
2019 Wildfire Legislation
In July 2019, AB 1054 was signed by the Governor of California and became effective immediately. The summary of the wildfire legislation in this report is based on SCE's interpretation of the legislation and is qualified in its entirety by, and should be read together with, AB 1054 and companion Assembly Bill 111.
Wildfire Insurance Fund
AB 1054 provided for the Wildfire Insurance Fund to reimburse utilities for payment of third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1.0 billion or the utility's insurance coverage. The Wildfire Insurance Fund was established in September 2019 when both SCE and SDG&E made their initial contributions to the fund. The Wildfire Insurance Fund is available for claims related to wildfires ignited after July 12, 2019 that are determined to have been caused by a utility by the responsible government investigatory agency.
SCE and SDG&E have collectively made their initial contributions totaling approximately $2.7 billion to the Wildfire Insurance Fund. While PG&E has committed to make an initial contribution of approximately $4.8 billion to the Wildfire Insurance Fund upon emergence from bankruptcy, its participation in, and contributions to the fund are subject to it resolving its bankruptcy proceeding and meeting certain other conditions prior to June 30, 2020. SCE, SDG&E and PG&E are also collectively expected to make aggregate contributions of $3.0 billion to the Wildfire Insurance Fund through annual contributions to the fund over a 10-year period, of which SCE and SDG&E have made their initial annual contributions totaling approximately $107 million. If PG&E is unable to participate in the Wildfire Insurance Fund, then SCE and SDG&E are collectively expected to make aggregate contributions of approximately $1.0 billion to the fund through annual contributions over the 10-year period. In addition to PG&E's, SCE's and SDG&E's contributions to the Wildfire Insurance Fund, $13.5 billion is expected to be collected over a 15-year period from their ratepayers through a dedicated rate component. The amount collected from ratepayers may be directly contributed to the Wildfire Insurance Fund or used to support the issuance of up to $10.5 billion in bonds by the California Department of Water Resources, the proceeds of which would be contributed to the fund. In addition to funding contributions to the Wildfire Insurance Fund, the amount collected from utility ratepayers will pay for, among other things, any interest and financing costs related to any bonds that are issued by the California Department of Water Resources to support the contributions to the Wildfire Insurance Fund. Based on a decision adopted by the CPUC in October 2019 in the Order Instituting Rulemaking to Consider Authorization of a Non-Bypassable Charge to Support the Wildfire Insurance Fund, PG&E's ratepayers will not be required to contribute to the fund if PG&E does not participate in the Wildfire Insurance Fund. In that case, $7.5 billion will be collected from SCE's and SDG&E's ratepayers through the dedicated rate component to support a contribution to the Wildfire Insurance Fund.
SCE made an initial contribution of approximately $2.4 billion to the Wildfire Insurance Fund in September 2019 and has committed to make ten annual contributions of approximately $95 million per year to the fund, by no later than January 1 of each year. SCE made its first annual contribution to the Wildfire Insurance Fund in December 2019. Edison International supported SCE's initial contribution to the Wildfire Insurance Fund by raising $1.2 billion from the issuance of Edison International equity. SCE raised the remaining $1.2 billion from the issuance of long-term debt. SCE's contributions to the Wildfire Insurance Fund will not be recoverable through electric rates and will be excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. SCE will also not be entitled to cost recovery for any borrowing costs incurred in connection with its contributions to the Wildfire Insurance Fund.
Participating investor-owned utilities will be reimbursed from the Wildfire Insurance Fund for eligible claims, subject to the fund administrator's review, and will be required to reimburse the fund for withdrawn amounts that the CPUC disallows subject, in some instances, to the AB 1054 Liability Cap. A utility will not be eligible for the AB 1054 Liability Cap if it does not maintain a valid safety certification or its actions or inactions that resulted in the wildfire are found to constitute conscious or willful disregard of the rights and safety of others. On July 25, 2019, SCE obtained its initial safety certification that will be valid for twelve months. Based on SCE's 2020 rate base and assuming the equity portion of SCE's capital structure is 52% (SCE's CPUC authorized capital structure), SCE's requirement to reimburse the Wildfire Insurance Fund for eligible claims disallowed in 2020 would be capped at approximately $3.0 billion. SCE will not be allowed to recover borrowing costs incurred to reimburse the fund for amounts that the CPUC disallows. The Wildfire Insurance Fund and, consequently, the AB 1054 Liability Cap will terminate when the administrator determines that the fund has been exhausted.
AB 1054 Prudency Standard
As a result of the establishment of the Wildfire Insurance Fund, AB 1054 created a new standard that the CPUC must apply when assessing the prudency of a utility in connection with a request for recovery of wildfire costs for wildfires ignited after July 12, 2019. Under AB 1054, the CPUC is required to find a utility to be prudent if the utility's conduct related to the ignition was consistent with actions that a reasonable utility would have undertaken under similar circumstances, at the
relevant point in time, and based on the information available at that time. Utilities with a valid safety certification will be presumed to have acted prudently related to a wildfire ignition unless a party in the cost recovery proceeding creates serious doubt as to the reasonableness of the utility's conduct, at which time, the burden shifts back to the utility to prove its conduct was reasonable. If a utility does not have a valid safety certification, it will have the burden to prove, based on a preponderance of evidence, that its conduct was prudent. The new prudency standard will survive the termination of the Wildfire Insurance Fund.
Utilities participating in the Wildfire Insurance Fund that are found to be prudent are not required to reimburse the fund for amounts withdrawn from the fund and can recover wildfire costs through electric rates if the fund has been exhausted.
Capital Expenditure Requirement
Under AB 1054, approximately $1.6 billion spent by SCE on wildfire risk mitigation capital expenditures made after August 1, 2019 cannot be included in the equity portion of SCE's rate base. SCE can apply for an irrevocable order from the CPUC to finance these capital expenditures, including through the issuance of securitized bonds, and can recover any prudently incurred financing costs. SCE expects to finance this capital requirement by issuing securitized bonds.
For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Initial and annual contributions to the wildfire insurance fund established pursuant to California Assembly Bill 1054," "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" and "Legal Proceedings."
2021 General Rate Case
In August 2019, SCE filed its 2021 GRC application for the three-year period 2021-2023. Following amendments and other revisions to the application in November 2019 and February 2020, SCE’s 2021 revenue requirement is $7.6 billion. SCE's request excludes the revenue requirement associated with the approximately $1.6 billion in wildfire risk mitigation capital expenditures that SCE will exclude from the equity portion of rate base as required under AB 1054.
In the amendment of February 2020, SCE removed its CSRP implementation costs from the 2021 GRC. SCE will continue to track the cost of the CSRP program in a memorandum account to track incremental costs incurred to implement the WMP. The planned 2019 WMP spending not contemplatedpreviously approved in the 2018 GRC and GS&RP proceedings is approximately $380 millionreview of which $122 million is capital. SCEthe CSRP implementation costs will track costs and seek recovery inbe deferred to a future CPUC procedural forums for any incremental costs beyond those which are ultimately approvedapplication to the CPUC.
The 2021 revenue requirement represents an increase of $1.1 billion over the 2020 revenue requirement authorized in the 2018 GRC and updated for anticipated post test-year ratemaking changes. Including the impact of anticipated lower kilowatt-hour sales in 2021 and one-time memorandum account recoveries, this represents an 11.4% increase over 2020 rates. SCE's 2021 GRC request also includes proposed revenue requirement increases of $423 million in 2022 and $514 million in 2023. The updated revenue requirements were requested based on the ROE and capital structure authorized at the time of the initial filing. A new capital structure has since been authorized. See "—2020 Cost of Capital Application."
SCE's requested increase to its revenue requirement in the 2021 GRC application is largely due to SCE's efforts to reduce wildfire risk. Certain of SCE's key wildfire mitigation forecast expenditures are subject to significant potential volatility. As a result, SCE has proposed establishing two-way balancing accounts for wildfire mitigation-related enhanced vegetation management, inspection activities and grid hardening, as well as for insurance premiums.
The capital programs requested in SCE's 2021 GRC include the infrastructure and programs necessary to implement California's ambitious public policy goals, including wildfire mitigation, de-carbonization of the economy through electrification and integration of distributed energy resources across a rapidly modernizing grid. See "—Capital Program" for further details.
The schedule established in the proceeding includes CPUC issuance of a proposed decision in the fourth quarter of 2020, or during the first quarter of 2021. If the final decision is issued in 2021, SCE will, consistent with CPUC practice in prior GRCs, request the CPUC to issue an order directing that the authorized revenue requirement changes be effective January 1, 2021.
Historically, the CPUC has set an annual revenue requirement for the base year and then set the GS&RPremaining two years by a methodology established in the GRC proceeding.
Charge Ready Program
In January 2016,2020, the CPUC approved SCE's $22 million Charge Ready Program Pilot, which allowsa change from a triennial GRC cycle to a quadrennial GRC cycle for large energy utilities such as SCE. SCE is required to install light-duty electric vehicle charging infrastructure, provide rebatesfile an amendment to offsetits application for the costthree-year period 2021 – 2023 to add an attrition year for 2024. The timing of qualified customer-owned charging stations, andthe amendment is subject to further direction from the CPUC.
implement aElectricity Industry Trends
In addition to responding to the "new normal" of increased wildfire-activity in California, the electric power industry is also undergoing transformative change driven by technological advances, such as customer-owned generation, electric vehicles and energy storage, which are altering the nature of energy generation and delivery. California is committed to reducing its GHG emissions, improving local air quality and supporting marketing, education,continued economic growth. The state set goals to reduce GHG emissions by 40% from 1990 levels by 2030 and outreach campaign. As of December 31, 2018, SCE had executed agreements80% from the same baseline by 2050. Additionally, the state is aiming to be carbon neutral by 2045. State and reserved fundinglocal air quality plans call for 79 sites to deploy 1,280 charge ports. The results of this pilot helped shape Charge Ready 2,substantial improvements, such as reducing smog-causing nitrogen oxides 90% below 2010 levels by 2032 in the second phasemost polluted areas of the Charge Ready program.
In June 2018, SCE filed an application to obtain approval for Charge Ready 2. Instate. While these policy goals cannot be achieved by the application, SCE requested approval for $760 million ($561 million capital) in 2018 dollars to install infrastructure and provide rebates to support 48,000electric sector alone, the electric grid is a critical enabler of the adoption of new electric vehicle charging ports as part of a four-year programenergy technologies 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 objectives. Therefore, California has set RPS targets modernizewhich require California retail sellers of electricity to provide 60% of energy sales from renewable resources by 2030. California also requires sellers of electricity to deliver 100% of retail sales from carbon free sources by 2045. In 2019 approximately 48% of SCE's customer deliveries came from carbon-free resources. SCE's climate change objectives align with California's requirements, and SCE anticipates it will meet its own objectives, and therefore California's requirements, through 2045.
The grid is also key to enabling more customer choices with respect to new energy technologies, including fostering the adoption of electric vehicles. Edison International believes that California's 2045 goals can be achieved most economically through emissions reductions from using clean electricity serving 100% of retail sales, electrifying 75% of vehicles and 70% of buildings and using low-carbon fuels for technologies that are not yet viable for electrification. Edison International expects to lead the transformation of the industry by building a modernized and more reliable grid, focusing on opportunities in clean energy and efficient electrification, and enabling customers' technology choices.
SCE plans to enable the adoption of new energy technologies that mitigate wildfire risk and benefit customers of the electric grid while also helping California achieve its environmental goals. SCE expects to achieve these objectives through improving the safety and reliability of the transmission and distribution systemnetwork and helping customers make cleaner energy choices including enabling increased penetration of DERs, electric transportation, building electrification and energy efficiency programs. SCE's ongoing focus to accommodate two-way flowsdrive operational and service excellence is intended to allow it to achieve these objectives safely while controlling costs and customer rates. SCE's focus on the transmission and distribution of electricity aligns with California's policy supporting competitive power procurement markets. For more information on the grid development, see "Liquidity and Capital Resources—Capital Investment Plan—Grid Development—Wildfire Mitigation" and "Liquidity and Capital Resources—Capital Investment Plan—Grid Development—Transportation Electrification."
Changes in the electric power industry are impacting customers and jurisdictions outside California as well. Edison International believes that other states will also pursue climate change and GHG reduction objectives and large commercial and industrial customers will continue to pursue cost reduction and sustainability goals. Edison Energy provides energy services and managed portfolio solutions to commercial and industrial customers who may be impacted by these changes. Edison Energy seeks to provide advice in dealing with increasingly complex tariff and technology choices in order to support customers and their management of energy associated with DERs, suchcosts and risks.
To better engage in this broader transformation and provide a view of developments outside of SCE, Edison International has made several minority investments in emerging companies in areas related to the technology changes that are driving industry transformation and may make additional investments in the future. These investments are not financially material to Edison International.
Capital Program
Total capital expenditures (including accruals) were $4.8 billion in 2019 and $4.4 billion in 2018. SCE's year-end rate base was $32.6 billion at December 31, 2019 compared to $29.6 billion at December 31, 2018. Under AB 1054, approximately $1.6 billion of wildfire risk mitigation capital expenditures cannot be included in the equity portion of SCE's rate base and instead can be recovered through issuance of securitized bonds. The year-end rate base of $32.6 billion at December 31, 2019 excludes $252 million wildfire risk mitigation capital expenditures as rooftop solar, and facilitate customer choice of new technologies and services that reduce emissions and improve resilience.required by AB 1054.
Based on the 2021 GRC request, SCE forecasts capital expenditures for 2020 – 2023 to be approximately $19.4 billion to $21.2 billion. SCE's 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 theforecast for 2020 reflects planned CPUC jurisdictional spending as a part ofinformed by the 2018 GRC DRP rule making, technology availability, pacefinal decision, spending associated with SCE's wildfire mitigation-related capital expenditures under the GS&RP and WMP, and current expectations of DER adoption,FERC- jurisdictional spending. SCE's capital expenditure forecast for 2021 – 2023 reflects the requested CPUC jurisdictional spending included in the 2021 GRC application, approved non-GRC CPUC capital spending, and other factors.current expectations of FERC- jurisdictional capital spending. SCE's forecasted capital expenditures for 2020 – 2021 include approximately $300 million of capital spending on the CSRP project. Total forecasted capital expenditures for
the CSRP project are approximately $540 million from inception through 2021. In the 2018 GRC, SCE provided a cost estimate to the CPUC of $209 million in capital expenditures for the CSRP program. In February 2018,2020, SCE filed an update with the CPUC issued a decision that established a new distribution investment deferral frameworkto exclude CSRP program expenditures from rate base and provided new guidance regarding DER adoption forecasting. In March 2018,capital expenditures of the CPUC approved a decision that provides a grid modernization framework that will be used2021 GRC application and to support CPUC reviewcontinue to track the cost of grid modernization investments that are proposedthe CSRP program in a GRC. This grid modernization framework will not apply to SCE's 2018 GRC, unless otherwise ordered by the ALJ or Assigned Commissionermemorandum account previously approved in the 2018 GRC. ItForecasted expenditures for FERC-jurisdictional capital projects are subject to change due to timeliness of permitting, licensing, regulatory approvals and contractor bids. Capital spending in 2021, 2022 and 2023 will applybe dependent upon the amount approved in a 2021 GRC final decision.
Based on management judgment using historical precedent of previously authorized amounts and potential permitting delays and other operational considerations, a range case has been provided reflecting a 10% reduction on the total capital forecast for 2021 – 2023 and a 10% reduction on FERC capital spending and non-GRC programs for 2020.
The following table sets forth a summary of capital expenditures for 2019 actual spend and a forecast for 2020 – 2023 on the basis described above:
|
| | | | | | | | | | | | | | | | | | | |
| (in billions) | | 2019 | 2020 | 2021 | 2022 | 2023 | Total 2020 – 2023 |
| Traditional capital expenditures | | | | | | | |
| Distribution | | $ | 3.1 |
| $ | 3.2 |
| $ | 3.4 |
| $ | 3.3 |
| $ | 3.2 |
| $ | 13.1 |
|
| Transmission | | 0.8 |
| 0.7 |
| 0.8 |
| 0.8 |
| 0.6 |
| 2.9 |
|
| Generation | | 0.2 |
| 0.2 |
| 0.2 |
| 0.2 |
| 0.2 |
| 0.8 |
|
| Subtotal | | 4.1 |
| 4.1 |
| 4.4 |
| 4.3 |
| 4.0 |
| 16.8 |
|
| Wildfire mitigation-related capital expenditures | | 0.7 |
| 0.9 |
| 1.0 |
| 1.1 |
| 1.4 |
| 4.4 |
|
| Total capital expenditures | | $ | 4.8 |
| $ | 5.0 |
| $ | 5.4 |
| $ | 5.4 |
| $ | 5.4 |
| $ | 21.2 |
|
| Total capital expenditures using range case discussed above | | * |
| $ | 4.8 |
| $ | 4.9 |
| $ | 4.9 |
| $ | 4.8 |
| $ | 19.4 |
|
* Not applicable
SCE's authorized CPUC-jurisdictional rate base is determined through the GRC and other regulatory proceedings. Differences between actual and CPUC-authorized capital expenditures are addressed in subsequent GRC or other regulatory proceedings. FERC-jurisdictional rate base is generally determined based on actual capital expenditures.
Reflected below is SCE's weighted average annual rate base for 2019 – 2023 incorporating CPUC capital expenditures authorized in the 2018 GRC final decision, expected FERC capital expenditures and capital expenditures included in the 2021 GRC application. The table below does not reflect the $1.6 billion of wildfire risk mitigation capital expenditures to subsequent GRCs.be excluded from the equity portion of SCE's rate base under AB 1054. The table below does not reflect rate base associated with non-GRC projects or programs that have not yet been approved by the CPUC, including CSRP, with the exception of GS&RP spend incurred before August 1, 2019. In addition, a third-party holds an option to invest up to $400 million in the West of Devers Transmission project at the estimated in-service date of 2021. The rate base in the table below is reduced to reflect this option.
|
| | | | | | | | | | | | | | | | |
| (in billions) | | 2019 | 2020 | 2021 | 2022 | 2023 |
| Rate base for expected capital expenditures | | $ | 30.8 |
| $ | 33.4 |
| $ | 35.9 |
| $ | 38.2 |
| $ | 41.0 |
|
| Rate base for expected capital expenditures (using range case described above) | | * |
| $ | 33.3 |
| $ | 35.1 |
| $ | 37.0 |
| $ | 39.2 |
|
* Not applicable
For additional information, see "Liquidity and Capital Resources—Capital Investment Plan."
RESULTS OF OPERATIONS
SCE
SCE's results of operations are derived mainly through two sources:
Earning activities – representing revenue authorized by the CPUC and the FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of authorized operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in earnings activities are revenue or penalties related to incentive mechanisms, other operating revenue and regulatory charges or disallowances.
Cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery of specific project or program costs, subject to reasonableness review or compliance with upfront standards. Cost-recovery activities include rates which provide recovery, subject to reasonableness review of, among other things, fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs) and certain operation and maintenance expenses. SCE earns no return on these activities.
Impact of 2018 GRC
The 2018 GRC final decision determines the amount of revenue that SCE is authorized to collect from customers to recover anticipated costs, including return on rate base. The 2018 GRC final decision approved an authorized revenue requirement of $5.1 billion for 2018, the first year ("Test Year") of the three-year GRC period, and authorized annual increases under a set escalation mechanism based on labor, non-labor and medical expenses.
In the absence of a 2018 GRC final decision, SCE recognized revenue in 2018 and the first quarter of 2019 based on the 2017 authorized revenue requirement, adjusted for items SCE determined to be probable of occurring, primarily the July 2017 cost of capital decision and Tax Reform. Adjustments were also made to 2017 authorized revenue to reflect changes in authorized tax benefits for certain balancing accounts.
As indicated in the table below, authorized revenue in the 2018 GRC final decision is less than the amount recognized in 2018:
|
| | | | | | | | | | | | | | | | | | | | |
| (in millions) | 2017 Authorized Revenue | | Adjustments | | 2018 Revenue Recognized in Form 10-K | | 2018 Test Year Authorized Revenue | | Adjustment to 2018 Revenue Recorded in 2019 | |
| Authorized revenue | $ | 5,640 |
| | $ | (235 | ) | | $ | 5,405 |
| | $ | 5,116 |
| | $ | (289 | ) | 1 |
| Cost of service: | | | | | | | | | | |
| Operation and maintenance | 1,931 |
| | (11 | ) | | 1,920 |
| | 1,582 |
| | (338 | ) | 2 |
| Depreciation | 1,575 |
| | 59 |
| | 1,634 |
| | 1,579 |
| | (55 | ) | 3 |
| Property and payroll taxes | 285 |
| | 9 |
| | 294 |
| | 315 |
| | 21 |
| |
| Income taxes | 257 |
| | (287 | ) | | (30 | ) | | (19 | ) | | 11 |
| |
| Authorized return | 1,592 |
| | (5 | ) | | 1,587 |
| | 1,659 |
| | 72 |
| |
| Total authorized revenue | $ | 5,640 |
| | $ | (235 | ) | | $ | 5,405 |
| | $ | 5,116 |
| | $ | (289 | ) | |
| |
1 | The change in authorized revenue in the Test Year is comprised of $129 million in earnings activities and $160 million in cost recovery activities. |
| |
2 | Authorized revenue for operation and maintenance costs decreased due to: |
$178 million reduction for earnings activities primarily from SCE's initiatives to improve operational efficiency, which has resulted in lower forecasted costs than included in the 2017 authorized amounts.
$160 million reduction in cost-recovery activities, which do not impact earnings, primarily for medical and employee benefit costs.
3 Authorized revenue for depreciation decreased as a result of lower authorized depreciation rates.
After the application of escalation factors to the Test Year, the CPUC authorized SCE to collect $5.5 billion from customers in 2019. During the second quarter of 2019, SCE recorded a reduction of revenue of $265 million to reflect $289 million of lower authorized revenue related to 2018 and $24 million of higher authorized revenue in 2019. The 2018 GRC final decision is retroactive to January 1, 2018 and the reduction of revenue contributed to a refund to customers of $554 million, which SCE recorded as a regulatory liability. SCE expects to refund these amounts to customers through December 2020.
Years ended December 31, 2019, 2018 and 2017
The following table is a summary of SCE's results of operations for the periods indicated.indicated:
| | | | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| (in millions) | Earning Activities | Cost- Recovery Activities | Total Consolidated | Earning Activities | Cost- Recovery Activities | Total Consolidated | Earning Activities | Cost- Recovery Activities | Total Consolidated | 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 |
| $ | 6,678 |
| $ | 5,628 |
| $ | 12,306 |
| $ | 6,560 |
| $ | 6,051 |
| $ | 12,611 |
| $ | 6,611 |
| $ | 5,643 |
| $ | 12,254 |
|
| Purchased power and fuel | — |
| 5,406 |
| 5,406 |
| — |
| 4,873 |
| 4,873 |
| — |
| 4,527 |
| 4,527 |
| — |
| 4,839 |
| 4,839 |
| — |
| 5,406 |
| 5,406 |
| — |
| 4,873 |
| 4,873 |
|
Operation and maintenance1 | 1,972 |
| 730 |
| 2,702 |
| 1,898 |
| 824 |
| 2,722 |
| 1,934 |
| 838 |
| 2,772 |
| 2,073 |
| 863 |
| 2,936 |
| 1,972 |
| 730 |
| 2,702 |
| 1,898 |
| 824 |
| 2,722 |
|
| Wildfire-related claims, net of insurance recoveries | 2,669 |
| — |
| 2,669 |
| — |
| — |
| — |
| — |
| — |
| — |
| 255 |
| — |
| 255 |
| 2,669 |
| — |
| 2,669 |
| — |
| — |
| — |
|
| Wildfire insurance fund expense | | 152 |
| — |
| 152 |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Depreciation and amortization | 1,867 |
| — |
| 1,867 |
| 2,032 |
| — |
| 2,032 |
| 1,998 |
| — |
| 1,998 |
| 1,727 |
| 1 |
| 1,728 |
| 1,867 |
| — |
| 1,867 |
| 2,032 |
| — |
| 2,032 |
|
| Property and other taxes | 392 |
| — |
| 392 |
| 372 |
| — |
| 372 |
| 351 |
| — |
| 351 |
| 396 |
| — |
| 396 |
| 392 |
| — |
| 392 |
| 372 |
| — |
| 372 |
|
| Impairment and other | (12 | ) | — |
| (12 | ) | 716 |
| — |
| 716 |
| — |
| — |
| — |
| 159 |
| — |
| 159 |
| (12 | ) | — |
| (12 | ) | 716 |
| — |
| 716 |
|
| Other operating income | (7 | ) | — |
| (7 | ) | (8 | ) | — |
| (8 | ) | — |
| — |
| — |
| (4 | ) | — |
| (4 | ) | (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 |
| 4,758 |
| 5,703 |
| 10,461 |
| 6,881 |
| 6,136 |
| 13,017 |
| 5,010 |
| 5,697 |
| 10,707 |
|
| Operating (loss) income | (321 | ) | (85 | ) | (406 | ) | 1,601 |
| (54 | ) | 1,547 |
| 2,221 |
| (39 | ) | 2,182 |
| |
| Operating income (loss) | | 1,920 |
| (75 | ) | 1,845 |
| (321 | ) | (85 | ) | (406 | ) | 1,601 |
| (54 | ) | 1,547 |
|
| Interest expense | (671 | ) | (2 | ) | (673 | ) | (588 | ) | (1 | ) | (589 | ) | (540 | ) | (1 | ) | (541 | ) | (738 | ) | (1 | ) | (739 | ) | (671 | ) | (2 | ) | (673 | ) | (588 | ) | (1 | ) | (589 | ) |
| 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 |
| |
| Other income | | 119 |
| 76 |
| 195 |
| 107 |
| 87 |
| 194 |
| 93 |
| 55 |
| 148 |
|
| Income (loss) before income taxes | | 1,301 |
| — |
| 1,301 |
| (885 | ) | — |
| (885 | ) | 1,106 |
| — |
| 1,106 |
|
| Income tax benefit | | (229 | ) |
|
| (229 | ) | (696 | ) | — |
| (696 | ) | (30 | ) | — |
| (30 | ) |
| Net income (loss) | | 1,530 |
| — |
| 1,530 |
| (189 | ) | — |
| (189 | ) | 1,136 |
| — |
| 1,136 |
|
| Preferred and preference stock dividend requirements | 121 |
| — |
| 121 |
| 124 |
| — |
| 124 |
| 123 |
| — |
| 123 |
| 121 |
|
|
| 121 |
| 121 |
| — |
| 121 |
| 124 |
| — |
| 124 |
|
| 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 |
| |
| Net income (loss) available for common stock | | $ | 1,409 |
| $ | — |
| $ | 1,409 |
| $ | (310 | ) | $ | — |
| $ | (310 | ) | $ | 1,012 |
| $ | — |
| $ | 1,012 |
|
| Net income (loss) available for common stock | | | $ | 1,409 |
| | | $ | (310 | ) | | $ | 1,012 |
|
| Less: Non-core items | | | | | | | | | | | | | | |
| Wildfire insurance fund expense | | | (109 | ) | | | — |
| | — |
|
| Wildfire-related claims, net of recoveries | | (1,825 | ) | | | — |
| | — |
| | (157 | ) | | | (1,825 | ) | | — |
|
| Impairment and other | | 9 |
| | | (448 | ) | | — |
| | (115 | ) | | | 9 |
| | (448 | ) |
| Re-measurement of deferred taxes | | — |
| | | (33 | ) | | — |
| | 88 |
| | | — |
| | (33 | ) |
| Settlement of California tax audits | | 66 |
| | | — |
| | — |
| |
|
| | | 66 |
| | — |
|
Core earnings2 | | $ | 1,440 |
| | | $ | 1,493 |
| | | $ | 1,376 |
| | $ | 1,702 |
| | | $ | 1,440 |
| | | $ | 1,493 |
|
| |
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
20182019 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—
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$118 million is primarily due to:
An increase in CPUC-related revenue of approximately $241$100 million relatedprimarily due to the adoption of the 2018 GRC final decision, including the application of the decision retroactively to January 1, 2018, as discussed above.
An increase of $38 million in authorizedFERC-related revenue fromprimarily due to the escalation mechanism set forth in the 2015 GRC decisionsettlement of SCE's 2018 Formula Rate proceeding, rate base growth and $32 million of higher operating costs subject to balancing account treatment, (primarilypartially offset by lower recoveries from FERC customers for wildfire-related claims in depreciation expense below). These increases2019 as compared to 2018.
A decrease in other operating revenue of $20 million primarily due to rate adjustments implemented in the second quarter of 2019.
Higher operation and maintenance expenses of $101 million primarily due to expenses related to wildfire mitigation activity that were not deferred as regulatory assets. Activities driving higher expenses included higher inspection, preventive maintenance and vegetation management costs in non-high fire risk areas. SCE has not recorded regulatory assets for $119 million of 2019 wildfire mitigation costs as there is no current precedent for recovery of these costs, but SCE is seeking recovery of these costs through a separate track of the 2021 GRC. Those costs were partially offset by $33 million of
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 amortizationimpact of the regulatory asset associated withadoption of the Coolwater-Lugo transmission project and a $8 million reduction to FERC revenue2018 GRC final decision primarily due to a change in estimate undercapitalization rates and the FERC formula rate mechanism.timing of regulatory deferral and cost recovery of incremental wildfire insurance expenses.
An increaseCharges of $20$255 million and $2.7 billion recorded in 2019 and 2018, respectively, for wildfire-related claims, net of expected insurance recoveries.
Expense of $152 million for other operating revenue resultinginsurance protection from refundsthe Wildfire Insurance Fund following SCE's election to customers recordedparticipate in 2016 dueand contribute to the retroactive extension of bonus depreciation in the PATH Act of 2015.fund. See "Management Overview—Southern California Wildfires and Mudslides" for further information.
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$140 million primarily related to the change in depreciation rates and amortization on transmission and distribution investments, partially offset by amortizationthe impact of disallowed historical capital expenditures from the adoption of the regulatory asset2018 GRC final decision.
Higher impairment and other of $171 million primarily related to Coolwater-Lugo plant recordedthe disallowed historical capital expenditures 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.SCE's 2018 GRC final decision, as discussed above.
Higher interest expense of $48$67 million primarily due to increased borrowings and higher interest on balancing account overcollections in 2017.borrowings.
Higher other income and expenses of $19$12 million primarily due to higher AFUDC equity income. See "Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses" for further information.interest income from various balancing accounts.
Lower income taxestax benefits of $286$467 million primarily due to the following:
Higher non-core incomeLower tax benefits in 2017benefit of $235$612 million due to higher pre-tax income.
Lower tax benefit of $66 million due to the impairment and other charges related2018 settlement of the 1994 – 2006 California tax audit.
Higher tax benefit of $211 million primarily due to the Revised San Onofre Settlement Agreement, partially offset by $33 million income tax expense related tochanges in the re-measurementallocation of deferred taxes resulting fromtax re-measurement between customers and shareholders as a result of a CPUC resolution issued in February 2019, the implementationadoption of Tax Reform.
Higher incomethe 2018 GRC final decision and 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.benefit on property-related items.
Cost-Recovery Activities
20182019 vs 20172018
Cost-recovery activities were primarily affected by the following:
HigherLower purchased power and fuel costs of $533$567 million primarily driven by higher powerlower load related to customer departures to CCAs and gas prices and volume experienced in 2018 relative to 2017,cooler weather, partially offset by higherlower congestion revenue right credits, lower capacity costs, proceeds fromhigher contract amendmentstermination charges and the receiptabsence of settlement funds received in 2018 from counterparties related to the California energy crisis.
LowerHigher operation and maintenance expense subject to balancing accountsexpenses of $94$133 million primarily driven by reduced spending on energy efficiency programsthe authorization to recover 2018 wildfire insurance costs that had been deferred as regulatory assets and the timing of revenue recognition associated with costs tracked through memorandum accounts,higher transmission access charges, partially offset by higher transmission access charges.lower employee-related expenses subject to balancing account treatment and lower spending on public programs.
HigherLower other income and expenses of $32$11 million primarily driven by higherlower 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 employeeSCE's other post-retirement 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.plans. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for further information.
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales) was $11.4 billion, $11.7 billion and $11.4 billion for 2019, 2018 and $10.9 billion for 2018, 2017, and 2016, respectively.
The 20182019 revenue increasedecrease is primarily related to higher purchased powerlower load related to customer departures to CCAs and fuel costs driven by higher power and gas prices and volume experienced in 2018 relative to 2017,cooler weather, partially offset by higher congestionCPUC revenue right credits and lower revenue for San Onofre resulting fromdue to the Revised San Onofre Settlement Agreement.adoption of the 2018 GRC final decision. 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$467 million in 20182019 compared to 2017 and decreased by $286 million in 2017 compared to 2016.2018. The effective tax rates were (78.6)%, (2.7)(17.6)% and 14.6%(78.6)% for 2018, 20172019 and 2016,2018, respectively. SCE's effective tax rate is below the federal statutory rate of 21% for 20182019 and 35% for 2017 and 20162018 primarily due to the CPUC's ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences, which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense. The effective tax rate decrease in 2018 was2019 is primarily due to impact of higher pre-tax income and absence of the 2018 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 decreaseaudit 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,2018, partially offset by lowerhigher tax benefits related toon property-related items recorded as a $133 million revenue refund toresult of 2018 GRC final decision and the changes in the allocation of excess deferred tax re-measurement between customers that was recordedand shareholders as a result of a CPUC resolution issued in 2016.February 2019.
See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for a reconciliation of the federal statutory rate to the effective income tax rates and "Management Overview—Permanent Retirement of San Onofre" above for more information.rates.
Edison International Parent and Other
Results of operations for Edison International Parent and Other includes amounts from other subsidiaries that are not significant as a reportable segment as well as intercompany eliminations.
Loss from Continuing Operations
The following table summarizes the results of Edison International Parent and Other:
| | | | Years ended December 31, | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Edison Energy Group and subsidiaries | $ | (78 | ) | | $ | (26 | ) | | $ | (38 | ) | $ | (24 | ) | | $ | (78 | ) | | $ | (26 | ) |
| Corporate expenses and other subsidiaries | (69 | ) | | (421 | ) | | (39 | ) | (101 | ) | | (69 | ) | | (421 | ) |
| Total Edison International Parent and Other | $ | (147 | ) | | $ | (447 | ) | | $ | (77 | ) | $ | (125 | ) | | $ | (147 | ) | | $ | (447 | ) |
The loss from continuing operations of Edison International Parent and Other decreased $300$22 million in 20182019 compared to 2017 primarily due to:
Lower income tax expense in 2018 primarily due to $433an after-tax loss of $50 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 taxinterest expense of $433 million in 2017 from the re-measurement of deferred taxes as a result of Tax Reform.increased borrowings in 2019.
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.
LIQUIDITY AND CAPITAL RESOURCES
SCE
SCE's ability to operate its business, fund capital expenditures and implement its business strategy is dependent upon its cash flow and access to the bank and capital markets. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, interest obligations, dividend payments to and equity contributions from Edison International, andobligations to preferred and preference shareholders, and the outcome of tax and regulatory matters.
As discussed
During 2019 SCE, along with Edison International Parent, engaged in a financing program to enable SCE to make an initial contribution of $2.4 billion to the Wildfire Insurance Fund in September 2019, fund a significant increase in wildfire mitigation expenditures, and increase the equity portion of SCE's capital structure to 52% by year-end 2020 based on SCE's current 37-month backwards looking compliance period. The increase in the equity portion of SCE's capital structure was authorized in the 2020 Cost of Capital proceeding in December 2019. See "Management Overview,Overview—2020 Cost of Capital Application." Tax Reform is expected
The 2019 financing program included $3.3 billion of equity contributions from Edison International Parent to lower rates charged to customersSCE, as well as SCE issuing $2.3 billion of first and refunding mortgage bonds. Additionally, in February 2019, SCE borrowed $750 million under a term loan which will resultwas repaid in less cash available to fund operations. full in April 2019.
In the next 12 months, SCE expects to continue to fund its cash requirements through operating cash flows, bank and capital market financings, and equity contributions from Edison International Parent, as needed.needed, while continuing to increase the equity portion of its capital structure. SCE also expects to repurchase or redeem preferred or preference stock to reduce the preferred equity component of the capital structure to 5% in line with the capital structure authorized in the 2020 Cost of Capital proceeding. See "Management Overview—2020 Cost of Capital Application." SCE also has availability under its credit facilitiesfacility to fund cash requirements.
SCE's long-term issuer credit ratings remain at investment grade levels after downgrade actions taken bylevels. In the third quarter of 2019, the major credit agencies changed SCE's outlook from negative to stable due to the passage of AB 1054 and the establishment of the Wildfire Insurance Fund, which provided the AB 1054 Liability Cap and the new standard that the CPUC must apply when assessing the prudency of a utility in 2018wildfire-related cost recovery proceedings. For further information, see "Management Overview—Southern California Wildfires and early 2019.Mudslides." The following table summarizes SCE's current, long-term issuer credit ratings and outlook from the major credit rating agencies:
|
| | | | |
| | | Moody's | Fitch | S&P |
| Credit Rating | | A3Baa2 | BBB+BBB- | BBB |
| Outlook | | Under Review for DowngradeStable | NegativeStable | Watch NegativeStable |
SCE's credit ratings may be further affected if, among other things, regulators fail to successfully implement AB 1054 in a consistent and credit supportive manner or the Wildfire Insurance Fund is depleted by 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 byclaims from catastrophic wildfires substantially caused by utility equipment.wildfires. Credit rating downgrades increase the cost and may impact the availability of short-term and long-term borrowings, including commercial paper, credit facilities, bond financings or other borrowings. In addition, some of SCE's power procurement contracts would require SCE to pay related liabilities or post additional collateral if SCE's credit rating were to fall below investment grade rating from the major credit rating agencies.grade. Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade is $22are $44 million as of December 31, 2018.2019. In addition, if SCE's credit rating falls below investment grade, it may be required to post up to $50 million in collateral in connection with its environmental remediation obligations, within 120 days of the end of the fiscal year in which the downgrade occurs. Furthermore, if SCE was downgraded below investment grade, counterparties may also institute new collateral requirements for future transactions. For further details, see "—Margin and Collateral Deposits."
Available Liquidity
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, 2018,2019, SCE had $2.1approximately $2.3 billion available under its $3.0 billion credit facility. TheIn June 2019, SCE extended its credit facility is availablethrough May 2024, pursuant to an option to extend, and may extend its credit facility for borrowing needs until May 2023, and contains two 1-year extension options. In February 2019, SCE issued a $750 million term loan andone
additional year with 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."lenders' approval.
SCE may finance balancing account undercollections and working capital requirements to support operations and capital expenditures with commercial paper, its credit facility or other borrowings, subject to availability in the bank and capital markets. SCE expects to finance approximately $1.6 billion of wildfire mitigation capital expenses by issuing securitized bonds. Prior to issuance of such bonds, other debt instruments may be used to temporarily finance the expenditures.
As necessary, SCE will utilize its available liquidity, capital market financings, other borrowings or parent company equity contributions 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 (seeEvents. For further information, see "Management Overview—Southern California Wildfires
and Mudslides" for further information).Mudslides."
Debt Covenant
The debt covenant in SCE's credit facility limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At December 31, 2018,2019, SCE's debt to total capitalization ratio was 0.500.47 to 1.
At December 31, 2018,2019, SCE was in compliance with all financial covenants that affect access to capital.
Capital Investment Plan
Major Transmission Projects
A summary of SCE's most significant transmission and substation construction projects during the next three years is presented below. The timing of the projects below is subject to timely receipt of permitting, licensing and regulatory approvals.
| | | Project Name | Project Lifecycle Phase | Direct Expenditures (in millions)1 | Inception to Date (in millions)1 | Scheduled In-Service Date | 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 | Construction | $840 | $484 | 2021 |
| Mesa Substation | Construction | $646 | $268 | 2022 | Construction | 646 | 373 | 2022 |
| Alberhill System | Licensing | $486 | $39 | —2 | |
| Riverside Transmission Reliability | Licensing | $441 | $9 | 2023 | |
Alberhill System2 | | Licensing | 486 | 41 | —2 |
Riverside Transmission Reliability3 | | Licensing | 451 | 11 | 2024 |
| Eldorado-Lugo-Mohave Upgrade | Licensing | $233 | $59 | 2021 | Licensing | 246 | 93 | 2021 |
| |
1 | Direct expenditures include direct labor, land and contract costs incurred for the respective projects and exclude overhead costs that are included in the capital expenditures forecast discussed in "Management Overview—Capital Program." |
| |
2 | Includes the original estimated project cost for Alberhill. In January 2020, SCE submitted a supplemental analysis to the CPUC which included alternative projects as well as an update to the original project cost. SCE is unable to predict the timing of a final CPUC decision, and the corresponding in-service date, in connection withand what the final project costs will be for the Alberhill System Project. |
3 While the Riverside Transmission Reliability Project total cost is currently estimated to be $451 million, the CPUC issued a proposed decision, which if adopted would increase the project cost to $584 million. See discussion in "Riverside Transmission Reliability" below for further information.
West of Devers
The West of Devers Project consists of upgrading and reconfiguring approximately 48 miles of existing 220 kV
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 220kV220-kV transmission lineline. Construction is on plan and SCE expects to complete construction byin 2021.
Mesa Substation
The Mesa Substation Project consists of replacing the existing 220 kV220-kV Mesa Substation with a new 500/220 kV220-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 Projectproject largely consistent with SCE's proposal and rejected alternative project configurations proposed by CPUC staff. Construction on the initial phase of construction (a new 220- kV substation) commenced in October 2017. In October 2017,2019, SCE awarded the competitive bid forachieved first energization of the new 220kV portionsubstation. The remaining phases of substation construction. SCE updated the expected cost of the Project dueconstruction are anticipated to schedule delays and scope changes. The remainder (500kV portion of substation construction) will be put out for competitive bid by early 2019 and SCE expects that costs associated with the Projectproject may change as a result of the competitive bidding process. SCE anticipates project completion in the first quarter of 2022.
Alberhill System
The Alberhill System Project would consist of constructing a new 500-kV substation, two 500-kV transmission lines to connect the proposed substation to the existing Serrano-Valley 500-kV transmission line, telecommunication equipment and subtransmission lines in unincorporated and incorporated portions of western Riverside County. The Projectproject was designed to meet long-term forecasted electrical demand in the proposed Alberhill System Project area and to increase electrical system reliability.reliability and resiliency. In April 2018 and July 2018, the CPUC issued a proposed decision and an alternate proposed decision, both denying SCE's ability to construct the Alberhill System Project based on a perceived lack of need. SCE filed comments on both proposed decisions requesting that the CPUC grant the certificate of public convenience and necessity for the Alberhill
System Project. In August 2018, the CPUC issued a decision that did not deny or approve the Alberhill System Project but directed SCE to submit supplemental information on the Alberhill System Project including detailsbut not limited to a load forecast and cost benefit analysis of demand and load forecasts and possibleseveral alternatives to the proposed project. Ongoing capital spending has been deferred as a result of the CPUC request for additional information and alternatives.information. In January 2020, SCE submitted a supplemental analysis to the CPUC for the Alberhill System Project including several alternatives to the proposed project as well as an update to the original project cost. A final decision on the Alberhill System Project is pending based on the supplemental analysis. Given the uncertainty
associated with the resolution of the permitting process, potential revisions to the project have not been reflected in total direct expenditures. SCE continues to believe the Alberhill System Projecta system solution is needed andfor the project area but is unable to predict the timing of a final CPUC decision in connection with the Alberhill System Project.Project proceeding.
Approximately 48% of the Alberhill System Project costs spent to date would be subject to recovery through CPUC revenue and 52% through FERC revenue. In October 2017, SCE obtained approval from the FERC for abandoned plant treatment for the Alberhill System Project, which allows SCE to seek recovery of 100% of all prudently-incurredprudently 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$46 million of capital expenditures, including overhead costs, as of December 31, 2018,2019, of which approximately $31$34 million may not be recoverable if the project is cancelled.
Riverside Transmission Reliability
The Riverside Transmission Reliability Project is a joint project between SCE and Riverside Public Utilities (RPU)("RPU"), the municipal utility department of the City of Riverside. While RPU would be responsible for constructing some of the Project'sproject's facilities within Riverside, SCE's portion of the Projectproject 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 Projectproject 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 Projectproject was originally developed, SCE informed the CPUC in August 2016 that it supports revisions to the proposed Project. In AprilOctober 2018, the CPUC issued a subsequentan environmental impact report which includedthat identified 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,January 2020, SCE received a proposed decision from the CPUC issuedthat would approve the final environmental report confirmingproject consistent with 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 certificateIf adopted, the cost of public convenience and necessity in the first quarter of 2020.revised project is estimated to be $584 million.
Eldorado-Lugo-Mohave Upgrade
The Eldorado-Lugo-Mohave Upgrade Project will increase capacity on existing transmission lines to allow additional renewable energy to flow from Nevada to southern California. The Projectproject 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 kV500-kV transmission lines by constructing two new capacitors along the lines; raise transmission tower heights to meet ground clearance requirements; and install communication wirefiber optics on ourthe transmission lines to allow for communication
provide communications 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.A final CPUC decision is anticipated during 2020. In JanuaryApril 2019, as directed by the CPUC, directed SCE to filefiled an amended application for a certificate of public convenience and necessity.necessity with the CPUC, which included total project costs of $257 million. A subsequent change to the project work scope reduced the project total cost to $246 million, a decrease of $11 million as compared to the estimate provided in the amended application.
Grid Development - Wildfire Mitigation
See "Management Overview—Wildfire Mitigation and Wildfire Insurance Expenses."
Grid Development - Transportation Electrification
Medium- and Heavy-Duty Vehicle Transportation Electrification
In January 2017, SCE filed an application with the CPUC requesting approval of transportation electrification programs to accelerate the adoption of electric transportation, which is currently assessingcritical 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 impactmodel developed for SCE's Charge Ready program, as well as six pilot projects to be considered on an accelerated basis. In January 2018, the CPUC issued a final decision approving five pilot projects with a budget of $16 million ($10 million capital) in 2016 dollars. In May 2018, the CPUC issued a final decision approving the five-year program, with certain modifications, to install charging infrastructure to support the electrification of 8,490 medium- and heavy-duty electric vehicles at 870 sites, which must be fully contracted for by 2024. The final decision includes an approved five-year budget of $356 million ($242 million capital) in nominal dollars. SCE expects to propose additional programs and pilots in the future. SCE's 2020 capital plan contemplates $4 million of medium- and heavy-duty vehicle transportation electrification spending.
Charge Ready Program
In January 2016, the CPUC approved SCE's $22 million Charge Ready Program Pilot, which allows SCE to install light-duty electric vehicle charging infrastructure, provide rebates to offset the cost of qualified customer-owned charging stations, and implement a supporting marketing, education and outreach campaign. As of December 31, 2019, SCE had executed agreements and reserved funding for 81 sites to deploy 1,301 charge ports under this pilot. The results of this decision onpilot helped shape Charge Ready 2, the timing and costsecond phase 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 RateCharge Ready program.
In June 2018, SCE provided its preliminary 2019 annual transmission revenue requirement updatefiled an application to interested parties. The update providedobtain 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 for48,000 new electric vehicle charging ports as part of a decrease in SCE's transmission revenue requirement of $131 million, or 11% from amounts currently authorized in rates, subject to settlement proceduresfour-year program that will also include a marketing, education and refund. The decrease is primarily due to loweringoutreach campaign. In December 2018, 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.
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 ultimatelyCPUC approved by FERC.
Energy Efficiency Incentive Mechanism
SCE has requested an award of approximately $11$22 million in incentivesbridge funding to continue the Charge Ready Program Pilot while the Charge Ready 2 application remains pending. As of December 31, 2019, with this additional funding, SCE had executed agreements and reserved funding for activities in program years 2016 and 2017. SCE anticipates that the CPUC will consider66 additional sites to deploy 1,463 additional charge ports. SCE's requested award during the first or second quarter2020 capital plan contemplates $8 million of 2019.bridge Charge Ready Program Pilot spending.
Decommissioning of San Onofre
The decommissioning of a nuclear plant requires the management of three related activities: radiological decommissioning, non-radiological decommissioning and the management of spent nuclear fuel. SCE has engaged a decommissioning general contractor to undertake a significant scope of decommissioning activities for Units 1, 2 and 3 at San Onofre. The decommissioning of San Onofre is expected to take many years.
Decommissioning of San Onofre Unit 1 began in 1999 and the transfer of spent nuclear fuel from Unit 1 to dry cask storage in the Independent Spent Fuel Storage Installation ("ISFSI") was completed in 2005. Major decommissioning work for Unit 1 has been completed except for reactor vessel disposal and certain underground work. Some spent nuclear fuel from Units 2 and 3 also was transferred to the ISFSI between 2007 and 2012. The initial activity phase of radiologicalRadiological 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, theThe spent fuel transfer operations were suspended on August 3, 2018 due to an incident that occurred when an SCE contractor was loading a spent fuel canister into the ISFSI. The incident did not result in any harm to the public or workers and the canister was subsequently safely loaded into the ISFSI. In May 2019, after an extensive review, the NRC determined that fuel loading can be safely resumed at San Onofre. SCE cannot predict whencommenced fuel transfer operations at San Onofre will recommence. SCE is in July 2019. In October 2019, the process of obtainingCalifornia Coastal Commission approved SCE's application for the environmental permitsCoastal Development Permit, the principle discretionary permit required to start major radiological decommissioning activities at San Onofre Units 2 and 3.Onofre. SCE cannot predict when allplans on commencing major decommissioning activities in 2020 in accordance with the terms of the necessary permits will be obtained.permit, subject to any court rulings in a proceeding brought in
December 2019 to challenge the California Coastal Commission's issuance of the permit.
In December 2018, SCE updated its decommissioning cost estimate for decommissioning activities to be completed at San Onofre Units 2 and 3 to $3.4 billion (SCE share is $2.5 billion) in 2017 dollars. The decommissioning cost estimate includes costs through the respective expected decommissioning completion dates, currently estimated to be in 2051 for San Onofre Units 2 and 3. The decommissioning cost estimate is subject to a number of uncertainties including the cost of disposal of nuclear waste, cost of removal of property, site remediation costs as well as a number of other assumptions and estimates, including when the federal government will provide for either interim or permanent off-site storage of spent nuclear fuel enabling the removal and transport of spent fuel canisters from the San Onofre site, as to which there can be no assurance. The cost estimate is subject to change as decommissioning proceeds and such changes may be material. The CPUC will conduct a reasonableness review for costs for each year. SCE's share of the San Onofre decommissioning costs recorded during 20182019 were $140$172 million.
SCE had nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $2.6$2.8 billion as of December 31, 2018.2019. Based upon the resolution of a number of uncertainties, including the cost and timing of nuclear waste disposal, the time it will take to obtain required permits, cost of removal of property, site remediation costs, the financial performance of the nuclear decommissioning trust fund investments, as well as the resolution of a number of other assumptions and estimates, additional contributions to the nuclear decommissioning trust funds may be required. In the event thatIf additional contributions to the nuclear decommissioning trust funds become necessary, SCE will seek recovery of such additional funds through electric rates and any such recovery will be subject to a reasonableness review by the CPUC. Cost increases resulting from contractual disputes or significant permitting delays, among other things, could cause SCE to materially overrun the decommissioning cost estimate and could materially impact the sufficiency of trust funds.
SCE Dividends
CPUC holding company rules require that SCE's dividend policy be established by SCE's Board of Directors on the same basis as if SCE were a stand-alone utility company, and that the capital requirements of SCE, as deemed to be necessary to meet SCE's electricity service obligations, shall receive first priority from the Boards of Directors of both Edison International and SCE. In addition, the CPUC regulates SCE's capital structure which limits the dividends it may pay to its shareholders. Under
Prior to January 1, 2020, under SCE's interpretation of CPUC regulations and capital structure decisions, the common equity component of SCE's capital structure mustwas required to remain at or above 48% on a weighted average basis over the 37-month period that SCE's capital structure iswas in effect for ratemaking purposes. As allowed under the Revised San Onofre Settlement Agreement, whichpurposes and SCE 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%. Effective January 1, 2020, the common equity component of SCE's authorized capital structure was increased from 48% to 52%. For further information, see "Management Overview—2020 Cost of Capital Application." Under AB 1054, the impact of SCE's contributions to the Wildfire Insurance Fund are excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. For further information, see "Management Overview—Southern California Wildfires and Mudslides."
On February 28, 2019, SCE is submittingsubmitted 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 seekingrequested a limited waiver to exclude wildfire-related charges and wildfire-related debt issuances from its equity ratio calculations until a determination regarding cost recovery is made. The CPUC has ruled that while the application is pending resolution, SCE must notify the CPUC if an adverse financial event reduces SCE's spot equity ratio by more than one percent from the level most recently filed with the CPUC in the proceeding. The last spot equity ratio SCE filed with the CPUC in the proceeding was 45.2% as of December 31, 2018. Under the CPUC's rules, SCE will not be deemed to be in violation of the equity ratio requirement, and therefore may continue to issue debt and dividends, while the waiver application is pending resolution. For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides." At December 31, 2019, without excluding the $2.0 billion after-tax wildfire-related charges incurred in 2018 and 2019, SCE's 37-month average common equity component of total capitalization was 48.5% and the maximum additional dividend that SCE could pay to Edison International under this limitation was $179 million, resulting in a restriction on net assets of approximately $17.6 billion. If the wildfire-related charges were excluded at December 31, 2019, SCE's 37-month average common equity component of total capitalization would have been 49.6%.
As a California corporation, SCE's ability to pay dividends is also governed by 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, if any, in order to liquidate stock senior to the shares receiving the dividend. Additionally, a California corporation may not declare a dividend if it is, or as a result of the dividend would be, likely to be unable to meet its liabilities as they mature. Prior to declaring dividends, SCE's Board of Directors evaluates available information, including when applicable, information pertaining to the 2017/2018 Wildfire/Mudslide Events, to ensure that the California law requirements for the declarations are met. On February 28, 2019,27, 2020, SCE declared a dividend to Edison International of $200$269 million.
The timing and amount of future dividends are also dependent on a number of other factors including SCE's requirements to fund other obligations and capital expenditures, and its ability to access the capital markets, and generate operating cash flows and earnings. If SCE incurs significant costs related to catastrophic wildfires, including the 2017/2018 Wildfire/Mudslide Events, and is unable to recover such costs through insurance, the Wildfire Insurance Fund (for fires after July 12, 2019), or electric ratesfrom customers 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.
Margin and Collateral Deposits
Certain derivative instruments, power and energy procurement contracts and other contractual arrangements contain collateral requirements. In addition, certain environmental remediation obligations require financial assurance that may be in the form of collateral postings. Future collateral requirements may differ from the requirements at December 31, 20182019 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, 2018.2019 if SCE's credit rating had been downgraded to below investment grade as of that date. The table below also provides the potential collateral that could be required due to adverse changes in wholesale power and natural gas prices over the remaining lives of existing power and energy procurement contracts.
|
| | | | |
| (in millions) | | |
Collateral posted as of December 31, 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 |
|
|
| | | | |
| (in millions) | | |
Collateral posted as of December 31, 20191 | | $ | 178 |
|
Incremental collateral requirements for purchased power and fuel contracts resulting from a potential downgrade of SCE's credit rating to below investment grade2 | | 44 |
|
Incremental collateral requirements for purchased power and fuel contracts resulting from adverse market price movement3 | | 27 |
|
| Posted and potential collateral requirements | | $ | 249 |
|
| |
1 | Net collateral provided to counterparties and other brokers consisted $191of $154 million in letters of credit and surety bonds and $7$24 million of cash collateral which was offset against net derivative liabilitiesreflected in "Other current assets" on the consolidated balance sheets. |
| |
2 | If SCE's credit ratings were to fallrating fell below investment grade, asexisting purchased power and fuel contracts would require $44 million of December 31, 2018,incremental collateral. Counterparties may also institute new collateral requirements, applicable to future transactions, at the time of a downgrade. Furthermore, SCE may also be required to post up to $50 million in collateral by April 30, 2019 related toin connection with its environmental remediation obligations.obligations, within 120 days of the end of the fiscal year in which the downgrade occurs. |
| |
3 | Incremental collateral requirements were based on potential changes in SCE's forward positions as of December 31, 20182019 due to adverse market price movements over the remaining lives of the existing power and fuel contracts using a 95% confidence level. |
Regulatory Balancing and Memorandum Accounts
SCE's cash flows are affected by regulatory balancing and memorandum accounts overcollections or undercollections. Overcollections and undercollections represent differences between cash collected in current rates for specified forecasted costs and the costs actually incurred. With some exceptions, SCE seeks to adjust rates on an annual basis or at other designated times to recover or refund the balances recorded in its balancing accounts. Undercollections or overcollections in these balancing and memorandum accounts impact cash flows and can change rapidly. Undercollections and overcollections generally accrue interest based on a three-month commercial paper rate published by the Federal Reserve.
As of December 31, 2018,2019, SCE had regulatory balancing account net overcollections of $1.3 billion,$365 million for regulatory balancing and memorandum accounts, primarily consisting of overcollections related to public purpose-related and energy efficiency program costs and BRRBA.BRRBA, offset by undercollections related to wildfire risk related costs and PABA. Overcollections related to public purpose-related programs may decrease as costs are incurred to fund programs established by the CPUC. Overcollections related to BRRBA are expected to decrease as refunds are provided to customers in 2019.2020. SCE is currently incurring wildfire-related spending at levels significantly exceeding amounts authorized in the 2018 GRC and has recognized regulatory assets for certain of these costs. Total spending on wildfire mitigation is expected to continue at higher levels in 2020 and beyond. Undercollections related to PABA are expected to decrease through the implementation of the annual ERRA and PABA review proceeding in 2020. See "Notes to Consolidated Financial Statements—Note 11. Regulatory Assets and Liabilities" for further information.
Edison International Parent and Other
In the next 12 months, Edison International expects to fund its net cash requirements through bank and capital market and bank financings, including by issuing additional debt and equity, 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,June 2019, Edison International declaredParent extended its credit facility through May 2024, pursuant to an option to extend, and may extend the credit facility for one additional year with the lenders' approval. At December 31, 2019, Edison International Parent's entire $1.5 billion credit facility was available for borrowing.
During 2019, Edison International Parent engaged in a dividendfinancing program to support SCE's initial contribution to the Wildfire Insurance Fund in September 2019, fund SCE's wildfire mitigation expenditures, and increase the equity portion of $0.6125 per shareSCE's capital structure. This included issuing 2.8 million shares of common stock for net proceeds of $198 million through the ATM program and issuing 32.2 million shares of common stock for net proceeds of $2.2 billion in an underwritten offering during 2019. For further details, see "Notes to be paid onConsolidated Financial Statements—Note 14. Equity." Edison International Parent also issued $1.4 billion of senior notes during 2019. The proceeds of these financing activities allowed Edison International to contribute $3.3 billion to SCE as equity contributions and repay a $1.0 billion term loan. The term loan was borrowed in April 30,2019 and the proceeds of the term loan were contributed to SCE largely to enable repayment of SCE's February 2019 term loan. Edison International Parent's term loan was repaid in full in December 2019.
At December 31, 2019, the current portion of Edison International Parent’s long-term debt included senior notes of $400 million due in April 2020.
Edison International Parent and Other's liquidity and its ability to pay operating expenses, satisfy debt obligations and pay dividends to common shareholders are dependent on access to the bank and capital markets, dividends from SCE, realization of tax benefits and its ability to meet California law requirements for the declaration of dividends. Prior to declaring dividends, Edison International's Board of Directors evaluates available information, including when applicable, information pertaining to the 2017/2018 Wildfire/Mudslide Events, to ensure that the California law requirements for the declarations are met. For information on the California law requirements on the declaration of dividends, see "—SCE—SCE Dividends."
Edison International intends to maintain its target payout ratio of 45% – 55% of SCE's core earnings, subject to the factors identified above.
Edison International may finance its ongoing cash requirements, including common stock dividends, working capital requirements, payment of obligations, and capital investments, including capital contributions to subsidiaries, with short-term or other financings, subject to availability in the bank and capital markets.
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. TheA 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, 2018,2019, 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, 2018,2019, Edison International Parent was in compliance with all financial covenants that affect access to capital.
Edison International Parent's long-term issuer credit ratings remain at investment grade levels after downgrade actions taken by the major credit rating agencies in 2018 and early 2019. In the third quarter of 2019, the major credit agencies changed Edison International Parent's outlook from negative to stable, due to the passage of AB 1054 and the establishment of the Wildfire Insurance Fund, which provided the AB 1054 Liability Cap and the new standard that the CPUC must apply when assessing the prudency of a utility in wildfire-related cost recovery proceedings. The following table summarizes Edison International Parent's current, long-term issuer credit ratings and outlook from the major credit rating agencies:
|
| | | | |
| | | Moody's | Fitch | S&P |
| Credit Rating | | Baa1Baa3 | BBB+BBB- | BBB |
| Outlook | | Under Review for DowngradeStable | NegativeStable | Watch NegativeStable |
Edison International Parent's credit ratings may be further affected if, among other things, regulators fail to successfully implement AB 1054 in a consistent and credit supportive manner or the Wildfire Insurance Fund is depleted by 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 byclaims from catastrophic wildfires substantially caused by utility equipment.wildfires. Credit rating downgrades increase the cost and may impact the availability of short-term and long-term borrowings, including commercial paper, credit facilities, note financings or other borrowings.
Net Operating Loss and Tax Credit Carryforwards
Edison International has approximately $1.2$1.3 billion of tax effected net operating loss and tax credit carryforwards at December 31, 20182019 (after offsetting $178$212 million of unrecognized tax benefits and $212 million of Capistrano Wind net operating loss and tax credit carryforwards), which are available to offset future consolidated tax liabilities. See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for further information regarding taxes payable to Capistrano Wind. TheForecast monetization has been delayed, mainly due to anticipated future payment of wildfire claims and the contribution to the Wildfire Insurance Fund as described in AB 1054. Edison International expects to utilize its net operating loss and tax credit carryforwards 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 2024.2027.
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 |
|
|
| | | | | | | | | | | |
| (in millions) | 2019 | | 2018 | | 2017 |
| Net cash (used in) provided by operating activities | $ | (91 | ) | | $ | 3,191 |
| | $ | 3,735 |
|
| Net cash provided by financing activities | 4,771 |
| | 616 |
| | 243 |
|
| Net cash used in investing activities | (4,678 | ) | | (4,300 | ) | | (3,503 | ) |
| Net increase (decrease) in cash, cash equivalents, and restricted cash | $ | 2 |
| | $ | (493 | ) | | $ | 475 |
|
| |
| Net cash 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 (Used in) Provided by Operating Activities
The following table summarizes major categories of net cash provided by operating activities as provided in more detail in SCE's consolidated statements of cash flows for 2019, 2018 2017 and 2016.2017:
| | | | Years ended December 31, | | Change in cash flows | Years ended December 31, | | Change in cash flows |
| (in millions) | 2018 | 20174 | 20164 | | 2018/2017 | 2017/2016 | 2019 | 2018 | 2017 | | 2019/2018 | 2018/2017 |
| Net (loss) income | $ | (189 | ) | $ | 1,136 |
| $ | 1,499 |
| |
| | |
| Net income (loss) | | $ | 1,530 |
| $ | (189 | ) | $ | 1,136 |
| |
| |
Non-cash items1 | 1,291 |
| 3,058 |
| 2,117 |
| | | 1,782 |
| 1,291 |
| 3,058 |
| | |
| Subtotal | $ | 1,102 |
| $ | 4,194 |
| $ | 3,616 |
| | $ | (3,092 | ) | $ | 578 |
| 3,312 |
| 1,102 |
| 4,194 |
| | 2,210 |
| (3,092 | ) |
| Contributions to Wildfire Insurance Fund | | (2,457 | ) | — |
| — |
| | (2,457 | ) | — |
|
Changes in cash flow resulting from working capital2 | (313 | ) | (148 | ) | 243 |
| | (165 | ) | (391 | ) | 298 |
| (313 | ) | (148 | ) | | 611 |
| (165 | ) |
| Regulatory assets and liabilities, net | (92 | ) | 4 |
| (292 | ) | | (96 | ) | 296 |
| (1,278 | ) | (92 | ) | 4 |
| | (1,186 | ) | (96 | ) |
Other noncurrent assets and liabilities, net3 | 2,494 |
| (315 | ) | (46 | ) | | 2,809 |
| (269 | ) | 34 |
| 2,494 |
| (315 | ) | | (2,460 | ) | 2,809 |
|
| Net cash provided by operating activities | $ | 3,191 |
| $ | 3,735 |
| $ | 3,521 |
| | $ | (544 | ) | $ | 214 |
| |
| Net cash (used in) provided by operating activities | | $ | (91 | ) | $ | 3,191 |
| $ | 3,735 |
| | $ | (3,282 | ) | $ | (544 | ) |
| |
1 | Non-cash items include depreciation and amortization, allowance for equity during construction, impairment and other, Wildfire Insurance Fund amortization expense, deferred income taxes and 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 billionchanges in liabilities for wildfire-related claims and an increase of $2.0 billion inwildfire-related insurance receivables in 2018 (offset in net loss above), andreceivables. Also includes 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 decreasedincreased in 20182019 by $3.1$2.2 billion from 2017 and2018. Net Income in 2019 increased by $1.7 billion primarily due to a $2.3 billion reduction in 2017 by $578 million from 2016. Excluding the $2.5 billion chargecharges for wildfire-related claims, net of expected recoveries from insurance and FERC customers in 2019 as compared to 2018, the decreaseadoption of the 2018 GRC final decision in 2018 was2019, higher FERC revenue due to the impactsettlement of SCE's 2018 Formula Rate proceeding and rate base growth in 2019, and the July 2017timing of regulatory deferral and cost recovery of capital decision on GRC revenue, higher operation and maintenance expenses related toincremental wildfire insurance premiums and vegetation management and higher net financing costs,expenses. These increases were partially offset by higher income tax benefits,inspection, preventive maintenance 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 financingvegetation management costs and higher non-cash items. The factors that impacted these items are discussed under "Results of Operations—SCE—Earning Activities."were not deferred as regulatory assets. Non-cash items included depreciation and amortization of $1.8 billion and $1.9 billion in 2019 and 2018, respectively, changes in deferred income taxes of $(243) million and investment tax credits of $(552) million $304in 2019 and 2018, respectively, an impairment charge of $170 million recorded in 2019 related to disallowed historical capital expenditures in SCE's 2018 GRC decision and $88Wildfire Insurance Fund amortization expense of $152 million recorded in 2018, 2017 and 2016, respectively, and impairment and other of $(12) million and $716 million in 2018 and 2017, respectively.2019.
Net cash used in operating activities was also impacted by cash outflow of $2.5 billion related to SCE's contributions to the Wildfire Insurance Fund in 2019. See "Notes to Consolidated Financial Statements—Note 12. Commitment and Contingencies" for further information.
Net cash inflow (outflow) for working capital was $298 million and $(313) million $(148) millionin 2019 and $243 million in 2018, 2017 and 2016, respectively. The net cash for each period was primarily related to timing of disbursements of $237 million and $(15) million $125 millionin 2019 and $45 million in
2018, 2017 and 2016, respectively, and changes in receivables from customers of $(73) million and $(288) million $163 millionin 2019 and $220 million in 2018, 2017 and 2016, respectively. Net cash for working capital also included insurance premium payments of $197$(471) million and $121$(197) million in 20182019 and 2017,2018, respectively, primarily for wildfire related coverage.wildfire-related coverage, partially offset by net tax refunds of $164 million and $57 million in 2019 and 2018, respectively.
Net cash provided by regulatory assets and liabilities, including changes in (under) overnet under collections of balancing accounts, was $(1,278) million and $(92) million $4 millionin 2019 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:
2019
BRRBA overcollections decreased by $300 million primarily due to refunds of prior overcollections (including incremental tax benefits) and current year undercollection due to rate changes delayed beyond January 1, 2019, offset by additional overcollection of distribution revenue to be refunded to customers over an 18-month period, starting in July 2019, as part of SCE's 2018 GRC final decision.
PABA was established in May 2019 to determine and pro-ratably recover from responsible bundled service and departing load customers the "above-market" costs of all generation resources that are eligible for cost recovery. Net undercollections for ERRA, PABA and the New System Generation Balancing Account decreased by $142 million primarily due to recovery of prior ERRA undercollections and overcollections of generation revenue occurring in 2019 and 2018 that are being refunded over an 18-month period, starting in July 2019, as part of SCE's 2018 GRC final decision. The cash inflow was partially offset by lower sales than forecasted in rates, higher than forecasted energy prices experienced in 2019, charges from CPUC-authorized contract terminations and refunds of prior overcollections from the New System Generation Balancing Account.
Lower cash due to elimination of approximately $360 million in a regulatory liability that was established in 2018 to record adjustments associated with the delay in the 2018 GRC decision. In May 2019, the CPUC approved the final decision in SCE's 2018 GRC, resulting in 2019 and 2018 overcollections being refunded to customers through BRRBA and PABA, as discussed above.
Additional undercollections of $596 million related to wildfire-related expenses that are probable of future recovery from customers, including wildfire risk mitigation costs, insurance premiums and service restoration and damage repair costs. See "Notes to Consolidated Financial Statements—Note 11. Regulatory Assets and Liabilities" for further information.
Higher cash due to $115 million of overcollections related to the timing of GHG auction revenue, low carbon fuel standard credit sales, and the related refunds and rebates to eligible customers.
Additional cash outflow due to refund of prior year overcollection of recovery of certain employee benefit related costs and reversal of TAMA overcollection as a result of adoption of the 2018 GRC final decision.
2018
BRRBA overcollections increased by $428 million primarily due to a $263 million reclassification of 2017 incremental tax benefits from TAMA to BRRBA (to be refunded in 2019) and higher sales than forecasted in rates, partially offset by a refund of 2016 incremental tax benefits.
Higher cash from increased regulatory liabilities of approximately $365 million primarily due to the delay in the 2018 GRC decision. During 2018, the amounts billed to customers were largely based on the 2017 authorized GRC revenue requirement, however, the amount of revenue recognized has been adjusted mainly for the July 2017 cost of capital decision and Tax Reform pending the outcome of the 2018 GRC and therefore, a regulatory liability has been established to record any associated adjustments.
Net undercollections for ERRA and the new system generation program were $741 million and $267 million at December 31, 2018 and 2017, respectively. Net undercollections increased $474 million during 2018 primarily due to an increase in costs due to higher than forecasted power and gas prices experienced in 2018 and higher load requirements than forecasted in rates, partially offset by an increase in cash due to recovery of prior year undercollections.
TAMA overcollections decreased by $287 million primarily due to a $263 million reclassification from TAMA to BRRBA to refund customers as discussed above.
Undercollections of $128 million related to the establishment, in the fourth quarter of 2018, of a wildfire expense memorandum account ("WEMA")WEMA to track wildfire relatedwildfire-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.
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 inprovided by other noncurrent assets and liabilities were primarily related to an increase of $232 million and $4.7 billion in liabilities for the 2017/2018 Wildfire/Mudslide Events related claims in 2019 and 2018, respectively, partially offset by the Local Public Entity Settlements payment of $360 million reduced by the subsequent insurance recovery of $290 million in 2019, and an increase of $2.0 billion in insurance receivables in 2018. Also includes net earnings from nuclear decommissioning trust investments ($41 million, $5567 million and $45$41 million in 2018, 20172019 and 2016,2018, respectively) and SCE's payments of decommissioning costs ($140 million, $236172 million and $168$140 million in 2018, 20172019 and 2016,2018, 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 2019, 2018 2017 and 2016.2017. Issuances of debt and preference stock and capital contribution from Edison International Parent are discussed in "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt"Agreements" and "—Note 13. Preferred and Preference Stock of Utility.14. Equity."
| | | (in millions) | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Issuances of first and refunding mortgage bonds, net of (discount) premium and issuance costs | $ | 2,692 |
| | $ | 1,011 |
| | $ | — |
| $ | 2,306 |
| | $ | 2,692 |
| | $ | 1,011 |
|
| Issuance of term loan | — |
| | 300 |
| | — |
| 750 |
| | — |
| | 300 |
|
| Repayment of term loan | | (750 | ) | | — |
| | — |
|
| Remarketing and issuances of pollution control bonds, net of issuance costs | — |
| | 134 |
| | — |
| — |
| | — |
| | 134 |
|
| Long-term debt matured or repurchased | (639 | ) | | (882 | ) | | (217 | ) | (82 | ) | | (639 | ) | | (882 | ) |
| Capital contributions from Edison International Parent | | 3,250 |
| | — |
| | — |
|
| Issuances of preference stock, net of issuance costs | — |
| | 462 |
| | 294 |
| — |
| | — |
| | 462 |
|
| Redemptions of preference stock | — |
| | (475 | ) | | (125 | ) | — |
| | — |
| | (475 | ) |
| Short-term debt (repayments), net of borrowings and discount | (520 | ) | | 469 |
| | 719 |
| (171 | ) | | (520 | ) | | 469 |
|
| Payments of common stock dividends to Edison International | (788 | ) | | (573 | ) | | (701 | ) | (400 | ) | | (788 | ) | | (573 | ) |
| Payments of preferred and preference stock dividends | (121 | ) | | (124 | ) | | (123 | ) | (121 | ) | | (121 | ) | | (124 | ) |
| Other | (8 | ) | | (79 | ) | | (66 | ) | (11 | ) | | (8 | ) | | (79 | ) |
| Net cash provided by (used in) financing activities | $ | 616 |
| | $ | 243 |
| | $ | (219 | ) | |
| Net cash provided by financing activities | | $ | 4,771 |
| | $ | 616 |
| | $ | 243 |
|
Net Cash Used in Investing Activities
Cash flows used in investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $4.9 billion, $4.5 billion for 2018,and $3.8 billion for 2019, 2018 and 2017, and $3.6 billion for 2016,respectively, primarily related to transmission and generation investments. SCE had a net redemption of nuclear decommissioning trust investments of $106 million and $109 million $197 millionin 2019 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.
Nuclear Decommissioning Activities
SCE's statementstatements of cash flows includes nuclear decommissioning activities, which are reflected in the following line items:
| | | (in millions) | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
Net cash used in operating activities: Net earnings from nuclear decommissioning trust investments | $ | 41 |
| | $ | 55 |
| | $ | 45 |
| $ | 67 |
| | $ | 41 |
| | $ | 55 |
|
| SCE's decommissioning costs | (140 | ) | | (236 | ) | | (168 | ) | (172 | ) | | (140 | ) | | (236 | ) |
Net cash provided by investing activities: Proceeds from sale of investments | 4,340 |
| | 5,239 |
| | 3,212 |
| 4,389 |
| | 4,340 |
| | 5,239 |
|
| Purchases of investments | (4,231 | ) | | (5,042 | ) | | (3,033 | ) | (4,283 | ) | | (4,231 | ) | | (5,042 | ) |
| Net cash impact | $ | 10 |
| | $ | 16 |
| | $ | 56 |
| $ | 1 |
| | $ | 10 |
| | $ | 16 |
|
Net cash used in operating activities relaterelates 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, $236172 million and $168$140 million in 2018, 20172019 and 2016,2018, respectively) and reimbursements to SCE from the nuclear decommissioning trust ($150 million, $252173 million and $224$150 million in 2019 and 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.Other, including intercompany eliminations. | | | (in millions) | 2018 | | 20171 | | 20161 | 2019 | | 2018 | | 2017 |
| Net cash used in operating activities | $ | (14 | ) | | $ | (138 | ) | | $ | (267 | ) | $ | (216 | ) | | $ | (14 | ) | | $ | (138 | ) |
| Net cash (used in) provided by financing activities | (534 | ) | | 764 |
| | 314 |
| |
| Net cash provided by (used in) financing activities | | 132 |
| | (534 | ) | | 764 |
|
| Net cash provided by (used in) investing activities | 61 |
| | (83 | ) | | (109 | ) | — |
| | 61 |
| | (83 | ) |
| Net (decrease) increase in cash, cash equivalents and restricted cash | $ | (487 | ) | | $ | 543 |
| | $ | (62 | ) | $ | (84 | ) | | $ | (487 | ) | | $ | 543 |
|
| |
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 decreasedincreased in 20182019 by $124$202 million from 2017 and decreased in 2017 by $129 million from 20162018 due to:
$92 million, $138Outflows of $137 million and $32$92 million cash outflow from operating activities in 2018, 20172019 and 2016,2018, respectively, due to payments and receipts relating to interest and operating costs. In addition, the cash
An outflow of $79 million in 2017 included higher pension payments2019 primarily related to executive retirement plans.
$78$164 million of intercompany tax-allocation payments offset by $85 million of federal and state income tax refunds. An inflow of $78 million in 2018 primarily related to federal income tax refunds.
$214 million of cash payments made to the Reorganization Trust in September 2016 related to the EME Settlement Agreement.
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) Financing Activities
Net cash provided by (used in) financing activities were as follows: |
| | | | | | | | | | | | |
| (in millions) | | 2019 | | 2018 | | 2017 |
| Dividends paid to Edison International common shareholders | | $ | (810 | ) | | $ | (788 | ) | | $ | (707 | ) |
| Dividends received from SCE | | 400 |
| | 788 |
| | 573 |
|
| Capital contribution to SCE | | (3,250 | ) | | — |
| | — |
|
| Receipt from (payment for) stock-based compensation | | 12 |
| | (10 | ) | | (140 | ) |
| Issuance of common stock | | 2,391 |
| | — |
| | — |
|
| Long-term debt issuance, net of discount and issuance costs | | 1,390 |
| | 545 |
| | 788 |
|
| Long-term debt repayments | | — |
| | (15 | ) | | (403 | ) |
| Issuance of term loan | | 1,000 |
| | — |
| | — |
|
| Repayments of term loan | | (1,000 | ) | | — |
| | — |
|
| Short-term debt (repayments), net of borrowings and discount | | (1 | ) | | (1,091 | ) | | 615 |
|
| Other | | — |
| | 37 |
| | 38 |
|
| Net cash provided by (used in) financing activities | | $ | 132 |
| | $ | (534 | ) | | $ | 764 |
|
Net Cash Provided by 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 andoffset by Edison Energy Group's capital expenditures primarily for commercial solar installations ($16 million, $88 million and $101 million in 2018, 2017 and 2016, respectively).2018.
Contractual Obligations and Contingencies
Contractual Obligations
As of December 31, 2019, Edison International Parent and Other and SCE's contractual obligations as of December 31, 2018, for the years 20192020 through 20232024 and thereafter are estimated below.
| | | (in millions) | Total | | Less than 1 year | | 1 to 3 years | | 3 to 5 years | | More than 5 years | 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 |
| $ | 27,185 |
| | $ | 745 |
| | $ | 2,659 |
| | $ | 2,103 |
| | $ | 21,678 |
|
Power purchase agreements:2 | 36,189 |
| | 2,562 |
| | 5,172 |
| | 4,600 |
| | 23,855 |
| |
Power purchase agreements2 | | 36,021 |
| | 2,796 |
| | 5,506 |
| | 4,617 |
| | 23,102 |
|
Other operating lease obligations3 | 234 |
| | 41 |
| | 56 |
| | 37 |
| | 100 |
| 219 |
| | 37 |
| | 54 |
| | 33 |
| | 95 |
|
Purchase obligations:4 | | | | | | | | | | | | | | | | | | |
| Other contractual obligations | 480 |
| | 79 |
| | 113 |
| | 79 |
| | 209 |
| 452 |
| | 77 |
| | 95 |
| | 91 |
| | 189 |
|
Total SCE5,6,7,8 | $ | 60,413 |
| | $ | 3,334 |
| | $ | 7,569 |
| | $ | 7,028 |
| | $ | 42,482 |
| |
Total SCE5,6,7 | | 63,877 |
| | 3,655 |
| | 8,314 |
| | 6,844 |
| | 45,064 |
|
| Edison International Parent and Other: | | | | | | | | | | | | | | | | | | |
Long-term debt maturities and interest1 | 2,055 |
| | 53 |
| | 491 |
| | 866 |
| | 645 |
| 3,773 |
| | 508 |
| | 907 |
| | 1,050 |
| | 1,308 |
|
| Other operating lease obligations | 6 |
| | 1 |
| | 2 |
| | 2 |
| | 1 |
| 5 |
| | 1 |
| | 2 |
| | 2 |
| | — |
|
Total Edison International Parent and Other5 | $ | 2,061 |
| | $ | 54 |
| | $ | 493 |
| | $ | 868 |
| | $ | 646 |
| 3,778 |
| | 509 |
| | 909 |
| | 1,052 |
| | 1,308 |
|
Total Edison International6,7,8 | $ | 62,474 |
| | $ | 3,388 |
| | $ | 8,062 |
| | $ | 7,896 |
| | $ | 43,128 |
| |
Total Edison International6,7 | | $ | 67,655 |
| | $ | 4,164 |
| | $ | 9,223 |
| | $ | 7,896 |
| | $ | 46,372 |
|
| |
1 | For additional details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Amount includes interest payments totaling $10.4$11.9 billion and $305$623 millionover 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 capitalfinance leases. For further discussion, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies.Contingencies" and "—Note 13. Leases." |
| |
3 | At December 31, 2018,2019, 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.13. Leases." |
| |
4 | For additional details, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies." At December 31, 2018,2019, 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, 2018,2019, Edison International Parent and Other and SCE had estimated contributions to the pension and PBOP plans. SCE estimated contributions are $80$48 million, $76$42 million, $76$40 million, $88$41 million and $169$44 million in 2019, 2020, 2021, 2022, 2023 and 2023,2024, respectively, which are excluded from the table above. Edison International Parent and Other estimated contributions are $27$18 million, $20$21 million, $26$19 million, $26$17 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, 2018,2019, Edison International and SCE had a total net liability recorded for uncertain tax positions of $338$370 million and $249$282 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,"Instruments" and "—Note 1. Summary of Significant Accounting Policies",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 and mudslide events, wildfire insurance,San Onofre Related Matters, Nuclear Insurance, and Spent Nuclear Fuel and the Tehachapi Transmission Project, 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, seepublic. 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"—Note 4. Fair Value Measurements."
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 2018,2019, 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 | Carrying Value | | Fair Value | | 10% Increase | | 10% Decrease |
| Edison International: | | | | | | | | | | | | | | |
| December 31, 2019 | | $ | 18,343 |
| | $ | 20,137 |
| | $ | 19,413 |
| | $ | 20,913 |
|
| December 31, 2018 | $ | 14,711 |
| | $ | 14,844 |
| | $ | 14,188 |
| | $ | 15,556 |
| 14,711 |
| | 14,844 |
| | 14,188 |
| | 15,556 |
|
| December 31, 2017 | 12,123 |
| | 13,760 |
| | 13,239 |
| | 14,308 |
| |
| SCE: | | | | | | | | | | | | | | |
| December 31, 2019 | | $ | 15,211 |
| | $ | 16,892 |
| | $ | 16,213 |
| | $ | 17,619 |
|
| December 31, 2018 | $ | 12,971 |
| | $ | 13,180 |
| | $ | 12,556 |
| | $ | 13,858 |
| 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'sthe fair value of derivative instruments 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 Statements—Note 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$86 million and $109$167 million at December 31, 20182019 and 2017,2018, 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, | December 31, |
| (in millions) | 2018 | 2017 | 2019 | 2018 |
| Increase in electricity prices by 10% | $ | 23 |
| $ | 11 |
| $ | 25 |
| $ | 23 |
|
| Decrease in electricity prices by 10% | (23 | ) | (11 | ) | (25 | ) | (23 | ) |
| Increase in gas prices by 10% | 2 |
| 10 |
| 12 |
| 2 |
|
| Decrease in gas prices by 10% | (2 | ) | (5 | ) | (12 | ) | (2 | ) |
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-ratedof 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 Based on SCE's policies and risk exposures related to credit, SCE does not anticipate a material adverse effect on their financial statements as a result of counterparty nonperformance. At December 31, 20182019, SCE's power and 2017,gas trading counterparty credit risk exposure was $91 million, 98% of which is associated with entities that have an investment grade rating of A or higher. SCE assigns a credit rating to counterparties based on the amountlower of balance sheet exposure as described above broken down by thea counterparty's S&P or Moody's rating.
For more information related to credit ratings of SCE's counterparties, was as follows:risks, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments."
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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.
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, 2018,2019, the consolidated balance sheets included regulatory assets of $6.5$7.1 billion and regulatory liabilities of $9.9$9.4 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.
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.
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. |
| |
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 | | SCE |
| (in millions) | Increase in health care cost trend rate by 1% | | Decrease in health care cost trend rate by 1% | | Increase in health care cost trend rate by 1% | | Decrease in health care cost trend rate by 1% |
| Change to accumulated benefit obligation for PBOP | $ | 210 |
| | $ | (173 | ) | | $ | 209 |
| | $ | (172 | ) |
| Change to annual aggregate service and interest costs | 11 |
| | (9 | ) | | 11 |
| | (9 | ) |
Accounting for Contingencies
Nature of Estimates Required. Edison International and SCE record loss contingencies when management determines that the outcome of future events is probable of occurring and when the amount of the loss can be reasonably estimated. Gain contingencies are recognized in the financial statements when they are realized.
Key Assumptions and Approach Used. The determination of a reservean accrual for a loss contingency is based on management judgment and estimates with respect to the likely outcome of the matter, including the analysis of different scenarios. Liabilities are recorded or adjusted when events or circumstances cause these judgments or estimates to change. In assessing whether a loss is a reasonable possibility, Edison International and SCE may consider the following factors, among others: the nature of the litigation, claim or assessment, available information, opinions or views of legal counsel and other advisors, and the experience gained from similar cases. Edison International and SCE provide disclosures for material contingencies when there is a reasonable possibility that a loss or an additional loss may be incurred.
Effect if Different Assumptions Used. Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and could have a significant impact on the liabilities, revenue and expenses recorded on the consolidated financial statements. For a discussion of contingencies, guarantees and indemnities, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."
Application to Southern California Wildfires
As discussed in "Management Overview," significantover the past several years, wind-driven wildfires and mudslides impacted portions of SCE's service territory, with wildfires in December 2017 and November 2018 impacted portionsand mudslides in January 2018 causing loss of SCE's service territory causinglife, substantial damage to both residential and business properties, and service outages for SCE customers.
Any potential liability of SCE for damages related to the 2017/2018 Wildfire/Mudslide Events will dependdepends on a number of factors, including whether SCE is determined to have substantially caused, or contributed to, the damages and whether parties seeking recovery of damages will be required to show negligence in addition to causation. Investigations into the causes of the 2017/2018 Wildfire/Mudslide Events are ongoing and final determinations of liability, including determinations of whether SCE was negligent, would only be made during lengthy and complex litigation processes.
Management judgment was required to assess whether a loss contingency was probable and reasonably estimable. 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,charges, before recoveries and taxes, of $232 million and $4.7 billion in
for the fourth quarteryears ended 2019 and 2018, respectively. Edison International and SCE recorded expected recoveries from insurance of $2.0 billion for 2017/2018 Wildfire/Mudslide Events during 2018. Edison International and SCE also recorded expected recoveries from insurance of $2.0 billion and expected recoveries through FERC electric rates of $14 million and $135 million.million for the years ended 2019 and 2018, respectively. The net chargecharges to earnings recorded waswere $157 million and $1.8 billion after-tax.after-tax for the years ended 2019 and 2018, respectively.
This charge correspondsThese charges correspond 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.Events and is subject to change as additional information becomes available. Edison International and SCE currently believe that it is reasonably possible that the amount of the actual loss will be greater than the amount accrued. However, Edison International and SCE are currently unable to reasonably estimate an upper end of the range of expected losses given the uncertainty as to the legal and factual determinations to be made during litigation, including uncertainty as to the contributing causes of the 2017/2018 Wildfire/Mudslide Events, the complexities associated with multiple ignition points, the potential for separate damages to be attributable to fires ignited at separate ignition points,that merge, whether inverse condemnation will be held applicable to SCE with respect to damages caused by the Montecito Mudslides, and the preliminary nature of the litigation processes. Edison International and SCE record a receivable for insurance receivablesrecoveries when the recovery of a recorded loss is determined to be probable. Edison International and SCE will seek to offset any actual losses realized with recoveries from insurance policies in place at the time of the events and, to the extent actual losses exceed insurance, through electric rates.
Recovery of uninsured costs through electric rates is subject to approval by regulators. Under accounting standards for rate-regulated enterprises, SCE defers costs as regulatory assets when it concludes that such costs are probable of future recovery in electric rates. SCE utilizes objectively determinable evidence to form its view on probability of future recovery. The only directly comparable precedent in which a California investor-owned utility has sought recovery for uninsured wildfire-related costs is SDG&E's requests for cost recovery related to 2007 wildfire activity, where FERC allowed recovery of all FERC-jurisdictional wildfire-related costs while the CPUC rejected recovery of all CPUC-jurisdictional wildfire-related costs based on a determination that SDG&E did not meet the CPUC's prudency standard. As a result, while SCE does not agree with the CPUC's decision, it believes that the CPUC's interpretation and application of the prudency standard to SDG&E creates substantial uncertainty regarding how that standard will be applied to an investor-owned utility in future wildfire cost-recovery proceedings.proceedings for fires ignited prior to July 12, 2019. Through the operation of its FERC Formula Rate and based upon the precedent established in SDG&E's recovery of FERC-jurisdictional wildfire-related costs, SCE believes it is probable it will recover its FERC-
jurisdictionalFERC-jurisdictional wildfire and mudslide related costs and has recorded a regulatory assetassets of $135$149 million, the FERC portion of the $4.7$4.9 billion charge itcharges accrued. The CPUC and FERC may reach different conclusions than SCE's current determination of probable outcomes.
Over the course of the various investigations and litigation processes associated with each of the 2017/2018 Wildfire/Mudslide Events, new facts may emerge as to the cause, extent and magnitude of potential damages. The amount of the expected loss and recorded receivables are subject to change based on new or additional information.
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. Certain estimates and assumptions are required to determine whether deferred tax assets can and will be utilized 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 Internal Revenue Service, 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. In determining whether it is more likely than not that all or some portion of net operating loss and tax credit carryforwards can be utilized, management analyzes the trend of U.S. GAAP earnings and then estimates the impact of future taxable income, reversing temporary differences and available prudent and feasible tax planning strategies.
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 evaluate uncertain tax positions at the end of each reporting period and make adjustments when warranted based on changes in fact or law.
Effect if Different Assumptions Used. Should a change in facts or circumstances lead to a change in judgment about the ultimate realizability of a deferred tax asset, Edison International and SCE would record or adjust the related valuation allowance in the period that the change in facts and circumstances occurs, along with a corresponding increase or decrease in the provision for income taxes.
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 Nuclear Decommissioning Cost Triennial Proceeding ("NDCTP") 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 $7.1 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 NDCTP 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 U.S. Department of Energy 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, 2019, 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. In May 2019, after an extensive review, the NRC determined that fuel loading can be safely resumed at San Onofre. SCE commenced fuel transfer operations at San Onofre in July 2019. In October 2019, the California Coastal Commission approved SCE's application for the Coastal Development Permit, the principle discretionary permit required to start major decommissioning activities at San Onofre. SCE plans on commencing major decommissioning activities in 2020 in accordance with the terms of the permit, subject to any court rulings in a proceeding brought in December 2019 to challenge the California Coastal Commission's issuance of the permit.
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, 2019 |
| Uniform increase in escalation rate of 1 percentage point | $ | 601 |
|
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 their 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, 2019, Edison International's and SCE's pension plans had a $4.1 billion and $3.7 billion benefit obligation, respectively, and total 2019 expense for these plans was $70 million and $64 million, respectively. As of December 31, 2019, the benefit obligation for both Edison International's and SCE's PBOP plans were $2.1 billion, and total 2019 expense for Edison International's and SCE's plans were $7 million. 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, 2019, this cumulative difference amounted to a regulatory asset of $110 million, meaning that the ratemaking method has recognized less in expense than the accounting 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 2019:
|
| | | | |
| (in millions) | Pension Plans | Postretirement Benefits Other than Pensions |
Discount rate1 | 4.19 | % | 4.35 | % |
Expected long-term return on plan assets2 | 6.50 | % | 5.30 | % |
Assumed health care cost trend rates3 | * |
| 6.75 | % |
| |
* | Not applicable to pension plans. |
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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 by matching the timing and amount of expected future benefit payments to the corresponding yields from the Aon- Hewitt AA Only Bond Universe yield curve on the measurement date. |
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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 returns on the pension plan assets were 19.2%, 8.0% and 9.6% for the one-year, five-year and ten-year periods ended December 31, 2019, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 19.0%, 6.8% and 8.8% over these same periods. Accounting principles provide that differences between expected and actual returns are recognized over the average future service of employees. |
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3 | The health care cost trend rate gradually declines to 5.0% for 2029 and beyond. |
As of December 31, 2019, Edison International and SCE had unrecognized pension costs of $181 million and $104 million, respectively, and unrecognized PBOP gains of $414 million and $416 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 or gains, $87 million of SCE's pension costs and $416 million of SCE's PBOP gains are recorded as regulatory assets and regulatory liabilities, respectively, and are expected to be recovered or 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:
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| | | | | | | | | | | | | | | |
| | 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 | $ | (383 | ) | | $ | 465 |
| | $ | (343 | ) | | $ | 417 |
|
| Change to accumulated benefit obligation for PBOP | (289 | ) | | 345 |
| | (287 | ) | | 343 |
|
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 $32 million and $30 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 $21 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 | | SCE |
| (in millions) | Increase in health care cost trend rate by 1% | | Decrease in health care cost trend rate by 1% | | Increase in health care cost trend rate by 1% | | Decrease in health care cost trend rate by 1% |
| Change to accumulated benefit obligation for PBOP | $ | 225 |
| | $ | (184 | ) | | $ | 224 |
| | $ | (183 | ) |
| Change to annual aggregate service and interest costs | 10 |
| | (8 | ) | | 10 |
| | (8 | ) |
Contributions to the Wildfire Insurance Fund
Nature of Estimates Required. At December 31, 2019, Edison International and SCE have a $2.8 billion long-term asset and a $323 million current asset reflected as "Wildfire Insurance Fund contributions" in the consolidated balance sheets for the initial $2.4 billion contribution made during the third quarter of 2019 and the present value of annual contributions SCE committed to make to the Wildfire Insurance Fund, reduced by amortization. At December 31, 2019, a long-term liability of $785 million has been reflected in "Other deferred credits and other long-term liabilities" for the present value of unpaid contribution amounts. Contributions were discounted to the present value at the date SCE committed to participate in the Wildfire Insurance Fund using US treasury interest rates.
Management concluded it would be most appropriate to account for the contributions to the Wildfire Insurance Fund similar to prepaid insurance, ratably allocating the expense to periods based on an estimated period of coverage.
Key Assumptions and Approach Used. The Wildfire Insurance Fund does not have a defined life. Instead, the Wildfire Insurance Fund will terminate when the administrator determines that the fund has been exhausted. Management estimates that the Wildfire Insurance Fund will provide insurance coverage for a period of 10 years. The determination of the correct period in which to record an expense in relation to contributions to the Wildfire Insurance Fund depends, among other factors, on management's assessment of: the future occurrence and magnitude of wildfires; the involvement of SCE, or other electrical corporations, in the ignition of those fires; the probable future outcomes of CPUC cost recovery proceedings for wildfire claims, which may require reimbursement of the fund by electrical corporations; the participation of PG&E in the fund; and the use of the contributions by the administrator of the Wildfire Insurance Fund. Further information regarding these factors may become available due to the actions of the fund administrator, or other entities, which could require management to reassess the period of coverage. In estimating the period of coverage, Edison International and SCE used Monte Carlo simulations based on five years (2014 – 2018) of historical data from wildfires caused by electrical utility equipment to estimate expected loss. The details of the operation of the Wildfire Insurance Fund and estimates related to claims by SCE, PG&E and SDG&E against the fund have been applied to the expected loss simulations to estimate the period of coverage of the fund. The most sensitive inputs to the estimated period of coverage are the expected frequency of wildfire events caused by investor-owned utility electrical equipment and the estimated costs associated with those forecasted events. These inputs are most affected by the historical data used in estimating expected losses. Using a 12-year period of historical data, with an average annual statewide gross claims of $5.0 billion, compared to $11.7 billion for the five year historical data, would increase the period of coverage to 20 years.
Effect if Different Assumptions Used. Changes in the estimated life of the insurance fund could have a material impact on the expense recognition.
NEW ACCOUNTING GUIDANCE
New accounting guidance is discussed in "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."
RISK FACTORS
RISKS RELATING TO EDISON INTERNATIONAL
Edison International's liquidity and ability to pay dividends depends on its ability to borrow funds, access to bank and capital markets, monetization of tax benefits retainedheld by EME,Edison International, and SCE's ability to pay dividends and tax allocation payments to Edison International.
Edison International is a holding company and, as such, it has no operations of its own. Edison International's ability to meet its financial obligations, make investments, and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of SCE and itsSCE's ability to make upstream distributions. If SCE does not make upstream distributions to Edison International and Edison International is unable to access the bank and capital markets on reasonable terms, Edison International may be unable to continue to pay dividends to its shareholders or meet its financial obligations.
Prior to paying dividends to Edison International, SCE has financial and regulatory obligations that must be satisfied, including, among others, debt service and preferred and preference stock dividends. Further, SCE and Edison International cannot pay dividends if California law requirements for the declaration of dividends are not met. For information on CPUC and California law requirements related to the declaration of dividends, see "Liquidity and Capital Resources—SCE—SCE Dividends" in the MD&A. SCE may also owe tax-allocation payments to Edison International under applicable tax-allocation agreements.
Edison International's ability to obtain financing, as well as its ability to refinance debt and make scheduled payments of principal and interest, are dependent on numerous factors, including its levels of indebtedness, maintenance of acceptable credit ratings, financial performance, liquidity and cash flow, and other market conditions. In addition, the factors affecting SCE's business will impact Edison International's ability to obtain financing. Edison International's inability to borrow funds from time to time could have a material effect on Edison International's liquidity and operations.
See "Risks Relating to Southern California Edison Company" below for further discussion.
Edison International's business activities are concentrated in one industry and in one region.
Edison International business activities are concentrated in the electricityelectric utility industry. Its principal subsidiary, SCE, serves customers only in southern and central California. As a result, Edison International's future performance may be affected by events and economic factors unique to California or by regional regulation, legislation or judicial decisions. For example, California courts have applied strict liability to investor-owned utilities in wildfire and other litigation matters. See "Management Overview—Southern California Wildfires and Mudslides" in the MD&A.
Edison Energy Group may not be successful.
Edison International, through Edison Energy, is pursuing an energy services business focused on large commercial and industrial customers by providing unbiased expertise to help define energy requirements and implement solutions to better manage energy costs and risks. There is no assurance that these activities will lead to growth or be profitable.
RISKS RELATING TO SOUTHERN CALIFORNIA EDISON COMPANY
Regulatory and Legislative Risks
SCE's financial results depend upon its ability to recover its costs and to earn a reasonable rate of return on capital investments in a timely manner from its customers through regulated rates.
SCE's ongoing financial results depend on its ability to recover its costs from its customers, including the costs of electricity purchased for its customers, through the rates it charges its customers as approved by the CPUC and FERC. SCE's financial results also depend on its ability to earn a reasonable return on capital, including long-term debt and equity. SCE's ability to recover its costs and earn a reasonable rate of return can be affected by many factors, including the time lag between when costs are incurred and when those costs are recovered in customers' rates and differences between the forecast or authorized costs embedded in rates (which are set on a prospective basis) and the amount of actual costs incurred. The CPUC or the FERC may not allow SCE to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. Further, SCE may be required to incur expenses before the relevant regulatory agency approves the recovery of such costs. For example, SCE is incurring costs to strengthen its wildfire mitigation and prevention efforts before it is clear whether such costs will be recoverable from customers. Also, to the extent SCE is required to pay uninsured wildfire-related damages, as expected, recovery of such costs may be denied if the CPUC determines that SCE was not prudent. In addition, while SCE supports California’sCalifornia's environmental goals, it may be prevented from fully executing on its strategy to support such goals by regulatory delay or lack of approval of cost-recovery for the costs of such strategic actions from the relevant regulatory agencies. In addition,
SCE's capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, leveling demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customer rates. If SCE is unable to obtain a sufficient rate increase or modify its rate design to recover its
costs (including an adequate return on capital) in rates in a timely manner, its financial condition and results of operations could be materially affected. For further information on SCE's rate requests, see "Management Overview—20182021 General Rate Case" and "Liquidity"Management Overview—2018 and Capital Resources—SCE—Regulatory Proceedings—2019 FERC Formula Rate" in the MD&A.
SCE is subject to extensive regulation and the risk of adverse regulatory and legislative decisions, delays in regulatory or legislative decisions, and changes in applicable regulations or legislation.
SCE operates in a highly regulated environment. SCE's business is subject to extensive federal, state and local energy, environmental and other laws and regulations. Among other things, the CPUC regulates SCE's retail rates and capital structure, and the FERC regulates SCE's wholesale rates. The NRC regulates the decommissioning of San Onofre in addition to the local and state agencies that require permits. The construction, planning, and siting of SCE's power plants and transmission lines in California are also subject to regulation by the CPUC and other local, state and federal agencies.
SCE must periodically apply for licenses and permits from these various regulatory authorities, including environmental regulatory authorities, and abide by their respective orders. Should SCE be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose fines, penalties or disallowances on SCE, SCE may be prevented from executing its strategy and its business could be materially affected. The process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by opponents and such delay or defeat could have a material effect on SCE's business.
Rules, restrictions and processes around ex parte communications could result in delayed decisions, increased investigations, enforcement actions and penalties. In addition, the CPUC or other parties may initiate investigations of past communications between public utilities, including SCE, and CPUC officials and staff that could result in reopening completed proceedings for reconsideration.
Edison International and SCE continue to pursue regulatory and legal strategies, and anticipate pursuing legislative and regulatory avenuesstrategies on the longer term, to address the application of a strict liability standard to wildfire-related property damages without the guaranteed ability to recover resulting costs in electric rates. Not achieving a timelyTo the extent the Wildfire Insurance Fund and comprehensive solution mitigatingother provisions of AB 1054 do not effectively mitigate the significant risk faced by California investor-owned utilities related to liability for damages arising from catastrophic wildfires where utility facilities are a substantial cause, not achieving a more comprehensive solution could have a detrimental effect on SCE's business and financial condition. The effectiveness of AB 1054 to mitigate the wildfire-related risk faced by SCE is conditioned in part on the performance of various entities newly formed under AB 1054 and related legislation to, among other things, administer the Wildfire Insurance Fund, issue safety certifications, oversee and enforce compliance with wildfire safety standards, and develop metrics to reduce risk and measure compliance with risk reduction. In addition, CPUC approval is required to recover the costs SCE is incurring to strengthen its wildfire mitigation and prevention efforts described in its 2019 WMP,and 2020 WMPs, including costs being incurred for its GS&RP. Further, the CPUC may assess penalties on SCE if it finds that SCE fails to substantially comply with its WMP. See "Management Overview—Southern California Wildfires and Mudslides" and "Management Overview—Capital Program—Distribution Grid"Wildfire Mitigation and Wildfire Insurance Expenses" in the MD&A.
In addition, existing regulations may be revised or reinterpretedre-interpreted and new laws and regulations may be adopted or become applicable to SCE, or its facilities or operations, in a manner that may have a detrimental effect on SCE's business or result in
significant additional costs. In addition, regulations adopted via the public initiative or legislative process may apply to SCE, or its facilities or operations, in a manner that may have a detrimental effect on SCE's business or result in significant additional costs.
SCE's energy procurement activities are subject to regulatory and market risks that could materially affect its financial condition and liquidity.
SCE obtains energy, capacity, environmental credits and ancillary services needed to serve its customers from its own generating plants and through contracts with energy producers and sellers. California law and CPUC decisions allow SCE to recover, through the rates it is allowed to charge its customers, reasonable procurement costs incurred in compliance with an approved procurement plan. Nonetheless, SCE's cash flows remain subject to volatility primarily resulting from changes in commodity prices, including as a result of gas supply constraints. Additionally, significant and prolonged gas use restrictions may adversely impact the reliability of the electric grid if critical generation resources are limited in their operations. For further information, see "Business—SCE—Purchased Power and Fuel Supply." SCE is also subject to the risks of unfavorable or untimely CPUC decisions about the compliance with SCE's procurement plan and the reasonableness of certain procurement-related costs.
SCE may not be able to hedge its risk for commodities on economic terms or fully recover the costs of hedges through the rates it is allowed to charge its customers, which could materially affect SCE's liquidity and results of operations, see "Market Risk Exposures" in the MD&A.
Operating Risks
Damage claims against SCE for wildfire-related losses may materially affect SCE’sSCE's financial condition and results of operations.
Prolonged drought conditions and shifting weather patterns in California resulting from climate change as well as increased tree mortality rates have increased the duration of the wildfire season and the risk of severe wildfire events. Severe wildfires and increased urban development in high fire risk areas in California have given rise to large damage claims against California utilities for fire-related losses alleged to be the result of utility practices and/or the failure of electric and other utility equipment. Catastrophic wildfires can occur in SCE's service territory even if SCE effectively implements its WMPs. California courts have previously found utilities to be strictly liable for property damage, regardless of fault, by applying the theory of inverse condemnation when a utility's facilities were determined to be a substantial cause of a wildfire that caused the property damage. The rationale generally stated by these courts for applying this theory to investor-owned utilities is that property losses resulting from a public improvement, such as the distribution of electricity, can be spread across the larger community that benefited from such improvement. However, in DecemberNovember 2017, the CPUC issued a decision denying an investor-owned utility's request to include in its rates uninsured wildfire-related costs arising from several 2007 fires, finding that the investor-owned utility did not prudently manage and operate its facilities prior to or at the outset of the 2007 wildfires. An inability to recover uninsured wildfire-related costs could materially affect SCE's business, financial condition and results of operations. For example, if SCE is found liable for damages related to catastrophic wildfires, including the 2017/2018 Wildfire/Mudslide Events, and SCE is unable to, or believes that it will be unable to, recover those damages through insurance, the Wildfire Insurance Fund (which is only available for fires ignited after July 12, 2019) or electric rates, or access the bank and capital markets on reasonable terms, SCE may not have sufficient cash or equity to pay dividends or may be restricted from declaring such dividends because it does not meet CPUC or California law requirements related to the declaration of dividends. For information on the California law requirements on the declaration of dividends, see "Liquidity and Capital Resources—SCE—SCE Dividends" in the MD&A. See "Management Overview—Southern California Wildfires and Mudslides" in the MD&A.
SCE's insurance coverage for wildfires arising from its ordinary operations may not be sufficient.
Edison International has experienced increased costs and difficulties in obtaining insurance coverage for wildfires that could arise in connection with SCE's ordinary operations. Edison International, SCE orand its contractors may experience coverage reductions and/or increased wildfire insurance costs in future years. No assurance can be given that losses will not exceed the limits of SCE's or its contractors' insurance coverage. SCE may not be able to recover uninsured losses and increases in the cost of insurance in customerelectric rates. Losses which are not fully insured or cannot be recovered inthrough the Wildfire Insurance Fund or electric rates could materially affect Edison International's and SCE's financial condition and results of operations. For more information on wildfire insurance risk, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."
SCE may not effectively implement its Wildfire Mitigation Plans.
SCE will face a higher likelihood of catastrophic wildfires in its service territory if it cannot effectively implement its WMPs. For example, SCE may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training and retaining contract workers it needs to fulfill its mitigation obligations under the WMPs. In addition, if SCE does not have an approved WMP, SCE will not be issued a safety certification from the CPUC and will consequently not benefit from the presumption of prudency or the AB 1054 Liability Cap.
The CPUC may assess penalties on SCE if it finds that SCE fails to substantially comply with its WMP. In addition, SCE may be subject to regulatory fines and penalties, claims for damages and reputational harm if it places excessive reliance on Public Safety Power Shut-Offs to mitigate wildfire risks.
For more information on AB 1054, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides—Recovery of Wildfire-Related Costs—2019 Wildfire Legislation."
SCE will not benefit from all of the features of AB 1054 if the Wildfire Insurance Fund is exhausted.
Catastrophic wildfires could rapidly exhaust the Wildfire Insurance Fund and SCE will not be reimbursed by the Wildfire Insurance Fund or benefit from the AB 1054 Liability Cap if the fund has been exhausted as a result of damage claims previously incurred by SCE or the other participating utilities.
In addition, because PG&E's participation in, and contributions to, the Wildfire Insurance Fund are subject to it emerging from bankruptcy and meeting certain other conditions prior to June 30, 2020, the Wildfire Insurance Fund may be smaller than is currently anticipated. If PG&E does not participate in the Wildfire Insurance Fund, it will not be entitled to seek reimbursement from the fund.
For more information on AB 1054, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides—Recovery of Wildfire-Related Costs—2019 Wildfire Legislation."
There are inherent risks associated with owning and decommissioning nuclear power generating facilities and obtaining cost reimbursement, including, among other things, insufficiency of nuclear decommissioning trust funds, costs exceeding current estimates, execution risks, potential harmful effects on the environment and human health and the hazards of storage, handling and disposal of radioactive materials. Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.
SCE funds decommissioning costs with assets that are currently held in nuclear decommissioning trusts. Based on current decommissioning cost estimates, SCE believes that further contributions to the nuclear decommissioning trusts' assets may be required to pay the costs of decommissioning. In the event thatIf additional contributions to the nuclear decommissioning trust funds become necessary, recovery of any such additional funds through electric rates is subject to the CPUC's review and approval.
The costs of decommissioning San Onofre are subject to reasonableness reviews by the CPUC. These costs may not be recoverable through regulatory processes or otherwise unless SCE can establish that the costs were reasonably incurred. In addition, SCE faces inherent execution risks including such matters as the risks of human performance, workforce capabilities, public opposition, permitting delays, and governmental approvals. Decommissioning costs ultimately incurred could exceed the current estimates and cost increases resulting from contractual disputes or significant permitting delays, among other things, could cause SCE to materially overrun current decommissioning cost estimates and could materially impact the sufficiency of trust funds. See "Liquidity and Capital Resources—Decommissioning of San Onofre" in the MD&A.
Despite the fact thatEven though San Onofre is being decommissioned, the presence of spent nuclear fuel still poses a potential risk of a nuclear incident. Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $14.1$13.9 billion for Palo Verde and $560 million for San Onofre. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available of $450 million per site. In the case of San Onofre, the balance is covered by a US Government indemnity. In the case of Palo Verde, the balance is covered by a loss sharing program among nuclear reactor licensees. There is no assurance that the CPUC would allow SCE to recover the required contribution made pursuant to this loss sharing program in the case of one or more nuclear incidents with claims that exceeded $450 million at a nuclear reactor which is participating in the program. If this public liability limit of $13.9 billion is insufficient, federal law contemplates that additional funds may be appropriated by Congress. There can be no assurance of SCE's ability to recover uninsured costs in the event the additional federal appropriations are insufficient. For more information on nuclear insurance risk, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Nuclear Insurance."
SCE's anticipated new customer service system is subject to implementation and cost-recovery risks that could materially affect SCE's business and financial condition.
SCE is currently testing a new customer service system that it anticipates implementing in 2021. If the customer service system does not function as intended upon implementation, SCE could experience, among other things, delayed or inaccurate customer bills that lead to over- or under- collections and other customer service concerns or degradation. Further, the process of implementing new technologies like the new customer service system represents opportunity for cybersecurity attacks on our information systems, which could lead to sensitive confidential personal and other data being compromised. Customer service degradation or the compromise of sensitive confidential personal and other data could result in violations of applicable privacy and other laws, material financial loss to SCE or to its customers, customer dissatisfaction, loss of confidence in SCE's security measures, and significant litigation and/or regulatory exposure, all of which could materially affect SCE's financial condition and results of operations and materially damage the business reputation of Edison International and SCE.
The expected cost of the new customer service system is significantly higher than SCE had originally projected. If the CPUC determines that any costs incurred by SCE to design, build, test and implement the customer service system were not reasonably or prudently incurred, SCE will not be able to recover such costs through electric rates.
Climate change exacerbated weather-related incidents and other natural disasters could materially affect SCE's financial condition and results of operations.
Weather-related incidents and other natural disasters, including storms, earthquakes and events caused, or exacerbated, by climate change, such as wildfires and mudslides, can disrupt the generation and transmission of electricity, and can seriously damage the infrastructure necessary to deliver power to SCE's customers. Climate change has caused, and exacerbated, extreme weather events and wildfires in southern California, and wildfires could cause, among other things, public safety issues, property damage and operational issues. Weather-related incidents and other natural disasters can lead to lost revenue and increased expense, including higher maintenance and repair costs, which SCE may not be able to recover from its customers. These incidents can also result in regulatory penalties and disallowances, particularly if SCE encounters difficulties in restoring power to its customers on a timely basis or if fire-related losses are found to be the result of utility practices and/or the failure of electric and other utility equipment. In addition, these occurrences could lead to significant claims for damages, including for loss of life and property damage. For example, the 2017/2018 Wildfire/Mudslide Events resulted in, among other things, loss of life, property damage and loss of service. These occurrences could materially affect SCE's business, financial condition and results of operations, and the inability to restore power to SCE's customers could also materially damage the business reputation of SCE and Edison International. For more information on the impact of the 2017/2018 Wildfire/Mudslide Events on SCE and Edison International, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."
The generation, transmission and distribution of electricity are dangerous and involve inherent risks of damage to private property and injury to employees and the general public.
Electricity is dangerous for employees and the general public should they come in contact with electrical current or equipment, including through downed power lines or if equipment malfunctions. In addition, the risks associated with the operation of transmission and distribution assets and power generating facilities include public and employee safety issues and the risk of utility assets causing or contributing to wildfires.
Injuries and property damage caused by such events can subject SCE to liability that, despite the existence of insurance coverage, can be significant. No assurance can be given that future losses will not exceed the limits of SCE's or its contractors' insurance coverage. The CPUC has increased its focus on public safety with an emphasis on heightened compliance with construction and operating standards and the potential for penalties being imposed on utilities. Additionally, the CPUC has delegated to its staff the authority to issue citations to electric utilities, which can impose fines of up to $100,000 per violation per day (capped at a maximum of $8 million), pursuant to the CPUC's jurisdiction for violations of safety rules found in statutes, regulations, and the CPUC's General Orders. The CPUC also can issue fines greater than $8 million outside of the citation program. Such penalties and liabilities could be significant and materially affect SCE's liquidity and results of operations.
SCE's financial condition and results of operations could be materially affected if it is unable to successfully manage the risks inherent in operating and maintaining its facilities.
SCE's infrastructure is aging and could pose a risk to system reliability. In order to mitigate this risk, SCE is engaged in a significant and ongoing infrastructure investment program. This substantial investment program elevates operational risks and the need for superior execution in SCE's activities. SCE's financial condition and results of operations could be materially affected if it is unable to successfully manage these risks as well as the risks inherent in operating and maintaining its facilities, the operation of which can be hazardous. SCE's inherent operating risks include such matters as the risks of human performance, workforce capabilities, public opposition to infrastructure projects, delays, environmental mitigation costs, difficulty in estimating costs or in recovering costs that are above original estimates, system limitations and degradation, and interruptions in necessary supplies.
SCE's distribution of water and propane gas on Catalina Island involves inherent risks of damage to private property and the environment and injury to employees and the general public.
SCE owns and operates the water distribution system on Catalina Island, California and a propane gas distribution system that serves the City of Avalon on Catalina Island, California. Production, storage, treatment and distribution of water for human use and the transportation, storage, distribution and use of gas can be dangerous, and can cause damage to private property and the environment and injury to employees and the general public if equipment fails or does not perform as anticipated. For example, the risks of operating a water distribution system include the potential for burst pipes and water
contamination and the risks of operating gas distribution system include the potential for gas leaks, fire or explosion. In addition, SCE may have to pay fines, penalties and remediation costs if it does not comply with laws and regulations in the operation of the water and gas distribution systems. An inability to recover costs associated with any such damages or injuries or any fines, penalties or remediation costs, from insurance or through rate payers, could materially affect SCE's business, financial condition and results of operations.
Financing Risks
As a capital intensivecapital-intensive company, SCE relies on access to the capital markets. If SCE were unable to access the capital markets or the cost of financing were to substantially increase, its liquidity and operations could be materially affected.
SCE regularly accesses the capital markets to finance its activities and is expected to do so by its regulators as part of its obligation to serve as a regulated utility. SCE's needs for capital for its ongoing infrastructure investment program are substantial. SCE's ability to obtain financing, as well as its ability to refinance debt and make scheduled payments of principal, interest and preferred stock dividends, are dependent on numerous factors, including SCE's levels of indebtedness, maintenance of acceptable credit ratings, financial performance, liquidity and cash flow, and other market conditions. In addition, the actions of other California investor-owned utilities and legal, regulatory and legislative decisions impacting investor-owned utilities can affect market conditions and therefore, SCE's ability to obtain financing. SCE's inability to obtain additional capital from time to time could have a material effect on SCE's liquidity and operations.
Competitive and Market Risks
SCE's inability to effectively and timely respond to the changes that the electricity industry is undergoing, as a result of increased competition, technological advances, and changes to the regulatory environment, could materially impact SCE's business model, financial condition and results of operations.
Customers and third parties are increasingly deploying DERs, such as solar generation, energy storage, energy efficiency and demand response technologies. California’sCalifornia's environmental policy objectives are accelerating the pace and scope of industry change. This change will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity and increase the grid's capacity to interconnect DERs. In addition, enabling California’sCalifornia's clean energy economy goals will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options and electric vehicle infrastructures. To this end, the CPUCIf SCE is conducting proceedings to: evaluateunable to effectively adapt to these changes, to the planning and operation of the electric distribution grid in order to prepare for higher penetration of DERs; consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by DERs, and if feasible, what, if any, compensation to utilities would be appropriate; and clarify the role of the electric distribution grid operator. The outcome of the CPUC's proceedings may impact SCE'sits business model, its ability to execute on its strategy, and ultimately its financial condition and results of operations. For more information, see "Management Overview—Capital Program—Grid Development" in the MD&A.operations could be materially impacted.
Customer-owned generation and load departures to CCAs or Electric Service Providers each reduce the amount of electricity that customers purchase from utilities and have the effect of increasing utility rates unless customer rates are designed to allocate the costs of the distribution grid across all customers that benefit from its use. For example, some customers in California who generate their own power doare not currently required to pay all transmission and distribution charges and non-bypassable charges, subject to limitations, which results in increased utility rates for those customers who do not own their generation. If regulations aren't changed such that customers pay their share of transmission and distribution charges and non-bypassable charges or the demand for electricity reduces so significantly
that SCE is no longer effectively able to recover such charges from its customers, SCE's business, financial condition and results of operations will be materially impacted.
In addition, the FERC has opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities.
For more information. See "Business—SCE—Competition."
Cybersecurity and Physical Security Risks
SCE's systems and network infrastructure are vulnerable totargets for physical and cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality.
Regulators such as NERC and U.S. Government agencies, including the Departments of Defense, Homeland Security and Energy, have increasingly stressed that threat sources continue to seek to exploit potential vulnerabilities in the U.S. national electric grid and other energy infrastructures, and that such attacks and disruptions, both physical and cyber, are highly sophisticated and dynamic.
SCE's operations require the continuous availability of critical information technology systems, sensitive customer data and network infrastructure and information, - all of which are represent targets for malicious actors. New cyber and physical threats arise as
SCE moves from an analog to a digital electric grid. For example, SCE's grid modernization efforts and the move to a network-connected grid increases the number of “threat surfaces”"threat surfaces" and potential vulnerabilities that an adversary can target.
SCE depends on a wide array of vendors to provide it with services and equipment. Malicious actors may attack vendors to disrupt the services they provide to SCE, or to use those vendors as a cyber conduit to attack SCE. Additionally, the equipment and material provided by SCE's vendors may contain cyber vulnerabilities.
SCE's systems have been, and will likely continue to be, subjected to computer attacks of malicious codes, unauthorized access attempts, and other illicit activities, but to date, SCE has not experienced a material cybersecurity breach. Though SCE actively monitors developments in this area and is involved in various industry groups and government initiatives, no security measures can completely shield its systems and infrastructure from vulnerabilities to cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality.
If SCE's information technology and operational technology systems' security measures were to be breached, or a critical system failure were to occur without timely recovery, SCE could be unable to fulfill critical business functions, such as delivery of electricity to customers, and/or sensitive confidential personal and other data could be compromised, which could result in violations of applicable privacy and other laws, material financial loss to SCE or to its customers, loss of confidence in SCE's security measures, customer dissatisfaction, and significant litigation and/or regulatory exposure, all of which could materially affect SCE's financial condition and results of operations and materially damage the business reputation of Edison International and SCE.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to this section is included in the MD&A under the heading "Market Risk Exposures."
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting FirmREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To theBoard of Directors and Shareholders of Edison International
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Edison International and its subsidiaries (the "Company"“Company”) as of December 31, 20182019 and 2017,2018, and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2018,2019, including the related notes and schedules of condensed financial information of parent as of December 31, 20182019 and 20172018 and for each of the three years in the period ended December 31, 20182019 and of valuation and qualifying accounts for each of the three years in the period ended December 31, 20182019 appearing under Item 15 (collectively referred to as the "consolidated“consolidated financial statements"statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20182019 and 2017,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20182019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal ControlsControl Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’sCompany's consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Contingent Liability - Southern California Wildfires and Mudslides
As described in Note 12 to the consolidated financial statements, the Thomas Fire, the Koenigstein Fire, the Montecito Mudslides and the Woolsey Fire (collectively, the "2017/2018 Wildfire/Mudslide Events") within the Company’s service territory caused substantial damage to both residential and business properties in the Santa Barbara, Ventura, and Los Angeles Counties. Based on information available to management and consideration of the risks associated with litigation, management expects to incur a material loss in connection with the 2017/2018 Wildfire/Mudslide Events. The Company is named as a defendant in multiple lawsuits filed related to both the wildfires and mudslides. Final determination of liability for the 2017/2018 Wildfire/Mudslide Events, including determinations of whether the Company was negligent, would only be made during lengthy and complex litigation processes. Even when investigations are still pending or liability is disputed, an assessment of likely outcomes, including through future settlement of disputed claims, may require a liability to be accrued under accounting standards. As of December 31, 2019, management has estimated liabilities of $4.5 billion, remaining expected recoveries from insurance of $1.7 billion and expected recoveries through FERC electric rates of $149 million on the consolidated balance sheet related to the 2017/2018 Wildfire/Mudslide Events. The accrued liability 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. Each reporting period, management reviews its loss estimates for remaining alleged and potential claims related to the 2017/2018 Wildfire Mudslide Events. The process for estimating losses associated with wildfire litigation claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including, but not limited to: estimates of known and expected claims by third parties based on currently available information, opinions of counsel regarding litigation risk, the status of and developments in the course of litigation, and prior experience litigating and settling wildfire litigation claims. While the low end of the reasonably estimated range of expected losses for the 2017/2018 Wildfire/Mudslide Events is estimated on an aggregate basis, some of the factors evaluated by management in connection with its fourth quarter 2019 review contributed to a significant increase in certain loss estimates, while others contributed to a significant decrease in certain other loss estimates. The net result of management's fourth quarter 2019 review was an increase in estimated losses of $232 million for total estimated losses of $4.5 billion as of December 31, 2019 for unpaid claims related to the 2017/2018 Wildfire/Mudslide Events. Additional information is expected to become available from multiple external sources, during the course of litigation and settlement discussions, and from the Company's ongoing internal review, including, among other things, information regarding the extent of damages that may be attributable to any fire determined to have been substantially caused by the Company's equipment, information that may be obtained from the equipment in California Department of Forestry and Fire Protection’s possession, and information pertaining to fire progression, suppression activities, damages alleged by plaintiffs and insurance claims made by third parties.
The principal considerations for our determination that performing procedures relating to the 2017/2018 Wildfire/Mudslide Events contingent liability is a critical audit matter are there was significant judgment by management when determining the probability of a loss being incurred and the estimate of the low end of a reasonably estimated range of expected potential loss for these contingencies, including but not limited to assumptions and subjective factors based on currently available information and assessments, opinions regarding litigation risk, and prior experience with litigating and settling other wildfire
cases. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management's conclusion related to these loss contingencies.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s evaluation of loss contingencies associated with wildfires and mudslides. These procedures also included, among others, obtaining and evaluating the letters of audit inquiry with internal and external legal counsel, assessing the reasonableness of management’s assessment regarding whether it is reasonably possible or probable and reasonably estimable that a loss has been incurred, evaluating the assumptions and methods used by management in developing the low end of the reasonably estimated range of expected potential losses, including currently available information and assessments, opinions regarding litigation risk, and prior experience with litigating and settling other wildfire cases. When assessing the assumptions related to the reasonably estimated range of expected potential losses, the assumptions used were evaluated for reasonableness considering (i) past wildfire litigation history, and (ii) third-party source data.
Recoverability of Regulatory Assets That Are Not Currently Reflected In Rates
As described in Notes 1 and 11 to the consolidated financial statements, the Company's accounting policies conform to accounting principles generally accepted in the United States of America, including the accounting principles for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utility Commission ("CPUC") and the Federal Energy Regulatory Commission ("FERC"). Management applies authoritative guidance for rate-regulated enterprises to the portion of its operations in which regulators set rates at levels intended to recover the estimated costs of providing service, plus a return on net investments in assets, or rate base. Regulators may also impose certain penalties or grant certain incentives. Due to timing and other differences in the collection of electric utility revenue, these accounting principles require an incurred cost that would otherwise be charged to expense by a non-regulated entity to be capitalized as a regulatory asset if it is probable that the cost is recoverable through future rates. As disclosed by management, 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 of the Company or other rate-regulated entities, and other factors that would indicate that the regulator will treat an incurred cost as allowable for ratemaking purposes. As of December 31, 2019, $868 million recorded in wildfire-related memorandum accounts represent wildfire-related costs that are probable of future recovery from customers.
The principal consideration for our determination that performing procedures relating to the Company's recoverability of regulatory assets that are not currently reflected in rates is a critical audit matter is there was significant judgment by management in determining the costs probable of recovery and reported as an asset on the balance sheet. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s assessment of the recoverability of regulatory assets not currently reflected in rates.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the Company's regulatory accounting process, including controls over management’s assessment of the probability of recovering regulatory assets not currently reflected in rates. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating management's assessment regarding the probability of recovery of the regulatory assets at the balance sheet date, evaluating the accounting and disclosure implications, and calculating regulatory assets balances based on provisions outlined in the rate orders. This evidence included reference to historical precedence of similar items and accounting treatment utilized by comparable companies under similar regulatory jurisdictions as well as evaluating progress in discussions between management and the regulator.
Wildfire Insurance Fund Coverage Period
As described in Notes 1 and 12 to the consolidated financial statements, the Company accounted for the contributions to the Wildfire Insurance Fund similar to prepaid insurance. No period of coverage was provided in Assembly Bill 1054, therefore expense is being allocated to periods ratably based on an estimated period of coverage. As of December 31, 2019, the Company has a $2.8 billion long-term asset and a $323 million current asset reflected as "Wildfire Insurance Fund contributions" in the consolidated balance sheets, for an initial $2.4 billion contribution made during the third quarter of 2019 and the present value of annual contributions SCE committed to make to the Wildfire Insurance Fund, reduced by amortization. A period of 10 years is being used to amortize the asset. In estimating the period of coverage management used Monte Carlo simulations based on five years (2014 – 2018) of historical data from wildfires assumed to be caused by electrical utility equipment to estimate expected loss. The details of the operation of the Wildfire Insurance Fund and estimates related to claims from the fund, have been applied to the expected loss simulations to estimate the period of
coverage of the fund. As disclosed by management, the most sensitive inputs to the estimated period of coverage are the expected frequency of wildfire events caused by investor-owned utility electrical equipment and the estimated costs associated with those forecasted events.
The principal consideration for our determination that performing procedures relating to the wildfire insurance fund coverage period is a critical audit matter is there was significant judgment by management in estimating the period of coverage from the wildfire insurance fund. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management's estimated coverage period of the wildfire fund and the significant inputs, including the expected frequency of wildfire events caused by electrical utility equipment and the estimated costs associated with those forecasted events. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's estimate regarding the estimated coverage period of the wildfire insurance fund. These procedures also included, among others, testing management’s process for developing the wildfire insurance fund coverage period estimate; evaluating the appropriateness of the Monte Carlo simulation models; testing the completeness, accuracy, and relevance of underlying data used in the models; and evaluating the significant inputs used by management, including the expected frequency of wildfire events caused by electrical equipment and the estimated costs associated with those forecasted events. Evaluating management's inputs related to the expected frequency of wildfire events and the estimated costs associated with the forecasted events involved evaluating whether the inputs used by management were reasonable considering (i) the historical frequency and severity of wildfire events in the State of California, (ii) the historical costs associated with wildfire events in the State of California, and (iii) the current wildfire risk in the State of California. Professionals with specialized skill and knowledge were used to assist in the evaluation of the Company’s Monte Carlo simulation models.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 28, 201927, 2020
We have served as the Company's auditor since 2002.
Report of Independent Registered Public Accounting Firm
TotheBoard of Directors and Shareholders of Southern California Edison Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Southern California Edison Company and its subsidiaries (the "Company") as of December 31, 20182019 and 2017,2018, and the related consolidated statements of income, of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2018,2019, including the related notes and schedule of valuation and qualifying accounts for each of the three years in the period ended December 31, 20182019 appearing under Item 15 (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20182019 and 2017,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20182019 in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 28, 201927, 2020
We have served as the Company's auditor since 2002.
CONSOLIDATED FINANCIAL STATEMENTS
|
| | | | | | | | | | | |
| Consolidated Statements of Income | Edison International | |
|
| | |
| | Years ended December 31, |
| (in millions, except per share amounts) | 2019 | | 2018 | | 2017 |
| Total operating revenue | $ | 12,347 |
| | $ | 12,657 |
| | $ | 12,320 |
|
| Purchased power and fuel | 4,839 |
| | 5,406 |
| | 4,873 |
|
| Operation and maintenance | 3,018 |
| | 2,797 |
| | 2,844 |
|
| Wildfire-related claims, net of insurance recoveries | 255 |
| | 2,669 |
| | — |
|
| Wildfire insurance fund expense | 152 |
| | — |
| | — |
|
| Depreciation and amortization | 1,730 |
| | 1,871 |
| | 2,041 |
|
| Property and other taxes | 399 |
| | 395 |
| | 377 |
|
| Impairment and other | 184 |
| | 78 |
| | 738 |
|
| Other operating income | (5 | ) | | (7 | ) | | (9 | ) |
| Total operating expenses | 10,572 |
| | 13,209 |
| | 10,864 |
|
| Operating income (loss) | 1,775 |
| | (552 | ) | | 1,456 |
|
| Interest expense | (841 | ) | | (734 | ) | | (639 | ) |
| Other income | 193 |
| | 197 |
| | 132 |
|
| Income (loss) from continuing operations before income taxes | 1,127 |
| | (1,089 | ) | | 949 |
|
| Income tax (benefit) expense | (278 | ) | | (739 | ) | | 281 |
|
| Income (loss) from continuing operations | 1,405 |
| | (350 | ) | | 668 |
|
| Income from discontinued operations, net of tax | — |
| | 34 |
| | — |
|
| Net income (loss) | 1,405 |
| | (316 | ) | | 668 |
|
| Preferred and preference stock dividend requirements of SCE | 121 |
| | 121 |
| | 124 |
|
| Other noncontrolling interests | — |
| | (14 | ) | | (21 | ) |
| Net income (loss) attributable to Edison International common shareholders | $ | 1,284 |
| | $ | (423 | ) | | $ | 565 |
|
| Amounts attributable to Edison International common shareholders: | | | | | |
| Income (loss) from continuing operations, net of tax | $ | 1,284 |
| | $ | (457 | ) | | $ | 565 |
|
| Income from discontinued operations, net of tax | — |
| | 34 |
| | — |
|
| Net income (loss) attributable to Edison International common shareholders | $ | 1,284 |
| | $ | (423 | ) | | $ | 565 |
|
| Basic earnings (loss) per common share attributable to Edison International common shareholders: | | | | | |
| Weighted average shares of common stock outstanding | 340 |
| | 326 |
| | 326 |
|
| Continuing operations | $ | 3.78 |
| | $ | (1.40 | ) | | $ | 1.73 |
|
| Discontinued operations | — |
| | 0.10 |
| | — |
|
| Total | $ | 3.78 |
| | $ | (1.30 | ) | | $ | 1.73 |
|
| Diluted earnings (loss) per common share attributable to Edison International common shareholders: | | | | | |
| Weighted average shares of common stock outstanding, including effect of dilutive securities | 341 |
| | 326 |
| | 328 |
|
| Continuing operations | $ | 3.77 |
| | $ | (1.40 | ) | | $ | 1.72 |
|
| Discontinued operations | — |
| | 0.10 |
| | — |
|
| Total | $ | 3.77 |
| | $ | (1.30 | ) | | $ | 1.72 |
|
The accompanying notes are an integral part of these consolidated financial statements.
50
|
| | | | | | | | | | | | |
| Consolidated Statements of Comprehensive Income | | Edison International | |
| | | | | |
| | | Years ended December 31, |
| (in millions) | | 2019 | | 2018 | | 2017 |
| Net income (loss) | | $ | 1,405 |
| | $ | (316 | ) | | $ | 668 |
|
| Other comprehensive (loss) income, net of tax: | | | | | | |
| Pension and postretirement benefits other than pensions: | | | | | | |
| Net (loss) income arising during period plus amortization of net loss included in net income | | (9 | ) | | (3 | ) | | 10 |
|
| Other | | — |
| | (4 | ) | | — |
|
| Other comprehensive (loss) income, net of tax | | (9 | ) | | (7 | ) | | 10 |
|
| Comprehensive income (loss) | | 1,396 |
| | (323 | ) | | 678 |
|
| Less: Comprehensive income attributable to noncontrolling interests | | 121 |
| | 107 |
| | 103 |
|
| Comprehensive income (loss) attributable to Edison International | | $ | 1,275 |
| | $ | (430 | ) | | $ | 575 |
|
The accompanying notes are an integral part of these consolidated financial statements.
51
|
| | | | | | | | |
| Consolidated Balance Sheets | | Edison International | |
| | | | | |
| | | December 31, |
| (in millions) | | 2019 | | 2018 |
| ASSETS | | | | |
| Cash and cash equivalents | | $ | 68 |
| | $ | 144 |
|
| Receivables, less allowances of $50 and $52 for uncollectible accounts at respective dates | | 788 |
| | 730 |
|
| Accrued unbilled revenue | | 488 |
| | 482 |
|
| Inventory | | 364 |
| | 282 |
|
| Income tax receivables | | 118 |
| | 191 |
|
| Prepaid expenses | | 214 |
| | 148 |
|
| Derivative assets | | 81 |
| | 171 |
|
| Regulatory assets | | 1,009 |
| | 1,133 |
|
| Wildfire Insurance Fund contributions | | 323 |
| | — |
|
| Other current assets | | 107 |
| | 78 |
|
| Total current assets | | 3,560 |
| | 3,359 |
|
| Nuclear decommissioning trusts | | 4,562 |
| | 4,120 |
|
| Other investments | | 64 |
| | 63 |
|
| Total investments | | 4,626 |
| | 4,183 |
|
| Utility property, plant and equipment, less accumulated depreciation and amortization of $9,958 and $9,566 at respective dates | | 44,198 |
| | 41,269 |
|
| Nonutility property, plant and equipment, less accumulated depreciation of $86 and $82 at respective dates | | 87 |
| | 79 |
|
| Total property, plant and equipment | | 44,285 |
| | 41,348 |
|
| Regulatory assets | | 6,088 |
| | 5,380 |
|
| Wildfire Insurance Fund contributions | | 2,767 |
| | — |
|
| Operating lease right-of-use assets | | 693 |
| | — |
|
| Other long-term assets | | 2,363 |
| | 2,445 |
|
| Total long-term assets | | 11,911 |
| | 7,825 |
|
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Total assets | | $ | 64,382 |
| | $ | 56,715 |
|
|
| | | | | | | | |
| Consolidated Balance Sheets | | Edison International | |
| | | | | |
| | | December 31, |
| (in millions, except share amounts) | | 2019 | | 2018 |
| LIABILITIES AND EQUITY | | | | |
| Short-term debt | | $ | 550 |
| | $ | 720 |
|
| Current portion of long-term debt | | 479 |
| | 79 |
|
| Accounts payable | | 1,752 |
| | 1,511 |
|
| Customer deposits | | 302 |
| | 299 |
|
| Regulatory liabilities | | 972 |
| | 1,532 |
|
| Current portion of operating lease liabilities | | 80 |
| | — |
|
| Other current liabilities | | 1,388 |
| | 1,254 |
|
| Total current liabilities | | 5,523 |
| | 5,395 |
|
| Long-term debt | | 17,864 |
| | 14,632 |
|
| Deferred income taxes and credits | | 5,078 |
| | 4,576 |
|
| Pensions and benefits | | 674 |
| | 869 |
|
| Asset retirement obligations | | 3,029 |
| | 3,031 |
|
| Regulatory liabilities | | 8,385 |
| | 8,329 |
|
| Operating lease liabilities | | 613 |
| | — |
|
| Wildfire-related claims | | 4,568 |
| | 4,669 |
|
| Other deferred credits and other long-term liabilities | | 3,152 |
| | 2,562 |
|
| Total deferred credits and other liabilities | | 25,499 |
| | 24,036 |
|
| Total liabilities | | 48,886 |
| | 44,063 |
|
| Commitments and contingencies (Note 12) | |
| |
|
| Common stock, no par value (800,000,000 shares authorized; 361,985,133 and 325,811,206 shares issued and outstanding at respective dates) | | 4,990 |
| | 2,545 |
|
| Accumulated other comprehensive loss | | (69 | ) | | (50 | ) |
| Retained earnings | | 8,382 |
| | 7,964 |
|
| Total Edison International's common shareholders' equity | | 13,303 |
| | 10,459 |
|
| Noncontrolling interests – preferred and preference stock of SCE | | 2,193 |
| | 2,193 |
|
| Total equity | | 15,496 |
| | 12,652 |
|
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Total liabilities and equity | | $ | 64,382 |
| | $ | 56,715 |
|
The accompanying notes are an integral part of these consolidated financial statements.
53
|
| | | | | | | | | | | | |
| Consolidated Statements of Cash Flows | | Edison International | |
| | | |
| | | Years ended December 31, |
| (in millions) | | 2019 | | 2018 | | 2017 |
| Cash flows from operating activities: | | | | | | |
| Net income (loss) | | $ | 1,405 |
| | $ | (316 | ) | | $ | 668 |
|
| Less: Income from discontinued operations | | — |
| | 34 |
| | — |
|
| Income (loss) from continuing operations | | 1,405 |
| | (350 | ) | | 668 |
|
| Adjustments to reconcile to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 1,803 |
| | 1,940 |
| | 2,115 |
|
| Allowance for equity during construction | | (101 | ) | | (104 | ) | | (87 | ) |
| Impairment and other | | 184 |
| | 78 |
| | 738 |
|
| Deferred income taxes | | (284 | ) | | (527 | ) | | 498 |
|
| Wildfire Insurance Fund amortization expense | | 152 |
| | — |
| | — |
|
| Other | | 29 |
| | 35 |
| | 34 |
|
| Nuclear decommissioning trusts | | (106 | ) | | (109 | ) | | (197 | ) |
| Contributions to Wildfire Insurance Fund | | (2,457 | ) | | — |
| | — |
|
| Changes in operating assets and liabilities: | | | | | | |
| Receivables | | (76 | ) | | (39 | ) | | 6 |
|
| Inventory | | (83 | ) | | (49 | ) | | (12 | ) |
| Accounts payable | | 288 |
| | (31 | ) | | 50 |
|
| Tax receivables and payables | | 88 |
| | 32 |
| | (250 | ) |
| Other current assets and liabilities | | (13 | ) | | (79 | ) | | 7 |
|
| Regulatory assets and liabilities, net | | (1,278 | ) | | (92 | ) | | 4 |
|
| Wildfire-related insurance receivable | | 285 |
| | (2,000 | ) | | — |
|
| Wildfire-related claims | | (101 | ) | | 4,669 |
| | — |
|
| Other noncurrent assets and liabilities | | (42 | ) | | (197 | ) | | 23 |
|
| Net cash (used in) provided by operating activities | | (307 | ) | | 3,177 |
| | 3,597 |
|
| Cash flows from financing activities: | | | | | | |
| Long-term debt issued or remarketed, net of premium, discount and issuance costs of $4, $63 and $2 for the respective years | | 3,696 |
| | 3,237 |
| | 2,233 |
|
| Long-term debt repaid | | (82 | ) | | (654 | ) | | (1,285 | ) |
| Term loan issued | | 1,750 |
| | — |
| | — |
|
| Term loan repaid | | (1,750 | ) | | — |
| | — |
|
| Common stock issued | | 2,391 |
| | — |
| | — |
|
| Preference stock issued, net | | — |
| | — |
| | 462 |
|
| Preference stock redeemed | | — |
| | — |
| | (475 | ) |
| Short-term debt financing, net | | (172 | ) | | (1,611 | ) | | 1,084 |
|
| Payments for stock-based compensation | | (64 | ) | | (46 | ) | | (393 | ) |
| Receipts from stock option exercises | | 58 |
| | 26 |
| | 215 |
|
| Dividends and distribution to noncontrolling interests | | (121 | ) | | (121 | ) | | (125 | ) |
| Dividends paid | | (810 | ) | | (788 | ) | | (707 | ) |
| Other | | 7 |
| | 39 |
| | (2 | ) |
| Net cash provided by financing activities | | 4,903 |
| | 82 |
| | 1,007 |
|
| Cash flows from investing activities: | | | | | | |
| Capital expenditures | | (4,877 | ) | | (4,509 | ) | | (3,844 | ) |
| Proceeds from sale of nuclear decommissioning trust investments | | 4,389 |
| | 4,340 |
| | 5,239 |
|
| Purchases of nuclear decommissioning trust investments | | (4,283 | ) | | (4,231 | ) | | (5,042 | ) |
| Proceeds from sale of SoCore Energy, net of cash acquired by buyer | | — |
| | 78 |
| | — |
|
| Other | | 93 |
| | 83 |
| | 61 |
|
| Net cash used in investing activities | | (4,678 | ) | | (4,239 | ) | | (3,586 | ) |
| Net (decrease) increase in cash, cash equivalents and restricted cash | | (82 | ) | | (980 | ) | | 1,018 |
|
| Cash, cash equivalents and restricted cash at beginning of year | | 152 |
| | 1,132 |
| | 114 |
|
| Cash, cash equivalents and restricted cash at end of year | | $ | 70 |
| | $ | 152 |
| | $ | 1,132 |
|
The accompanying notes are an integral part of these consolidated financial statements.
54
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Statements of Changes in Equity | | | | | | | | Edison International | |
| | | | | | | | |
| | Equity Attributable to Common Shareholders | | Noncontrolling Interests | | |
| (in millions, except per share amounts) | Common
Stock | | Accumulated
Other
Comprehensive
Loss | | Retained
Earnings | | Subtotal | | Other | | Preferred
and
Preference
Stock | | Total
Equity |
| Balance at December 31, 2016 | $ | 2,505 |
| | $ | (53 | ) | | $ | 9,544 |
| | $ | 11,996 |
| | $ | — |
| | $ | 2,191 |
| | $ | 14,187 |
|
| Net income (loss) | — |
| | — |
| | 565 |
| | 565 |
| | (18 | ) | | 124 |
| | 671 |
|
| Other comprehensive income | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Contribution from tax equity investor | — |
| | — |
| | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Common stock dividends declared ($2.2325 per share) | — |
| | — |
| | (727 | ) | | (727 | ) | | — |
| | — |
| | (727 | ) |
| Dividends to noncontrolling interests ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | — |
| | (124 | ) | | (124 | ) |
| Stock-based compensation | — |
| | — |
| | (179 | ) | | (179 | ) | | — |
| | — |
| | (179 | ) |
| Noncash stock-based compensation | 21 |
| | — |
| | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Issuance of preference stock | — |
| | — |
| | — |
| | — |
| | — |
| | 462 |
| | 462 |
|
| Redemption of preference stock | — |
| | — |
| | (15 | ) | | (15 | ) | | — |
| | (460 | ) | | (475 | ) |
| Balance at December 31, 2017 | $ | 2,526 |
| | $ | (43 | ) | | $ | 9,188 |
| | $ | 11,671 |
| | $ | 2 |
| | $ | 2,193 |
| | $ | 13,866 |
|
| Net (loss) income | — |
| | — |
| | (423 | ) | | (423 | ) | | (11 | ) | | 121 |
| | (313 | ) |
| Other comprehensive loss | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) |
| Cumulative effect of accounting changes | — |
| | (5 | ) | | 10 |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Contribution from tax equity investor | — |
| | — |
| | — |
| | — |
| | 24 |
| | — |
| | 24 |
|
| Common stock dividends declared ($2.4275 per share) | — |
| | — |
| | (791 | ) | | (791 | ) | | — |
| | — |
| | (791 | ) |
| Dividends to noncontrolling interests ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | — |
| | (121 | ) | | (121 | ) |
| Stock-based compensation | — |
| | — |
| | (20 | ) | | (20 | ) | | — |
| | — |
| | (20 | ) |
| Noncash stock-based compensation | 19 |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | 19 |
|
| Deconsolidation of SoCore Energy | — |
| | — |
| | — |
| | — |
| | (15 | ) | | — |
| | (15 | ) |
| Balance at December 31, 2018 | $ | 2,545 |
| | $ | (50 | ) | | $ | 7,964 |
| | $ | 10,459 |
| | $ | — |
| | $ | 2,193 |
| | $ | 12,652 |
|
| Net income | — |
| | — |
| | 1,284 |
| | 1,284 |
| | — |
| | 121 |
| | 1,405 |
|
| Other comprehensive loss | — |
| | (9 | ) | | — |
| | (9 | ) | | — |
| | — |
| | (9 | ) |
| Cumulative effect of accounting change (Note 1) | — |
| | (10 | ) | | 10 |
| | — |
| | — |
| | — |
| | — |
|
| Common stock issued, net of issuance cost (Note 14) | 2,421 |
| | — |
| | — |
| | 2,421 |
| | — |
| | — |
| | 2,421 |
|
| Common stock dividends declared ($2.4750 per share) | — |
| | — |
| | (849 | ) | | (849 | ) | | — |
| | — |
| | (849 | ) |
| Dividends to noncontrolling interests ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | — |
| | (121 | ) | | (121 | ) |
| Stock-based compensation | — |
| | — |
| | (27 | ) | | (27 | ) | | — |
| | — |
| | (27 | ) |
| Noncash stock-based compensation | 24 |
| | — |
| | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Balance at December 31, 2019 | $ | 4,990 |
| | $ | (69 | ) | | $ | 8,382 |
| | $ | 13,303 |
| | $ | — |
| | $ | 2,193 |
| | $ | 15,496 |
|
The accompanying notes are an integral part of these consolidated financial statements.
55
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CONSOLIDATED STATEMENTS
|
| | | | | | | | | | | |
| Consolidated Statements of Income | Edison International | |
|
| | |
| | Years ended December 31, |
| (in millions, except per-share amounts) | 2018 | | 2017 | | 2016 |
| Total operating revenue | $ | 12,657 |
| | $ | 12,320 |
| | $ | 11,869 |
|
| Purchased power and fuel | 5,406 |
| | 4,873 |
| | 4,527 |
|
| Operation and maintenance | 2,797 |
| | 2,844 |
| | 2,898 |
|
| Wildfire-related claims, net of insurance recoveries | 2,669 |
| | — |
| | — |
|
| Depreciation and amortization | 1,871 |
| | 2,041 |
| | 2,007 |
|
| Property and other taxes | 395 |
| | 377 |
| | 354 |
|
| Impairment and other | 78 |
| | 738 |
| | 21 |
|
| Other operating income | (7 | ) | | (9 | ) | | — |
|
| Total operating expenses | 13,209 |
| | 10,864 |
| | 9,807 |
|
| Operating (loss) income | (552 | ) | | 1,456 |
| | 2,062 |
|
| Interest expense | (734 | ) | | (639 | ) | | (581 | ) |
| Other income and expenses | 197 |
| | 132 |
| | 109 |
|
| (Loss) income from continuing operations before income taxes | (1,089 | ) | | 949 |
| | 1,590 |
|
| Income tax (benefit) expense | (739 | ) | | 281 |
| | 177 |
|
| (Loss) income from continuing operations | (350 | ) | | 668 |
| | 1,413 |
|
| Income from discontinued operations, net of tax | 34 |
| | — |
| | 12 |
|
| Net (loss) income | (316 | ) | | 668 |
| | 1,425 |
|
| Preferred and preference stock dividend requirements of utility | 121 |
| | 124 |
| | 123 |
|
| Other noncontrolling interests | (14 | ) | | (21 | ) | | (9 | ) |
| Net (loss) income attributable to Edison International common shareholders | $ | (423 | ) | | $ | 565 |
| | $ | 1,311 |
|
| Amounts attributable to Edison International common shareholders: | | | | | |
| (Loss) income from continuing operations, net of tax | $ | (457 | ) | | $ | 565 |
| | $ | 1,299 |
|
| Income from discontinued operations, net of tax | 34 |
| | — |
| | 12 |
|
| Net (loss) income attributable to Edison International common shareholders | $ | (423 | ) | | $ | 565 |
| | $ | 1,311 |
|
| Basic (loss) earnings per common share attributable to Edison International common shareholders: | | | | | |
| Weighted-average shares of common stock outstanding | 326 |
| | 326 |
| | 326 |
|
| Continuing operations | $ | (1.40 | ) | | $ | 1.73 |
| | $ | 3.99 |
|
| Discontinued operations | 0.10 |
| | — |
| | 0.03 |
|
| Total | $ | (1.30 | ) | | $ | 1.73 |
| | $ | 4.02 |
|
| Diluted (loss) earnings per common share attributable to Edison International common shareholders: | | | | | |
| Weighted-average shares of common stock outstanding, including effect of dilutive securities | 326 |
| | 328 |
| | 330 |
|
| Continuing operations | $ | (1.40 | ) | | $ | 1.72 |
| | $ | 3.94 |
|
| Discontinued operations | 0.10 |
| | — |
| | 0.03 |
|
| Total | $ | (1.30 | ) | | $ | 1.72 |
| | $ | 3.97 |
|
|
| | | | | | | | | | | | |
| Consolidated Statements of Comprehensive Income | | Edison International | |
| | | | | |
| | | Years ended December 31, |
| (in millions) | | 2018 | | 2017 | | 2016 |
| Net (loss) income | | $ | (316 | ) | | $ | 668 |
| | $ | 1,425 |
|
| Other comprehensive (loss) income, net of tax: | | | | | | |
| Pension and postretirement benefits other than pensions: | | | | | | |
| Net (loss) gain arising during the period plus amortization included in net income | | (3 | ) | | 10 |
| | 2 |
|
| Other | | (4 | ) | | — |
| | 1 |
|
| Other comprehensive (loss) income, net of tax | | (7 | ) | | 10 |
| | 3 |
|
| Comprehensive (loss) income | | (323 | ) | | 678 |
| | 1,428 |
|
| Less: Comprehensive income attributable to noncontrolling interests | | 107 |
| | 103 |
| | 114 |
|
| Comprehensive (loss) income attributable to Edison International | | $ | (430 | ) | | $ | 575 |
| | $ | 1,314 |
|
|
| | | | | | | | |
| Consolidated Balance Sheets | | Edison International | |
| | | | | |
| | | December 31, |
| (in millions) | | 2018 | | 2017 |
| ASSETS | | | | |
| Cash and cash equivalents | | $ | 144 |
| | $ | 1,091 |
|
| Receivables, less allowances of $52 and $54 for uncollectible accounts at respective dates | | 730 |
| | 717 |
|
| Accrued unbilled revenue | | 482 |
| | 212 |
|
| Inventory | | 282 |
| | 242 |
|
| Income tax receivables | | 191 |
| | 224 |
|
| Prepaid expenses | | 148 |
| | 233 |
|
| Derivative assets | | 171 |
| | 105 |
|
| Regulatory assets | | 1,133 |
| | 703 |
|
| Other current assets | | 78 |
| | 202 |
|
| Total current assets | | 3,359 |
| | 3,729 |
|
| Nuclear decommissioning trusts | | 4,120 |
| | 4,440 |
|
| Other investments | | 63 |
| | 73 |
|
| Total investments | | 4,183 |
| | 4,513 |
|
| Utility property, plant and equipment, less accumulated depreciation and amortization of $9,566 and $9,355 at respective dates | | 41,269 |
| | 38,708 |
|
| Nonutility property, plant and equipment, less accumulated depreciation of $82 and $114 at respective dates | | 79 |
| | 342 |
|
| Total property, plant and equipment | | 41,348 |
| | 39,050 |
|
| Regulatory assets | | 5,380 |
| | 4,914 |
|
| Other long-term assets | | 2,445 |
| | 374 |
|
| Total long-term assets | | 7,825 |
| | 5,288 |
|
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Total assets | | $ | 56,715 |
| | $ | 52,580 |
|
|
| | | | | | | | |
| Consolidated Balance Sheets | | Edison International | |
| | | | | |
| | | December 31, |
| (in millions, except share amounts) | | 2018 | | 2017 |
| LIABILITIES AND EQUITY | | | | |
| Short-term debt | | $ | 720 |
| | $ | 2,393 |
|
| Current portion of long-term debt | | 79 |
| | 481 |
|
| Accounts payable | | 1,511 |
| | 1,503 |
|
| Accrued taxes | | 21 |
| | 23 |
|
| Customer deposits | | 299 |
| | 281 |
|
| Regulatory liabilities | | 1,532 |
| | 1,121 |
|
| Other current liabilities | | 1,233 |
| | 1,266 |
|
| Total current liabilities | | 5,395 |
| | 7,068 |
|
| Long-term debt | | 14,632 |
| | 11,642 |
|
| Deferred income taxes and credits | | 4,576 |
| | 4,567 |
|
| Pensions and benefits | | 869 |
| | 943 |
|
| Asset retirement obligations | | 3,031 |
| | 2,908 |
|
| Regulatory liabilities | | 8,329 |
| | 8,614 |
|
| Wildfire-related claims | | 4,669 |
| | — |
|
| Other deferred credits and other long-term liabilities | | 2,562 |
| | 2,953 |
|
| Total deferred credits and other liabilities | | 24,036 |
| | 19,985 |
|
| Total liabilities | | 44,063 |
| | 38,695 |
|
| Commitments and contingencies (Note 12) | |
| |
|
| Redeemable noncontrolling interest | | — |
| | 19 |
|
| Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at respective dates) | | 2,545 |
| | 2,526 |
|
| Accumulated other comprehensive loss | | (50 | ) | | (43 | ) |
| Retained earnings | | 7,964 |
| | 9,188 |
|
| Total Edison International's common shareholders' equity | | 10,459 |
| | 11,671 |
|
Noncontrolling interests – preferred and preference stock of SCE | | 2,193 |
| | 2,193 |
|
| Other noncontrolling interests | | — |
| | 2 |
|
| Total equity | | 12,652 |
| | 13,866 |
|
| | | | | |
| | | | | |
| Total liabilities and equity | | $ | 56,715 |
| | $ | 52,580 |
|
|
| | | | | | | | | | | | |
| Consolidated Statements of Cash Flows | | Edison International | |
| | | |
| | | Years ended December 31, |
| (in millions) | | 2018 | | 2017 | | 2016 |
| Cash flows from operating activities: | | | | | | |
| Net (loss) income | | $ | (316 | ) | | $ | 668 |
| | $ | 1,425 |
|
| Less: Income from discontinued operations | | 34 |
| | — |
| | 12 |
|
| (Loss) income from continuing operations | | (350 | ) | | 668 |
| | 1,413 |
|
| Adjustments to reconcile to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 1,940 |
| | 2,115 |
| | 2,098 |
|
| Allowance for equity during construction | | (104 | ) | | (87 | ) | | (74 | ) |
| Impairment and other | | 78 |
| | 738 |
| | — |
|
| Deferred income taxes and investment tax credits | | (527 | ) | | 498 |
| | 190 |
|
| Other | | 35 |
| | 34 |
| | 29 |
|
| Nuclear decommissioning trusts | | (109 | ) | | (197 | ) | | (179 | ) |
| EME settlement payments, net of insurance proceeds | | — |
| | — |
| | (209 | ) |
| Changes in operating assets and liabilities: | | | | | | |
| Receivables | | (39 | ) | | 6 |
| | 50 |
|
| Inventory | | (49 | ) | | (12 | ) | | 8 |
|
| Accounts payable | | (31 | ) | | 50 |
| | 35 |
|
| Tax receivables and payables | | 32 |
| | (250 | ) | | (6 | ) |
| Other current assets and liabilities | | (79 | ) | | 7 |
| | 220 |
|
| Regulatory assets and liabilities, net | | (92 | ) | | 4 |
| | (292 | ) |
| Wildfire-related insurance receivable | | (2,000 | ) | | — |
| | — |
|
| Wildfire-related claims | | 4,669 |
| | — |
| | — |
|
| Other noncurrent assets and liabilities | | (197 | ) | | 23 |
| | (29 | ) |
| Net cash provided by operating activities | | 3,177 |
| | 3,597 |
| | 3,254 |
|
| Cash flows from financing activities: | | | | | | |
| Long-term debt issued or remarketed, net of (discount), premium and issuance costs of $(63), $(2), and $(7) for respective years | | 3,237 |
| | 2,233 |
| | 397 |
|
| Long-term debt matured or repurchased | | (654 | ) | | (1,285 | ) | | (220 | ) |
| Preference stock issued, net | | — |
| | 462 |
| | 294 |
|
| Preference stock redeemed | | — |
| | (475 | ) | | (125 | ) |
| Short-term debt financing, net | | (1,611 | ) | | 1,084 |
| | 611 |
|
| Payments for stock-based compensation | | (46 | ) | | (393 | ) | | (237 | ) |
| Receipts from stock option exercises | | 26 |
| | 215 |
| | 135 |
|
| Dividends and distribution to noncontrolling interests | | (121 | ) | | (125 | ) | | (123 | ) |
| Dividends paid | | (788 | ) | | (707 | ) | | (626 | ) |
| Other | | 39 |
| | (2 | ) | | (11 | ) |
| Net cash provided by financing activities | | 82 |
| | 1,007 |
| | 95 |
|
| Cash flows from investing activities: | | | | | | |
| Capital expenditures | | (4,509 | ) | | (3,844 | ) | | (3,749 | ) |
| Proceeds from sale of nuclear decommissioning trust investments | | 4,340 |
| | 5,239 |
| | 3,212 |
|
| Purchases of nuclear decommissioning trust investments | | (4,231 | ) | | (5,042 | ) | | (3,033 | ) |
| Proceeds from sale of SoCore Energy, net of cash acquired by buyer | | 78 |
| | — |
| | — |
|
| Other | | 83 |
| | 61 |
| | 167 |
|
| Net cash used in investing activities | | (4,239 | ) | | (3,586 | ) | | (3,403 | ) |
| Net (decrease) increase in cash, cash equivalent and restricted cash | | (980 | ) | | 1,018 |
| | (54 | ) |
| Cash, cash equivalents and restricted cash at beginning of year | | 1,132 |
| | 114 |
| | 168 |
|
| Cash, cash equivalents and restricted cash at end of year | | $ | 152 |
| | $ | 1,132 |
| | $ | 114 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated Statements of Changes in Equity | | | | | | | | Edison International | |
| | | | | | | | |
| | Equity Attributable to Common Shareholders | | Noncontrolling Interests | | |
| (in millions) | Common
Stock | | Accumulated
Other
Comprehensive
Loss | | Retained
Earnings | | Subtotal | | Other | | Preferred
and
Preference
Stock | | Total
Equity |
| Balance at December 31, 2015 | $ | 2,484 |
| | $ | (56 | ) | | $ | 8,940 |
| | $ | 11,368 |
| | $ | — |
| | $ | 2,020 |
| | $ | 13,388 |
|
| Net income | — |
| | — |
| | 1,311 |
| | 1,311 |
| | — |
| | 123 |
| | 1,434 |
|
| Other comprehensive income | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Common stock dividends declared ($1.9825 per share) | — |
| | — |
| | (646 | ) | | (646 | ) | | — |
| | — |
| | (646 | ) |
| Dividends to noncontrolling interests ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | — |
| | (123 | ) | | (123 | ) |
| Stock-based compensation | (1 | ) | | — |
| | (59 | ) | | (60 | ) | | — |
| | — |
| | (60 | ) |
| Noncash stock-based compensation | 22 |
| | — |
| | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
| Issuance of preference stock | — |
| | — |
| | — |
| | — |
| | — |
| | 294 |
| | 294 |
|
| Redemption of preference stock | — |
| | — |
| | (2 | ) | | (2 | ) | | — |
| | (123 | ) | | (125 | ) |
| Balance at December 31, 2016 | $ | 2,505 |
| | $ | (53 | ) | | $ | 9,544 |
| | $ | 11,996 |
| | $ | — |
| | $ | 2,191 |
| | $ | 14,187 |
|
| Net income (loss) | — |
| | — |
| | 565 |
| | 565 |
| | (18 | ) | | 124 |
| | 671 |
|
| Other comprehensive income | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
| Contribution from tax equity investor | — |
| | — |
| | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Common stock dividends declared ($2.2325 per share) | — |
| | — |
| | (727 | ) | | (727 | ) | | — |
| | — |
| | (727 | ) |
| Dividends to noncontrolling interests ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | — |
| | (124 | ) | | (124 | ) |
| Stock-based compensation | — |
| | — |
| | (179 | ) | | (179 | ) | | — |
| | — |
| | (179 | ) |
| Noncash stock-based compensation | 21 |
| | — |
| | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Issuance of preference stock | — |
| | — |
| | — |
| | — |
| | — |
| | 462 |
| | 462 |
|
| Redemption of preference stock | — |
| | — |
| | (15 | ) | | (15 | ) | | — |
| | (460 | ) | | (475 | ) |
| Balance at December 31, 2017 | $ | 2,526 |
| | $ | (43 | ) | | $ | 9,188 |
| | $ | 11,671 |
| | $ | 2 |
| | $ | 2,193 |
| | $ | 13,866 |
|
| Net (loss) income | — |
| | — |
| | (423 | ) | | (423 | ) | | (11 | ) | | 121 |
| | (313 | ) |
| Other comprehensive loss | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) |
| Cumulative effect of accounting changes | — |
| | (5 | ) | | 10 |
| | 5 |
| | — |
| | — |
| | 5 |
|
| Contribution from tax equity investor | — |
|
| — |
|
| — |
|
| — |
|
| 24 |
| | — |
|
| 24 |
|
| Common stock dividends declared ($2.4275 per share) | — |
| | — |
| | (791 | ) | | (791 | ) | | — |
| | — |
| | (791 | ) |
| Dividends to noncontrolling interests ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | — |
| | (121 | ) | | (121 | ) |
| Stock-based compensation | — |
| | — |
| | (20 | ) | | (20 | ) | | — |
| | — |
| | (20 | ) |
| Noncash stock-based compensation | 19 |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | 19 |
|
| Deconsolidation of SoCore Energy | — |
| | — |
| | — |
| | — |
| | (15 | ) | | — |
| | (15 | ) |
| Balance at December 31, 2018 | $ | 2,545 |
| | $ | (50 | ) | | $ | 7,964 |
| | $ | 10,459 |
| | $ | — |
| | $ | 2,193 |
| | $ | 12,652 |
|
(This page has been left blank intentionally.)
|
| |
| Consolidated Statements of Income | Southern California Edison Company |
| | | | | Years ended December 31, | | Years ended December 31, |
| (in millions) | | 2018 | | 2017 | | 2016 | | 2019 | | 2018 | | 2017 |
| Operating revenue | | $ | 12,611 |
| | $ | 12,254 |
| | $ | 11,830 |
| | $ | 12,306 |
| | $ | 12,611 |
| | $ | 12,254 |
|
| Purchased power and fuel | | 5,406 |
| | 4,873 |
| | 4,527 |
| | 4,839 |
| | 5,406 |
| | 4,873 |
|
| Operation and maintenance | | 2,702 |
| | 2,722 |
| | 2,772 |
| | 2,936 |
| | 2,702 |
| | 2,722 |
|
| Wildfire-related claims, net of insurance recoveries | | 2,669 |
| | — |
| | — |
| | 255 |
| | 2,669 |
| | — |
|
| Wildfire insurance fund expense | | | 152 |
| | — |
| | — |
|
| Depreciation and amortization | | 1,867 |
| | 2,032 |
| | 1,998 |
| | 1,728 |
| | 1,867 |
| | 2,032 |
|
| Property and other taxes | | 392 |
| | 372 |
| | 351 |
| | 396 |
| | 392 |
| | 372 |
|
| Impairment and other | | (12 | ) | | 716 |
| | — |
| | 159 |
| | (12 | ) | | 716 |
|
| Other operating income | | (7 | ) | | (8 | ) | | — |
| | (4 | ) | | (7 | ) | | (8 | ) |
| Total operating expenses | | 13,017 |
| | 10,707 |
| | 9,648 |
| | 10,461 |
| | 13,017 |
| | 10,707 |
|
| Operating (loss) income | | (406 | ) | | 1,547 |
| | 2,182 |
| |
| Operating income (loss) | | | 1,845 |
| | (406 | ) | | 1,547 |
|
| Interest expense | | (673 | ) | | (589 | ) | | (541 | ) | | (739 | ) | | (673 | ) | | (589 | ) |
| Other income and expenses | | 194 |
| | 148 |
| | 114 |
| |
| (Loss) income before income taxes | | (885 | ) | | 1,106 |
| | 1,755 |
| |
| Income tax (benefit) expense | | (696 | ) | | (30 | ) | | 256 |
| |
| Net (loss) income | | (189 | ) | | 1,136 |
| | 1,499 |
| |
| Other income | | | 195 |
| | 194 |
| | 148 |
|
| Income (loss) before taxes | | | 1,301 |
| | (885 | ) | | 1,106 |
|
| Income tax benefit | | | (229 | ) | | (696 | ) | | (30 | ) |
| Net income (loss) | | | 1,530 |
| | (189 | ) | | 1,136 |
|
| Less: Preferred and preference stock dividend requirements | | 121 |
| | 124 |
| | 123 |
| | 121 |
| | 121 |
| | 124 |
|
| Net (loss) income available for common stock | | $ | (310 | ) | | $ | 1,012 |
| | $ | 1,376 |
| |
| Net income (loss) available for common stock | | | $ | 1,409 |
| | $ | (310 | ) | | $ | 1,012 |
|
| | Consolidated Statements of Comprehensive Income | | | | | | |
| | | Years ended December 31, | | Years ended December 31, |
| (in millions) | | 2018 | | 2017 | | 2016 | | 2019 | | 2018 | | 2017 |
| Net (loss) income | | $ | (189 | ) | | $ | 1,136 |
| | $ | 1,499 |
| |
| Other comprehensive income (loss), net of tax: | | | | | | | |
| Net income (loss) | | | $ | 1,530 |
| | $ | (189 | ) | | $ | 1,136 |
|
| Other comprehensive (loss) income, net of tax: | | | | | | | |
| Pension and postretirement benefits other than pensions: | | | | | | | | | | | | |
| Net loss arising during period plus amortization included in net income | | 1 |
| | 1 |
| | 1 |
| |
| Net (loss) income arising during period plus amortization of net loss included in net income | | | (11 | ) | | 1 |
| | 1 |
|
| Other | | (5 | ) | | — |
| | 1 |
| | — |
| | (5 | ) | | — |
|
| Other comprehensive (loss) income, net of tax | | (4 | ) | | 1 |
| | 2 |
| | (11 | ) | | (4 | ) | | 1 |
|
| Comprehensive (loss) income | | $ | (193 | ) | | $ | 1,137 |
| | $ | 1,501 |
| |
| Comprehensive income (loss) | | | $ | 1,519 |
| | $ | (193 | ) | | $ | 1,137 |
|
The accompanying notes are an integral part of these consolidated financial statements.
57
|
| |
| Consolidated Balance Sheets | Southern California Edison Company |
| | | | | December 31, | | December 31, |
| (in millions) | | 2018 | | 2017 | | 2019 | | 2018 |
| ASSETS | | | | | | | | |
| Cash and cash equivalents | | $ | 21 |
| | $ | 515 |
| | $ | 24 |
| | $ | 21 |
|
| Receivables, less allowances of $51 and $53 for uncollectible accounts at respective dates | | 711 |
| | 693 |
| |
| Receivables, less allowances of $49 and $51 for uncollectible accounts at respective dates | | | 777 |
| | 711 |
|
| Accrued unbilled revenue | | 482 |
| | 212 |
| | 488 |
| | 482 |
|
| Inventory | | 282 |
| | 242 |
| | 364 |
| | 282 |
|
| Income tax receivables | | 312 |
| | 229 |
| | 148 |
| | 312 |
|
| Prepaid expenses | | 144 |
| | 228 |
| | 213 |
| | 144 |
|
| Derivative assets | | 171 |
| | 105 |
| | 81 |
| | 171 |
|
| Regulatory assets | | 1,133 |
| | 703 |
| | 1,009 |
| | 1,133 |
|
| Wildfire Insurance Fund contributions | | | 323 |
| | — |
|
| Other current assets | | 69 |
| | 160 |
| | 103 |
| | 69 |
|
| Total current assets | | 3,325 |
| | 3,087 |
| | 3,530 |
| | 3,325 |
|
| Nuclear decommissioning trusts | | 4,120 |
| | 4,440 |
| | 4,562 |
| | 4,120 |
|
| Other investments | | 45 |
| | 52 |
| | 46 |
| | 45 |
|
| Total investments | | 4,165 |
| | 4,492 |
| | 4,608 |
| | 4,165 |
|
| Utility property, plant and equipment, less accumulated depreciation and amortization of $9,566 and $9,355 at respective dates | | 41,269 |
| | 38,708 |
| |
| Nonutility property, plant and equipment, less accumulated depreciation of $77 and $97 at respective dates | | 75 |
| | 77 |
| |
| Utility property, plant and equipment, less accumulated depreciation and amortization of $9,958 and $9,566 at respective dates | | | 44,198 |
| | 41,269 |
|
| Nonutility property, plant and equipment, less accumulated depreciation of $80 and $77 at respective dates | | | 83 |
| | 75 |
|
| Total property, plant and equipment | | 41,344 |
| | 38,785 |
| | 44,281 |
| | 41,344 |
|
| Regulatory assets | | 5,380 |
| | 4,914 |
| | 6,088 |
| | 5,380 |
|
| Long-term insurance receivable due from affiliate | | 1,000 |
| | — |
| |
| Wildfire Insurance Fund contributions | | | 2,767 |
| | — |
|
| Operating lease right-of-use assets | | | 689 |
| | — |
|
| Long-term insurance receivables due from affiliate | | | 803 |
| | 1,000 |
|
| Other long-term assets | | 1,360 |
| | 237 |
| | 1,507 |
| | 1,360 |
|
| Total long-term assets | | 7,740 |
| | 5,151 |
| | 11,854 |
| | 7,740 |
|
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total assets | | $ | 56,574 |
| | $ | 51,515 |
| | $ | 64,273 |
| | $ | 56,574 |
|
|
| |
| Consolidated Balance Sheets | Southern California Edison Company |
| | | | | December 31, | | December 31, |
| (in millions, except share amounts) | | 2018 | | 2017 | | 2019 | | 2018 |
| LIABILITIES AND EQUITY | | | | | | | | |
| Short-term debt | | $ | 720 |
| | $ | 1,238 |
| | $ | 550 |
| | $ | 720 |
|
| Current portion of long-term debt | | 79 |
| | 479 |
| | 79 |
| | 79 |
|
| Accounts payable | | 1,519 |
| | 1,519 |
| | 1,779 |
| | 1,519 |
|
| Accrued taxes | | 22 |
| | 24 |
| |
| Customer deposits | | 299 |
| | 281 |
| | 302 |
| | 299 |
|
| Regulatory liabilities | | 1,532 |
| | 1,121 |
| | 972 |
| | 1,532 |
|
| Current portion of operating lease liabilities | | | 79 |
| | — |
|
| Other current liabilities | | 975 |
| | 1,225 |
| | 1,298 |
| | 997 |
|
| Total current liabilities | | 5,146 |
| | 5,887 |
| | 5,059 |
| | 5,146 |
|
| Long-term debt | | 12,892 |
| | 10,428 |
| | 15,132 |
| | 12,892 |
|
| Deferred income taxes and credits | | 5,898 |
| | 5,890 |
| | 6,451 |
| | 5,898 |
|
| Pensions and benefits | | 433 |
| | 483 |
| | 237 |
| | 433 |
|
| Asset retirement obligations | | 3,031 |
| | 2,892 |
| | 3,029 |
| | 3,031 |
|
| Regulatory liabilities | | 8,329 |
| | 8,614 |
| | 8,385 |
| | 8,329 |
|
| Operating lease liabilities | | | 610 |
| | — |
|
| Wildfire-related claims | | 4,669 |
| | — |
| | 4,568 |
| | 4,669 |
|
| Other deferred credits and other long-term liabilities | | 2,391 |
| | 2,649 |
| | 2,975 |
| | 2,391 |
|
| Total deferred credits and other liabilities | | 24,751 |
| | 20,528 |
| | 26,255 |
| | 24,751 |
|
| Total liabilities | | 42,789 |
| | 36,843 |
| | 46,446 |
| | 42,789 |
|
| Commitments and contingencies (Note 12) | |
|
| |
|
| |
|
| |
|
|
| Preferred and preference stock | | 2,245 |
| | 2,245 |
| | 2,245 |
| | 2,245 |
|
| Common stock, no par value (560,000,000 shares authorized; 434,888,104 shares issued and outstanding at respective dates) | | 2,168 |
| | 2,168 |
| | 2,168 |
| | 2,168 |
|
| Additional paid-in capital | | 680 |
| | 671 |
| | 3,939 |
| | 680 |
|
| Accumulated other comprehensive loss | | (23 | ) | | (19 | ) | | (39 | ) | | (23 | ) |
| Retained earnings | | 8,715 |
| | 9,607 |
| | 9,514 |
| | 8,715 |
|
| Total equity | | 13,785 |
| | 14,672 |
| | 17,827 |
| | 13,785 |
|
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total liabilities and equity | | $ | 56,574 |
| | $ | 51,515 |
| | $ | 64,273 |
| | $ | 56,574 |
|
The accompanying notes are an integral part of these consolidated financial statements.
59
| | | Consolidated Statements of Cash Flows | | Southern California Edison Company | | | Southern California Edison Company | |
| | | | | |
| |
| Years ended December 31, |
| Years ended December 31, |
| (in millions) |
| 2018 |
| 2017 |
| 2016 |
| 2019 |
| 2018 |
| 2017 |
| Cash flows from operating activities: |
| |
| |
| |
| |
| |
| |
| Net (loss) income |
| $ | (189 | ) |
| $ | 1,136 |
|
| $ | 1,499 |
| |
| Net income (loss) | |
| $ | 1,530 |
|
| $ | (189 | ) |
| $ | 1,136 |
|
| Adjustments to reconcile to net cash provided by operating activities: |
| |
| |
| |
| |
| |
| |
| Depreciation and amortization |
| 1,931 |
|
| 2,101 |
|
| 2,085 |
|
| 1,798 |
|
| 1,931 |
|
| 2,101 |
|
| Allowance for equity during construction |
| (104 | ) |
| (87 | ) |
| (74 | ) |
| (101 | ) |
| (104 | ) |
| (87 | ) |
| Impairment and other |
| (12 | ) |
| 716 |
|
| — |
|
| 159 |
|
| (12 | ) |
| 716 |
|
| Deferred income taxes and investment tax credits |
| (552 | ) |
| 304 |
|
| 88 |
| |
| Deferred income taxes | |
| (243 | ) |
| (552 | ) |
| 304 |
|
| Wildfire Insurance Fund amortization expense | | | 152 |
| | — |
| | — |
|
| Other |
| 28 |
|
| 24 |
|
| 18 |
|
| 17 |
|
| 28 |
|
| 24 |
|
| Nuclear decommissioning trusts | | (109 | ) | | (197 | ) | | (179 | ) | | (106 | ) | | (109 | ) | | (197 | ) |
| Contributions to Wildfire Insurance Fund | | | (2,457 | ) | | — |
| | — |
|
| Changes in operating assets and liabilities: |
| |
| |
| |
| |
| |
| |
| Receivables |
| (45 | ) |
| 5 |
|
| 23 |
|
| (89 | ) |
| (45 | ) |
| 5 |
|
| Inventory |
| (50 | ) |
| (11 | ) |
| (3 | ) |
| (83 | ) |
| (50 | ) |
| (11 | ) |
| Accounts payable |
| (43 | ) |
| 50 |
|
| 45 |
|
| 307 |
|
| (43 | ) |
| 50 |
|
| Tax receivables and payables |
| (84 | ) |
| (234 | ) |
| (16 | ) |
| 178 |
|
| (84 | ) |
| (234 | ) |
| Other current assets and liabilities |
| (91 | ) |
| 42 |
|
| 194 |
|
| (15 | ) |
| (91 | ) |
| 42 |
|
| Regulatory assets and liabilities, net |
| (92 | ) |
| 4 |
|
| (292 | ) |
| (1,278 | ) |
| (92 | ) |
| 4 |
|
| Wildfire-related insurance receivable | | (2,000 | ) | | — |
| | — |
| | 285 |
| | (2,000 | ) | | — |
|
| Wildfire-related claims | | 4,669 |
| | — |
| | — |
| | (101 | ) | | 4,669 |
| | — |
|
| Other noncurrent assets and liabilities |
| (66 | ) |
| (118 | ) |
| 133 |
|
| (44 | ) |
| (66 | ) |
| (118 | ) |
| Net cash provided by operating activities |
| 3,191 |
|
| 3,735 |
|
| 3,521 |
| |
| Net cash (used in) provided by operating activities | |
| (91 | ) |
| 3,191 |
|
| 3,735 |
|
| Cash flows from financing activities: |
| |
| |
| |
| |
| |
| |
| Long-term debt issued or remarketed, net of (discount), premium and issuance costs of $(58) and $10 for 2018 and 2017, respectively |
| 2,692 |
|
| 1,445 |
|
| — |
| |
| Long-term debt matured or repurchased |
| (639 | ) |
| (882 | ) |
| (217 | ) | |
| Long-term debt issued or remarketed, net of premium, discount and issuance costs of $6, $(58) and $10 for the respective years | |
| 2,306 |
|
| 2,692 |
|
| 1,445 |
|
| Long-term debt repaid | |
| (82 | ) |
| (639 | ) |
| (882 | ) |
| Term loan issued | | | 750 |
| | — |
| | — |
|
| Term loan repaid | | | (750 | ) | | — |
| | — |
|
| Capital contributions from Edison International Parent | | | 3,250 |
| | — |
| | — |
|
| Preference stock issued, net |
| — |
|
| 462 |
|
| 294 |
|
| — |
|
| — |
|
| 462 |
|
| Preference stock redeemed |
| — |
|
| (475 | ) |
| (125 | ) |
| — |
|
| — |
|
| (475 | ) |
| Short-term debt financing, net |
| (520 | ) |
| 469 |
|
| 719 |
|
| (171 | ) |
| (520 | ) |
| 469 |
|
| Payments for stock-based compensation | | (22 | ) | | (86 | ) | | (127 | ) | | (40 | ) | | (22 | ) | | (86 | ) |
| Receipts from stock option exercises | | 12 |
| | 48 |
| | 76 |
| | 22 |
| | 12 |
| | 48 |
|
| Dividends paid |
| (909 | ) |
| (697 | ) |
| (824 | ) |
| (521 | ) |
| (909 | ) |
| (697 | ) |
| Other | | 2 |
| | (41 | ) | | (15 | ) | | 7 |
| | 2 |
| | (41 | ) |
| Net cash provided by (used in) financing activities |
| 616 |
|
| 243 |
|
| (219 | ) | |
| Net cash provided by financing activities | |
| 4,771 |
|
| 616 |
|
| 243 |
|
| Cash flows from investing activities: |
| |
| |
| |
| |
| |
| |
| Capital expenditures |
| (4,491 | ) |
| (3,756 | ) |
| (3,648 | ) |
| (4,876 | ) |
| (4,491 | ) |
| (3,756 | ) |
| Proceeds from sale of nuclear decommissioning trust investments |
| 4,340 |
|
| 5,239 |
|
| 3,212 |
|
| 4,389 |
|
| 4,340 |
|
| 5,239 |
|
| Purchases of nuclear decommissioning trust investments |
| (4,231 | ) |
| (5,042 | ) |
| (3,033 | ) |
| (4,283 | ) |
| (4,231 | ) |
| (5,042 | ) |
| Other |
| 82 |
|
| 56 |
|
| 175 |
|
| 92 |
|
| 82 |
|
| 56 |
|
| Net cash used in investing activities |
| (4,300 | ) |
| (3,503 | ) |
| (3,294 | ) |
| (4,678 | ) |
| (4,300 | ) |
| (3,503 | ) |
| Net (decrease) increase in cash, cash equivalents and restricted cash |
| (493 | ) |
| 475 |
|
| 8 |
| |
| Net increase (decrease) in cash, cash equivalents and restricted cash | |
| 2 |
|
| (493 | ) |
| 475 |
|
| Cash, cash equivalents and restricted cash at beginning of year |
| 515 |
|
| 40 |
|
| 32 |
|
| 22 |
|
| 515 |
|
| 40 |
|
| Cash, cash equivalents and restricted cash at end of year |
| $ | 22 |
|
| $ | 515 |
|
| $ | 40 |
|
| $ | 24 |
|
| $ | 22 |
|
| $ | 515 |
|
The accompanying notes are an integral part of these consolidated financial statements.
60
|
| |
| Consolidated Statements of Changes in Equity | Southern California Edison Company |
| | | | | | | | | | | | | |
| (in millions) | Preferred
and
Preference
Stock | | Common
Stock | | Additional
Paid-in
Capital | | Accumulated
Other
Comprehensive
Loss | | Retained
Earnings | | Total
Equity | |
| Balance at December 31, 2015 | $ | 2,070 |
| | $ | 2,168 |
| | $ | 652 |
| | $ | (22 | ) | | $ | 8,804 |
| | $ | 13,672 |
| |
| Net income | — |
| | — |
| | — |
| | — |
| | 1,499 |
| | 1,499 |
| |
| Other comprehensive income | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
| |
| Dividends declared on common stock ($1.61 per share) | — |
| | — |
| | — |
| | — |
| | (701 | ) | | (701 | ) | |
| Dividends declared on preferred and preference stock ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | (123 | ) | | (123 | ) | |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | (44 | ) | | (44 | ) | |
| Noncash stock-based compensation | — |
| | — |
| | 9 |
| | — |
| | — |
| | 9 |
| |
| Issuance of preference stock | 300 |
| | — |
| | (6 | ) | | — |
| | — |
| | 294 |
| |
| Redemption of preference stock | (125 | ) | | — |
| | 2 |
| | — |
| | (2 | ) | | (125 | ) | |
| (in millions, except per share amounts) | | Preferred
and
Preference
Stock | | Common
Stock | | Additional
Paid-in
Capital | | Accumulated
Other
Comprehensive
Loss | | Retained
Earnings | | Total
Equity |
| Balance at December 31, 2016 | $ | 2,245 |
| | $ | 2,168 |
| | $ | 657 |
| | $ | (20 | ) | | $ | 9,433 |
| | $ | 14,483 |
| $ | 2,245 |
| | $ | 2,168 |
| | $ | 657 |
| | $ | (20 | ) | | $ | 9,433 |
| | $ | 14,483 |
|
| Net income | — |
| | — |
| | — |
| | — |
| | 1,136 |
| | 1,136 |
| — |
| | — |
| | — |
| | — |
| | 1,136 |
| | 1,136 |
|
| Other comprehensive income | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Dividends declared on common stock ($1.81 per share) | — |
| | — |
| | — |
| | — |
| | (785 | ) | | (785 | ) | |
| Dividends declared on preferred and preference stock ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | (124 | ) | | (124 | ) | |
| Dividends declared on common stock ($1.8051 per share) | | — |
| | — |
| | — |
| | — |
| | (785 | ) | | (785 | ) |
| Dividends declared on preferred stock ($1.02 - $1.195 per share) and preference stock ($62.50 - $143.75 per share) | | — |
| | — |
| | — |
| | — |
| | (124 | ) | | (124 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | (38 | ) | | (38 | ) | — |
| | — |
| | — |
| | — |
| | (38 | ) | | (38 | ) |
| Noncash stock-based compensation | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
| — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
| Issuance of preference stock | 475 |
| | — |
| | (13 | ) | | — |
| | — |
| | 462 |
| 475 |
| | — |
| | (13 | ) | | — |
| | — |
| | 462 |
|
| Redemption of preference stock | (475 | ) | | — |
| | 15 |
| | — |
| | (15 | ) | | (475 | ) | (475 | ) | | — |
| | 15 |
| | — |
| | (15 | ) | | (475 | ) |
| Balance at December 31, 2017 | $ | 2,245 |
| | $ | 2,168 |
| | $ | 671 |
| | $ | (19 | ) | | $ | 9,607 |
| | $ | 14,672 |
| $ | 2,245 |
| | $ | 2,168 |
| | $ | 671 |
| | $ | (19 | ) | | $ | 9,607 |
| | $ | 14,672 |
|
| Net loss | — |
| | — |
| | — |
| | — |
| | (189 | ) | | (189 | ) | — |
| | — |
| | — |
| | — |
| | (189 | ) | | (189 | ) |
| Other comprehensive income | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Cumulative effect of accounting change | — |
| | — |
| | — |
| | (5 | ) | | 5 |
| | — |
| — |
| | — |
| | — |
| | (5 | ) | | 5 |
| | — |
|
| Dividends declared on common stock ($1.32 per share) | — |
| | — |
| | — |
| | — |
| | (576 | ) | | (576 | ) | |
| Dividends declared on preferred and preference stock ($1.02 - $1.195 per share for preferred stock; $62.50 - $143.75 per share for preference stock) | — |
| | — |
| | — |
| | — |
| | (121 | ) | | (121 | ) | |
| Dividends declared on common stock ($1.3245 per share) | | — |
| | — |
| | — |
| | — |
| | (576 | ) | | (576 | ) |
| Dividends declared on preferred stock ($1.02 - $1.195 per share) and preference stock ($62.50 - $143.75 per share) | | — |
| | — |
| | — |
| | — |
| | (121 | ) | | (121 | ) |
| Stock-based compensation | — |
| | — |
| | — |
| | — |
| | (11 | ) | | (11 | ) | — |
| | — |
| | — |
| | — |
| | (11 | ) | | (11 | ) |
| Noncash stock-based compensation | — |
| | — |
| | 9 |
| | — |
| | — |
| | 9 |
| — |
| | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
| Balance at December 31, 2018 | $ | 2,245 |
| | $ | 2,168 |
| | $ | 680 |
| | $ | (23 | ) | | $ | 8,715 |
| | $ | 13,785 |
| $ | 2,245 |
| | $ | 2,168 |
| | $ | 680 |
| | $ | (23 | ) | | $ | 8,715 |
| | $ | 13,785 |
|
| Net income | | — |
| | — |
| | — |
| | — |
| | 1,530 |
| | 1,530 |
|
| Other comprehensive loss | | — |
| | — |
| | — |
| | (11 | ) | | — |
| | (11 | ) |
| Cumulative effect of accounting change (Note 1) | | — |
| | — |
| | — |
| | (5 | ) | | 5 |
| | — |
|
| Capital contribution from Edison International Parent (Note 14) | | — |
| | — |
| | 3,250 |
| | — |
| | — |
| | 3,250 |
|
| Dividends declared on common stock ($1.3797 per share) | | — |
| | — |
| | — |
| | — |
| | (600 | ) | | (600 | ) |
| Dividends declared on preferred stock ($1.02 - $1.195 per share) and preference stock ($62.50 - $143.75 per share) | | — |
| | — |
| | — |
| | — |
| | (121 | ) | | (121 | ) |
| Stock-based compensation | | — |
| | — |
| | (3 | ) | | — |
| | (15 | ) | | (18 | ) |
| Noncash stock-based compensation | | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
| Balance at December 31, 2019 | | $ | 2,245 |
| | $ | 2,168 |
| | $ | 3,939 |
| | $ | (39 | ) | | $ | 9,514 |
| | $ | 17,827 |
|
The accompanying notes are an integral part of these consolidated financial statements.
61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Organization and Basis of Presentation
Edison International is the parent holding company of Southern California Edison Company ("SCE") and Edison Energy Group, Inc. ("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, LLC ("Edison Energy") which is engaged in the competitive business of providing energy services to commercial and industrial customer.customers. Edison Energy's business activities are currently not material to report as a separate business segment. These combined notes to the consolidated financial statements apply to both Edison International and SCE unless otherwise described. Edison International's consolidated financial statements include the accounts of Edison International, SCE and other wholly owned and controlled subsidiaries. References to Edison International refer to the consolidated group of Edison International and its subsidiaries. References to "Edison International Parent and Other" refer to Edison International Parent and its competitive subsidiaries and "Edison International Parent" refer to Edison International on a stand-alone basis, not consolidated with its subsidiaries. SCE's consolidated financial statements include the accounts of SCE and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated from the consolidated financial statements.
Edison International's and SCE's accounting policies conform to accounting principles generally accepted in the United States of America, including the accounting principles for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utility Commission ("CPUC") and the Federal Energy Regulatory Commission ("FERC"). SCE applies authoritative guidance for rate-regulated enterprises to the portion of its operations in which regulators set rates at levels intended to recover the estimated costs of providing service, plus a return on net investments in assets, or rate base. Regulators may also impose certain penalties or grant certain incentives. Due to timing and other differences in the collection of electric utility revenue, these principles require an incurred cost that would otherwise be charged to expense by a
non-regulated entity to be capitalized as a regulatory asset if it is probable that the cost is recoverable through future rates; and conversely the principles require recording 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 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. SCE assesses, at the end of each reporting period, whether regulatory assets are probable of future recovery. See Note 11 for composition of regulatory assets and liabilities.
The preparation of financial statements in conformity with United States generally accepted accounting principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reported period. Actual results could differ from those estimates.
Effective January 1, 2018, Edison International and SCE adopted several accounting standards retrospectively. Prior Certain prior year financial statementsamounts have been reclassified and updatedconformed to reflect the retrospective application of these standards as applicable. For further information, see "New Accounting Guidance" below.current year's presentation.
Sale of SoCore Energy
On February 28, 2018, Edison International agreed to sell SoCore Energy LLC ("SoCore Energy"), a subsidiary of Edison Energy Group, to a third party, subject to the completion of closing conditions, which were satisfied on April 16, 2018. As a result, Edison International recognized a pre-tax loss of $62 million ($50 million after-tax) for the year ended December 31, 2018 and the assets and liabilities of SoCore Energy were not reflected in the consolidated Edison International balance sheet as of December 31, 2018.
Cash, Cash Equivalents and Restricted Cash
Cash equivalents include investments in money market funds. Generally, the carrying value of cash equivalents equals the fair value, as these investments have original maturities of three months or less. The cash equivalents were as follows:
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Money market funds | $ | 31 |
| | $ | 116 |
| | $ | — |
| | $ | 1 |
|
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Money market funds | $ | 116 |
| | $ | 1,024 |
| | $ | 1 |
| | $ | 483 |
|
Cash is temporarily invested until required for check clearing. Checks issued, but not yet paid by the financial institution, are reclassified from cash to accounts payable at the end of each reporting period as follows:
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Book balances reclassified to accounts payable | $ | 75 |
| | $ | 65 |
| | $ | 74 |
| | $ | 65 |
|
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Book balances reclassified to accounts payable | $ | 65 |
| | $ | 64 |
| | $ | 65 |
| | $ | 63 |
|
Edison International's restricted cash at December 31, 2018 and 2017 were $8 million and $41 million, respectively. Restricted cash at December 31, 2017 primarily relates to funds held by SoCore Energy and its consolidated affiliates pursuant to project financing or purchase agreements, most of which lapsed before June 30, 2018. As a result of the sale of SoCore Energy, the assets and liabilities of SoCore Energy were not included in the consolidated Edison International balance sheet at December 31, 2018, as discussed above.
The following table sets forth the cash, cash equivalents and restricted cash included in the consolidated statements of cash flows:
| | | (in millions) | | December 31, 2018 | | December 31, 2017 | | December 31, 2019 | | December 31, 2018 |
| Edison International: | | | | | | | | |
| Cash and cash equivalents | | $ | 144 |
| | $ | 1,091 |
| | $ | 68 |
| | $ | 144 |
|
Short-term restricted cash 1 | | 8 |
| | 40 |
| | 2 |
| | 8 |
|
Long-term restricted cash 2 | | — |
| | 1 |
| |
| Total cash, cash equivalents, and restricted cash | | $ | 152 |
| | $ | 1,132 |
| | $ | 70 |
| | $ | 152 |
|
| SCE: | | | | | | | | |
| Cash and cash equivalents | | $ | 21 |
| | $ | 515 |
| | $ | 24 |
| | $ | 21 |
|
Short-term restricted cash1 | | 1 |
| | — |
| | — |
| | 1 |
|
| Total cash, cash equivalents, and restricted cash | | $ | 22 |
| | $ | 515 |
| | $ | 24 |
| | $ | 22 |
|
| |
1 | Reflected in "Other current assets" on Edison International's and SCE's consolidated balance sheets. |
| |
2
| Reflected in "Other long-term assets" on Edison International's consolidated balance sheets.
|
Allowance for Uncollectible Accounts
Allowances for uncollectible accounts are provided based upon a variety of factors, including historical amounts written-off, current economic conditions and assessment of customer collectability.
Inventory
SCE's inventory is primarily composed of materials, supplies and spare parts, and generally stated at weighted average cost.
Emission Allowances and Energy Credits
SCE is allocated greenhouse gas ("GHG") allowances annually which it is then required to sell into quarterly auctions. GHG proceeds from the auctions are recorded as a regulatory liability to be refunded to customers. SCE purchases GHG allowances in quarterly auctions or from counterparties to satisfy its GHG emission compliance obligations and recovers such costs of GHG allowances from customers. GHG allowances held for use are classified as "Other current assets" on the consolidated balance sheets and are stated, similar to an inventory method, at the lower of weighted-averageweighted average cost or market. SCE had GHG allowances held for use of $38$50 million and $127$38 million at December 31, 20182019 and 2017,2018, respectively. GHG emission obligations were $30$50 million and $129$30 million at December 31, 20182019 and 2017,2018, respectively, and are classified as "Other current liabilities" on the consolidated balance sheets.
SCE is allocated low carbon fuel standard ("LCFS") credits which it sells to market participants. Proceeds from the sales, net of program costs, are recorded in a balancing account to be refunded to eligible customers. SCE's net proceeds from the sale of these LCFS credits were $103$184 million and $24$103 million and are classified as "Regulatory liabilities" on the consolidated balance sheets at December 31, 20182019 and 2017,2018, respectively.
Property, Plant and Equipment
SCE plant additions, including replacements and betterments, are capitalized. Direct material and labor and indirect costs such as construction overhead, administrative and general costs, pension and benefits, and property taxes are capitalized as part of plant additions. The CPUC authorizes a capitalization rate for each of the indirect costs which are allocated to each project based on either labor or total costs.
Estimated useful lives (authorizedauthorized by the CPUC in the 2015 GRC)2018 General Rate Case ("GRC") and weighted-averageweighted average useful lives of SCE's property, plant and equipment, are as follows:
|
| | |
| | Estimated Useful Lives | Weighted-Average
Weighted Average
Useful Lives |
| Generation plant | 10 years to 5456 years | 3736 years |
| Distribution plant | 20 years to 6065 years | 4348 years |
| Transmission plant | 4045 years to 65 years | 5254 years |
| General plant and other | 5 years to 60 years | 2225 years |
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. SCE's depreciation expense was $1.65$1.7 billion, $1.61$1.7 billion and $1.52$1.6 billion for 2019, 2018 2017 and 2016,2017, respectively. Depreciation expense stated as a percent of average original cost of depreciable utility plant was, on a composite basis, 3.7%3.6%, 3.8%3.7% and 3.8% for 2019, 2018 2017 and 2016,2017, respectively. The original costs of retired property isare charged to accumulated depreciation. See Note 2 for further information.
Nuclear fuel for the Palo Verde Nuclear Generating Station ("Palo Verde") is recorded as utility plant (nuclear fuel in the fabrication and installation phase is recorded as construction in progress) in accordance with CPUC ratemaking procedures. Palo Verde nuclear fuel is amortized using the units of production method.
Allowance for funds used during construction ("AFUDC") represents the estimated cost of debt and equity funds that finance utility-plant construction and is capitalized during certain plant construction. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset. AFUDC equity represents a method to compensate SCE for the estimated cost of equity used to finance utility plant additions and is recorded as part of construction in progress. AFUDC equity was $101 million, $104 million and $87 million in 2019, 2018 and $74 million in 2018, 2017, and 2016, respectively, and is reflected in "Other income and expenses.income." AFUDC debt was $63 million, $44 million and $28 million in 2019, 2018 and $23 million in 2018, 2017, and 2016, respectively and is reflected as a reduction of "Interest expense."
Major Maintenance
Major maintenance costs for SCE's power plant facilities and equipment are expensed as incurred.
Impairment of Long-Lived Assets
Impairments of long-lived assets are evaluated based on a review of estimated future cash flows expected to be generated whenever events or changes in circumstances indicate that the carrying amount of such investments or assets may not be recoverable. If the carrying amount of a long-lived asset exceeds expected future cash flows, undiscounted and without interest charges, an impairment loss is recognized in the amount of the excess of fair value over the carrying amount. Fair value is determined via market, cost and income basedincome-based valuation techniques, as appropriate.
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.
Initial and annual contributions to the wildfire insurance fund established pursuant to California Assembly Bill 1054 (the "Wildfire Insurance Fund" and "AB 1054")
Edison International and SCE accounted for the contributions to the Wildfire Insurance Fund similarly to prepaid insurance. No period of coverage was provided in AB 1054, therefore expense is being allocated to periods ratably based on an estimated period of coverage. At December 31, 2019, Edison International and SCE have a $2.8 billion long-term asset and a $323 million current asset reflected as "Wildfire Insurance Fund contributions" in the consolidated balance sheets for the initial $2.4 billion contribution made during the third quarter of 2019 and the present value of annual contributions SCE committed to make to the Wildfire Insurance Fund, reduced by amortization. At December 31, 2019, a long-term liability of $785 million has been reflected in "Other deferred credits and other long-term liabilities" for the present value of unpaid contribution amounts. Contributions were discounted to the present value at the date SCE committed to participate in the Wildfire Insurance Fund using US treasury interest rates.
A period of 10 years is being used to amortize the asset. All expenses related to the contributions are being reflected in "Operation and maintenance" in the consolidated statements of income. Changes in the estimated period of coverage provided by the Wildfire Insurance Fund could lead to material changes in future expense recognition. In estimating the period of coverage Edison International and SCE used Monte Carlo simulations based on five years (2014 – 2018) of historical data from wildfires caused by electrical utility equipment to estimate expected losses. The details of the operation of the Wildfire Insurance Fund and estimates related to claims by SCE, Pacific Gas & Electric Company ("PG&E") and San Diego Gas & Electric ("SDG&E") against the fund have been applied to the expected loss simulations to estimate the period of coverage of the fund. The most sensitive inputs to the estimated period of coverage are the expected frequency of wildfire events caused by investor-owned utility electrical equipment and the estimated costs associated with those forecasted events. Edison International and SCE evaluate all inputs annually, or upon claims being made from the fund for catastrophic wildfires, and the expected life of the insurance fund will be adjusted as required.
Edison International and SCE will assess the Wildfire Insurance Fund contribution assets for impairment in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire, based on the ability of SCE to benefit from the coverage provided by the Wildfire Insurance Fund in an amount equal to the recorded assets.
Goodwill
Edison International assesses goodwill through an annual goodwill impairment test, at the reporting unit level as of October 1st1 of each year. Edison International updates its goodwill impairment test between annual tests if events occur or circumstances change such that it is more likely than not that the fair value of a reporting unit is below its carrying value. In assessing goodwill for impairment, Edison International may perform a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment, Edison International assesses, among other things, macroeconomic conditions, industry and market considerations, overall financial performance, cost factors and entity-specific events. If, after assessing these qualitative factors, Edison International determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then Edison International performs the two-step goodwill impairment test ("quantitative assessment").
In October 2019 and 2018, Edison International qualitatively determined that it was more likely than not that the carrying value of the Edison Energy reporting unit exceeded the fair value, therefore, Edison International performed a quantitative assessment.assessments. The fair value of the Edison Energy reporting unit was estimated using the income approach, which utilizes a discounted cash flow analysis based on the earnings expected to be generated in the future. This determination requires significant assumptions and estimates in forecasting future cash flows and establishing a market discount rate and a terminal value. The most critical assumption affecting the estimate of the Edison Energy reporting unit's fair value was a reduction in forecasted growth of the businesses acquired at the end of 2015.growth. During the fourth quarter of 2019 and 2018, Edison International recorded an impairment of its Edison Energy reporting unit goodwill totaling $25 million ($18 million after-tax) and $19 million ($13 million after-tax)., respectively. At December 31, 2019 and 2018, Edison International has $34 million and $59 million of goodwill, all of which is related to its Edison Energy reporting unit. Goodwill constitutes the majority of Edison International's $83$57 million investment in Edison Energy. During the second quarter of 2017, Edison International recorded an impairment of SoCore Energy's goodwill totaling $16.5$17 million ($10 million after-tax). At December 31, 2017, goodwill was comprised of $78 million at the Edison Energy reporting unit and $5 million at the SoCore Energy reporting unit. SoCore Energy was sold in April 2018, as discussed above.
Nuclear Decommissioning and Asset Retirement Obligations
The fair value of a liability for an asset retirement obligation ("ARO") is recorded in the period in which it is incurred, including a liability for the fair value of a conditional ARO, if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. When an ARO liability is initially recorded, SCE capitalizes the cost by increasing the carrying amount of the related long-lived asset. For each subsequent period, the liability is increased for accretion expense and the capitalized cost is depreciated over the useful life of the related asset.
AROs related to decommissioning of SCE's nuclear power facilities are based on site-specific studies conducted as part of each Nuclear Decommissioning Cost Triennial Proceeding ("NDCTP") conducted before the CPUC. Revisions of an ARO are established for updated site-specific decommissioning cost estimates.
SCE adjusts its nuclear decommissioning obligation into a nuclear-related ARO regulatory asset and also records an ARO regulatory liability as a result of timing differences between the recognition of costs and the recovery of costs through the ratemaking process. For further information, see Note 11.
SCE has not recorded an ARO for assets that are expected to operate indefinitely or where SCE cannot estimate a settlement date (or range of potential settlement dates). As such, ARO liabilities are not recorded for certain retirement activities, including certain hydroelectric facilities.
The following table summarizes the changes in SCE's ARO liability:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Beginning balance | $ | 3,031 |
| | $ | 2,892 |
|
Accretion1 | 166 |
| | 169 |
|
| Revisions | 4 |
| | 110 |
|
| Liabilities settled | (172 | ) | | (140 | ) |
| Ending balance | $ | 3,029 |
| | $ | 3,031 |
|
|
| | | | | | | |
| | December 31, |
| (in millions) | 2018 | | 2017 |
| Beginning balance | $ | 2,892 |
| | $ | 2,586 |
|
Accretion1 | 169 |
| | 166 |
|
| Revisions | 110 |
| | 376 |
|
| Liabilities settled | (140 | ) | | (236 | ) |
| Ending balance | $ | 3,031 |
| | $ | 2,892 |
|
| |
1 | An ARO represents the present value of a future obligation. Accretion is an increase in the liability to account for the time value of money resulting from discounting. |
AROs related to decommissioning of SCE's nuclear power facilities are based on site-specific studies conducted as part of each Nuclear Decommissioning Cost Triennial Proceeding ("NDCTP") conducted before the CPUC. Revisions of an ARO are established for updated site-specific decommissioning cost estimates.
The ARO for decommissioning SCE's San Onofre Nuclear Generating Station ("San Onofre") and Palo Verde nuclear power facilities is $2.8 billion as of December 31, 2018.2019. The liability to decommission SCE's nuclear power facilities is based on a 2017 decommissioning study that was filed as part of the 2018 NDTCPNDCTP 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.
The initial activity phaseSCE records an ARO regulatory liability as a result of radiologicaltiming differences between the recognition of costs and the recovery of costs through the ratemaking process. For further information, see Note 11.
Decommissioning of San Onofre Unit 1 began in 1999 and the transfer of spent nuclear fuel from Unit 1 to dry cask storage in the Independent Spent Fuel Storage Installation ("ISFSI") was completed in 2005. Major decommissioning work for Unit 1 has been completed except for reactor vessel disposal and certain underground work. Some spent nuclear fuel from Units 2 and 3 also was transferred to the ISFSI between 2007 and 2012. Radiological decommissioning of San Onofre Units 2 and 3 began in June 2013 with SCE filing a certification of permanent cessation of power operations at San Onofre with the Nuclear Regulatory Commission and some spent nuclear fuel was transferred to dry cask storage in the Independent Spent Fuel Storage Installation ("ISFSI") between 2007 and 2012.Commission. 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. In May 2019, after an extensive review, the NRC determined that fuel loading can be safely resumed at San Onofre. SCE cannot predict whencommenced fuel transfer operations at San Onofre will recommence.in July 2019. In October 2019, the California Coastal Commission approved SCE's application for the Coastal Development Permit, the principle discretionary permit required to start major decommissioning activities at San Onofre. SCE plans on commencing major decommissioning activities in 2020 in accordance with the terms of the permit, subject to any court rulings in a proceeding brought in December 2019 to challenge the California Coastal Commission's issuance of the permit.
Decommissioning costs, which are recovered through customer rates over the term of each nuclear facility's operating license, are recorded as a component of depreciation expense, with a corresponding credit to the ARO regulatory liability. Due to regulatory recovery of SCE's nuclear decommissioning expense, prudently incurred costs for nuclear decommissioning activities do not affect SCE's earnings. Amortization of the ARO asset (included within the unamortized
nuclear investment) and accretion of the ARO liability are deferred as decreases to the ARO regulatory liability account, resulting in no impact on earnings.
SCE has collected in rates amounts for the future decommissioning of its nuclear assets and has placed those amounts in independent trusts. Amounts collected in rates in excess of the ARO liability are classified as regulatory liabilities.
Changes in the estimated costs, timing of decommissioning or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission. SCE currently estimates that it will spend approximately $7.2$7.1 billion through 2079 to decommission its nuclear facilities. This estimate is based on SCE's decommissioning cost methodology used for ratemaking purposes, escalated at rates ranging from 2.2% to 7.5% (depending on the cost element) annually. These costs are expected to be funded from independent decommissioning trusts. SCE estimates annual after-tax earnings on the decommissioning funds of 2.4% to 3.8%. Future decommissioning costs related to SCE's nuclear assets are expected to be funded from independent decommissioning trusts. dependent on asset class. If the assumed return on trust assets is not earned or costs escalate at higher rates, SCE expects that additional funds needed for decommissioning will be recoverable through future rates, subject to a reasonableness review. See Note 10 for further information.
Due to regulatory recovery of SCE's nuclear decommissioning expense, prudently incurred costs for nuclear decommissioning activities do not affect SCE's earnings. SCE's nuclear decommissioning costs are subject to CPUC review through the triennial regulatory proceeding. SCE's nuclear decommissioning trust investments primarily consist of fixed income investments that are classified as available-for-sale and equity investments. Due to regulatory mechanisms, investment earnings and realized gains and losses have no impact on earnings. Unrealized gains and losses on decommissioning trust funds, including other-than-temporary impairment, increase or decrease the trust assets and the related regulatory asset or liability and have no impact on electric utility revenue or decommissioning expense. SCE reviews each fixed income security for other-than-temporary impairment on the last day of each month. If the fair value on the last day of two consecutive months is less than the cost for that security, SCE recognizes a loss for the other-than-temporary impairment.
If the fair value is greater or less than the carrying value for that security at the time of sale, SCE recognizes a related realized gain or loss, respectively.
Deferred Financing Costs
Debt premium, discount and issuance expenses incurred in connection with obtaining financing are deferred and amortized on a straight-line basis. Under CPUC ratemaking procedures, SCE's debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt. SCE had unamortized losses on reacquired debt of $153$142 million and $168$153 million at December 31, 20182019 and 2017,2018, respectively, reflected as long-term "Regulatory assets" in the consolidated balance sheets. Edison International and SCE had unamortized debt issuance costs related to issuances under the credit facilities of $10 million and $8 million at December 31, 2018, respectively, and $15 million and $7 million at December 31, 2017, respectively, reflected in "Other long-term assets" on the consolidated balance sheets. In addition, Edison International and SCE had debt issuance costs related to issuances of long-term debt of $121 million and $106 million at December 31, 2019, respectively, and $102 million and $93 million at December 31, 2018, respectively, and $88 million and $77 million at December 31, 2017, respectively, reflected as a reduction of "Long-term debt" on the consolidated balance sheets.
Amortization of deferred financing costs charged to interest expense is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Amortization of deferred financing costs charged to interest expense | $ | 30 |
| | $ | 30 |
| | $ | 30 |
| | $ | 26 |
| | $ | 26 |
| | $ | 27 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Amortization of deferred financing costs charged to interest expense | $ | 30 |
| | $ | 30 |
| | $ | 31 |
| | $ | 26 |
| | $ | 27 |
| | $ | 27 |
|
Revenue Recognition
Revenue is recognized by Edison International and SCE when a performance obligation to transfer control of the promised goods is satisfied or when services are rendered to customers. This typically occurs when electricity is delivered to customers, which includes amounts for services rendered but unbilled at the end of a reporting period.
SCE's GRC proceeding, for the three-year period 2018 – 2020, is pending. Revenue from Contracts with Customers
Provision of Electricity
SCE has requested aprincipally generates revenue requirement of $5.534 billion forthrough supplying and delivering electricity to 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 recognized revenue in 2018 and is recognizing revenue in 2019customers. Rates charged to customers are based on the 2017 authorized revenue requirement, adjusted for the July 2017 cost of capital decision and Tax Reform. The CPUC hastariff rates, approved the establishment of a GRC memorandum account and the 2018 and 2019 revenue requirements adopted by the CPUC and FERC. Starting with SCE's 2021 GRC, revenue will be effectiveauthorized through quadrennial GRC proceedings, which are intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its CPUC-jurisdictional rate base. The CPUC sets an annual revenue requirement for the base year and the remaining three years are set by a methodology established in the GRC proceeding. Revenue was previously authorized by the CPUC in triennial GRC proceedings. As described above, SCE also earns revenue, with no return, to recover costs for power procurement and other activities.
Revenue is authorized by the FERC through a formula rate which is intended to provide SCE a reasonable opportunity to recover transmission capital and operating costs that are prudently incurred, including a return on its FERC-jurisdictional rate base. Under the operation of the formula rate, transmission revenue is updated to actual cost of service annually.
For SCE's electricity sales for both residential and non-residential customers, SCE satisfies the performance obligation of delivering electricity over time as of January 1, 2018the customers simultaneously receive and January 1, 2019, respectively. The amounts billedconsume the delivered electricity.
Energy sales are typically on a month-to-month implied contract for transmission, distribution and generation services. Revenue is recognized over time as the energy is supplied and delivered to customers forand the year ended December 31, 2018 were basedrespective revenue is billed and paid on the 2017 authorized revenue requirement and a regulatory liability has been established to record the associated adjustments. See Note 11 for further details.
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.
In October 2017, SCE filed its new formula rate with the FERC. In December 2017, the FERC issued an order setting the effective date of SCE's new FERC formula rate as of January 1, 2018, subject to settlement procedures and refund. Pending resolution of the FERC formula rate proceeding, SCE is recognizing revenue based on the FERC formula rate adjusted for the impact of Tax Reform and other adjustments.monthly basis.
CPUC and FERC rates decouple authorized revenue from the volume of electricity sales and the price of energy procured so that SCE receives revenue equal to amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity sold to customers and specific customer classes does not have a direct impact on SCE's financial results. See Note 7 for further information on SCE's revenue.
Sales and Use Taxes
SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE's ability to collect from the customer, are accounted for on a gross basis. SCE's franchise fees billed to customers were $122 million, $133 million and $133 million for the years ended December 31, 2019, 2018 and 2017, respectively. When SCE acts as an agent for sales and use tax, the taxes are accounted for on a net basis. Amounts billed to and collected from customers for these taxes are remitted to the taxing authorities and are not recognized as electric utility revenue.
SCE's Alternative Revenue Programs
The CPUC and FERC have authorized additional, alternative revenue programs which adjust billings for the effects of broad external factors or compensate SCE for demand-side management initiatives and provide for incentive awards if SCE achieves certain objectives. These alternative revenue programs allow SCE to recover costs that SCE has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, revenue is recognized for these alternative revenue programs at the time the costs are incurred and, for incentive-based programs, at the time the awards are approved by the CPUC. SCE begins recognizing revenues for these programs when a program has been established by an order from either the CPUC or FERC that allows for automatic adjustment of future rates, the amount of revenue for the period is objectively determinable and probable of recovery and the revenue will be collected within 24 months following the end of the annual period.
Regulatory Proceedings
2018 General Rate Case
In the absence of a 2018 GRC final decision, SCE recognized revenue in 2018 and the first quarter of 2019 based on the 2017 authorized revenue requirement, adjusted for items SCE determined to be probable of occurring, primarily the July 2017 cost of capital decision and the Tax Cuts and Jobs Act ("Tax Reform"). Adjustments were also made to 2017 authorized revenue to reflect changes in authorized tax benefits for certain balancing accounts. See Note 11 for further information.
In May 2019, the CPUC approved a final decision in SCE's 2018 GRC. The final decision authorized a revenue requirement of $5.1 billion for 2018 and identified changes to certain balancing accounts, including the expansion of the TAMA to include the impacts of all differences between forecast and recorded tax expense. The final decision also disallowed certain historical spending, largely related to specific pole replacements the CPUC determined were performed prematurely.
The final decision allows a post-test year rate making mechanism that escalates capital additions by 2.49% for both 2019 and 2020. It also allows operation and maintenance expenses to be escalated for 2019 and 2020 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology set forth in the final decision results in a revenue requirement of $5.5 billion in 2019 and $5.9 billion in 2020.
The revenue requirements in the 2018 GRC final decision are retroactive to January 1, 2018. SCE recorded the prior period impact of the 2018 GRC final decision in 2019 including:
An increase to earnings of $131 million from the application of the decision to revenue, depreciation expense and income tax expense. Depreciation expense decreased as a result of lower authorized depreciation rates. An increase in the authorized revenue requirement for income tax expense offsets income tax expense recognized during 2018 and the first quarter of 2019. The reduction of revenue of $265 million reflected $289 million of lower authorized revenue related to 2018 and $24 million of higher authorized revenue in 2019. The reduction in revenue contributed to a refund to customers of $554 million, which SCE recorded as a regulatory liability. SCE expects to refund these amounts to customers through December 2020.
An impairment of utility property, plant and equipment of $170 million ($123 million after-tax) related to disallowed historical capital expenditures, primarily the write-off of specific pole replacements the CPUC determined were performed prematurely.
2018 and 2019 FERC Formula Rate
In December 2019, the FERC approved a settlement on SCE's formula rates for the 2018 Formula Rate case that established SCE's FERC transmission revenue requirement for January 1, 2018 through November 11, 2019 (the "FERC 2018 Settlement Period"). Prior to the settlement, SCE had been recognizing revenue during the FERC 2018 Settlement Period based on its expectations of the probable outcome of the 2018 Formula Rate case. Regulatory assets and liabilities were adjusted based on the settlement of the 2018 Formula Rate case, which resulted in an increase in net income of $29 million related to 2018, being recorded in 2019. The 2019 Formula Rate remains subject to hearing and settlement procedures and amounts billed to customers under the 2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved. Pending resolution of the 2019 Formula Rate case, SCE is recognizing revenue based on the return on equity established in the 2020 Cost of Capital decision of the CPUC.
Power Purchase Agreements
SCE enters into power purchase agreements ("PPAs") in the normal course of business. A power purchase agreement may be considered a variable interest in a variable interest entity ("VIE"). If SCE is the primary beneficiary in the VIE, SCE should consolidate the VIE. None of SCE's PPAs resulted in consolidation of a VIE at December 31, 20182019 and 2017.2018. See Note 3 for further discussion of PPAs that are considered variable interests.
A PPA may also contain a lease for accounting purposes. See "Leases" below and Note 12 and Note 13 for further discussion of SCE's PPAs, including agreements that are classified as operating and capitalfinance leases for accounting purposes.
A PPA that does not contain a lease may be classified as a derivative which is recorded at fair value on the consolidated balance sheets. These PPAs may be eligible for an election to designate as a normal purchase and sale, which is accounted for on an accrual basis as an executory contract. See Note 6 for further information on derivative instruments.
PPAs that do not meet the above classifications are accounted for on an accrual basis.
Derivative Instruments
SCE records derivative instruments on its consolidated balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as normal purchases or sales. The normal purchases and sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. During the third quarter of 2017, SCE designated certain derivative contracts as normal purchase and normal sale contracts, which resulted in a reclassification of $914 million from derivative liabilities to other liabilities. These liabilities will be amortized over the remaining contract terms.
Realized gains and losses from SCE's derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no impact on purchased-powerpurchased power expense or earnings. SCE does not use hedge accounting for derivative transactions due to regulatory accounting treatment.
Where SCE's derivative instruments are subject to a master netting agreement and certain criteria are met, SCE presents its derivative assets and liabilities on a net basis on its consolidated balance sheets. In addition, derivative positions are offset against margin and cash collateral deposits. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. See Note 6 for further information on derivative instruments.
Leases
A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified assets for a period of time in exchange for consideration. An entity controls the use when it has a right to obtain substantially all of the benefits from the use of the identified asset and has the right to direct the use of the asset. SCE determines if an arrangement is a lease at contract inception. For all classes of underlying assets, SCE includes both the lease and non-lease components as a single component and accounts for it as a lease. Lease liabilities are recognized based on the present value of the lease payments over the lease term at the commencement date. SCE calculates and uses the rate implicit in the lease if the information is readily available or if not available, SCE uses its incremental borrowing rate in determining the present value of lease payments. Incremental borrowing rates are comprised of underlying risk-free rates and secured credit spreads relative to first mortgage bonds with like tenors of lease term durations. Lease right-of-use ("ROU") assets are based on the liability, subject to adjustments, such as lease incentives. The ROU assets also include any lease payments made at or before the commencement date. SCE excludes variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. SCE's lease terms include options to extend or terminate the lease when it is reasonably certain that such options will be exercised. Operating leases are included in "Operating lease right-of-use assets," "Current portion of operating lease liabilities" and "Operating lease liabilities" on the consolidated balance sheets. Finance leases are included in "Utility property, plant and equipment," "Other current liabilities" and "Other deferred credits and other long-term liabilities" on the consolidated balance sheets.
SCE enters into PPAspower purchase agreements that may contain leases,leases. This occurs when a power purchase agreement designates a specific power plant, SCE obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. Leases that commenced before January 1, 2019 were not reassessed as discussed under "Power Purchase Agreements" above. A PPA containsSCE elected the package of practical expedients (see "Accounting Guidance Adopted" below for more information). Prior to January 1, 2019, a power purchase agreement contained a lease when SCE purchasespurchased substantially all of the output from a specific plant and doesdid not otherwise meet a fixed price per unit of output exception. SCE also enters into a number of agreements to lease property and equipment in the normal course of business, primarily related to vehicles, office space and other equipment. Minimum lease payments underSee Note 13 for further discussion of SCE's contracts that are classified as operating and finance leases.
Edison International Parent and Other's leases primarily relate to Edison Energy Group. The leases for propertyEdison International Parent and equipmentOther are reflected in "Operation and maintenance" on the consolidated statements of income.immaterial to Edison International.
Stock-Based Compensation
Stock options, performance shares, deferred stock units and restricted stock units have been granted under Edison International's long-term incentive compensation programs. Generally,For equity awards that are settled in common stock, Edison International does not issueeither issues new common stock, for settlement of equity awards, which are recorded as part of retained earnings. Rather,or uses a third party is used to purchase shares from the market and deliver such shares for the settlement of option exercises, performance shares, deferred stock units and restricted stock units.the awards. The performance shares awardedgranted during 2017 to 2018 that are earned, arehave been or will be settled solely in cash. DeferredThe performance shares granted in 2019 that are earned, will be settled in common stock. Stock options, deferred stock units and restricted stock units are settled in common stock; however,stock. However, for awards that are otherwise settled entirely in common stock, Edison International will substitutesubstitutes cash awards to the extent necessary to paysatisfy applicable tax withholding obligations or any government levies.
Stock-based compensation expense is recognized, net of estimated forfeitures, on a straight-line basis over the requisite service period and is based on estimated fair values. For equity awards paid in common stock, fair value is determined at the grant date. However, with respect to the portion of the performance shares payable in common stock that are subject to market and financial performance conditions defined in the grants, the number of awards that areperformance shares expected to vest. Edison Internationalbe earned is subject to revision and SCE estimateupdated at each reporting period, with a related adjustment to compensation expense. Awards paid in cash are classified as share-based liability awards and fair value is remeasured at each reporting date with the number of awards that are expected to vest rather than account for forfeitures when they occur.related compensation cost adjusted. For awards granted to retirement-eligible participants, stock compensation expenses areexpense is recognized on a prorated basis over the initial year. For awards granted to participants who become eligible for retirement during the requisite service period, stock compensation expenses areexpense is recognized over the period between the date of grant and the date the participant first becomes eligible for retirement. Under new accounting guidance adopted in 2016, share-basedEdison International and SCE estimate the number of awards that are expected to vest rather than account for forfeitures when they occur. Share-based payments may create a permanent difference between the amount of compensation expense recognized for book and tax purposes. The tax impact of this permanent difference is recognized in earnings in the period it is created. Effective January 1, 2016, the excess tax benefits are classified as an operating activity along with other income tax cash flows on the statement of cash flows.See Note 9 for further information.
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
Prior to January 1, 2020, under SCE's interpretation of CPUC regulations and capital structure decisions, the common equity component of SCE's capital structure mustwas required to remain at or above 48% on a weighted average basis over the 37-month period that SCE's capital structure iswas in effect for ratemaking purposes. As allowed under the Revised San Onofre Settlement Agreement, whichpurposes and SCE 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 Note 12 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%. Effective January 1, 2020, the common equity component of SCE's authorized capital structure was increased from 48% to 52%. Under AB 1054, the impact of SCE's contributions to the Wildfire Insurance Fund are excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. For further information, see Note 12.
On February 28, 2019, SCE is submittingsubmitted 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 seekingrequested a limited waiver to exclude wildfire-related charges and wildfire-related debt issuances from its equity ratio calculations until a determination regarding cost recovery is made. The CPUC has ruled that while the application is pending resolution, SCE must notify the CPUC if an adverse financial event reduces SCE's spot equity ratio by more than one percent from the level most recently filed with the CPUC in the proceeding. The last spot equity ratio SCE filed with the CPUC in the proceeding was 45.2% as of December 31, 2018. Under the CPUC's rules, SCE will not be deemed to be in violation of the equity ratio requirement, and therefore may continue to issue debt and dividends, while the waiver application is pending resolution. For further information, see Note 12. At December 31, 2019, without excluding the $2.0 billion after-tax wildfire-related charges incurred in 2018 and 2019, SCE's 37-month average common equity component of total capitalization was 48.5% and the maximum additional dividend that SCE could pay to Edison International under this limitation was $179 million, resulting in a restriction on net assets of approximately $17.6 billion. If the wildfire-related charges were excluded at December 31, 2019, SCE's 37-month average common equity component of total capitalization would have been 49.6%.
As a California corporation, SCE's ability to pay dividends is also governed by 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, if any, in order to liquidate stock senior to the shares receiving the dividend. Additionally, a California corporation may not declare a dividend if it is, or as a result of the dividend would be, likely to be unable to meet its liabilities as they mature. Prior to declaring dividends, SCE's Board of Directors evaluates available information, including when applicable, information pertaining to the 2017/2018 Wildfire/Mudslide Events, to ensure that the California law requirements for the declarations are met. On February 28, 2019,27, 2020, SCE declared a dividend to Edison International of $200$269 million.
The timing and amount of future dividends are also dependent on a number of other factors including SCE's requirements to fund other obligations and capital expenditures, and its ability to access the capital markets, and generate operating cash flows and earnings. If SCE incurs significant costs related to catastrophic wildfires, including the 2017/2018 Wildfire/Mudslide Events, and is unable to recover such costs through insurance, the Wildfire Insurance Fund (for fires after July 12, 2019), or electric ratesfrom customers 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.
Earnings Per Share
Edison International computes earnings per common share ("EPS") using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's participating securities are stock-based compensation awards, payable in common shares, which earn dividend equivalents on an equal basis with common shares once the awards are vested. ForSee Note 9 and Note 14 for further information, see Note 9. information.
EPS attributable to Edison International common shareholders was computed as follows:
|
| | | | | | | | | | | |
| | Years ended December 31, |
| (in millions, except per share amounts) | 2019 | | 2018 | | 2017 |
| Basic earnings (loss) per share – continuing operations: | | | | | |
| Income (loss) from continuing operations attributable to common shareholders | $ | 1,284 |
| | $ | (457 | ) | | $ | 565 |
|
| Participating securities dividends | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Weighted average common shares outstanding | 340 |
| | 326 |
| | 326 |
|
| Basic earnings (loss) per share – continuing operations | 3.78 |
| | (1.40 | ) | | 1.73 |
|
| Diluted earnings (loss) per share – continuing operations: | | | | | |
| Income (loss) from continuing operations attributable to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Participating securities dividends | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Income impact of assumed conversions | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders and assumed conversions | 1,284 |
| | (457 | ) | | 565 |
|
| Weighted average common shares outstanding | 340 |
| | 326 |
| | 326 |
|
Incremental shares from assumed conversions1 | 1 |
| | — |
| | 2 |
|
| Adjusted weighted average shares – diluted | 341 |
| | 326 |
| | 328 |
|
| Diluted earnings (loss) per share – continuing operations | $ | 3.77 |
| | $ | (1.40 | ) | | $ | 1.72 |
|
|
| | | | | | | | | | | |
| | Years ended December 31, |
| (in millions, except per-share amounts) | 2018 | | 2017 | | 2016 |
| Basic (loss) earnings per share – continuing operations: | | | | | |
| (Loss) income from continuing operations attributable to common shareholders | $ | (457 | ) | | $ | 565 |
| | $ | 1,299 |
|
| Participating securities dividends | — |
| | — |
| | — |
|
| (Loss) income from continuing operations available to common shareholders | $ | (457 | ) | | $ | 565 |
| | $ | 1,299 |
|
| Weighted average common shares outstanding | 326 |
| | 326 |
| | 326 |
|
| Basic (loss) earnings per share – continuing operations | $ | (1.40 | ) | | $ | 1.73 |
| | $ | 3.99 |
|
| Diluted (loss) earnings per share – continuing operations: | | | | | |
| (Loss) income from continuing operations attributable to common shareholders | $ | (457 | ) | | $ | 565 |
| | $ | 1,299 |
|
| Participating securities dividends | — |
| | — |
| | — |
|
| (Loss) income from continuing operations available to common shareholders | $ | (457 | ) | | $ | 565 |
| | $ | 1,299 |
|
| Income impact of assumed conversions | — |
| | — |
| | 1 |
|
| (Loss) income from continuing operations available to common shareholders and assumed conversions | $ | (457 | ) | | $ | 565 |
| | $ | 1,300 |
|
| Weighted average common shares outstanding | 326 |
| | 326 |
| | 326 |
|
Incremental shares from assumed conversions1 | — |
| | 2 |
| | 4 |
|
| Adjusted weighted average shares – diluted | 326 |
| | 328 |
| | 330 |
|
| Diluted (loss) earnings per share – continuing operations | $ | (1.40 | ) | | $ | 1.72 |
| | $ | 3.94 |
|
| |
1 | Due to the loss reported for the year ended December 31, 2018, incremental shares were not included as the effect would be antidilutive. |
In addition to the participating securities discussed above, Edison International also may award stock options, which are payable in common shares and are included in the diluted earnings per share calculation. Stock option awards to purchase 8,852,706;4,511,802, 8,852,706 and 1,334,451 and 167,795 shares of common stock for the years ended December 31, 2019, 2018 2017 and 2016,2017, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the effect would have been antidilutive.
Income Taxes
Edison International and SCE estimate their income taxes for each jurisdiction in which they operate. This involves estimating current period tax expense along 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 in the consolidated balance sheets. In December 2017, the Tax Cuts and Jobs Act ("Tax Reform")Reform was signed into law. This comprehensive reform of tax law reduces the federal corporate income tax rate from 35% to 21% which resulted in the re-measurement of deferred taxes using the new tax rate. See Note 8 for further information.
Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Investment tax credits are deferred and amortized to income tax expense over the lives of the properties or the term of the power purchase agreement of the respective project.
Interest income, interest expense and penalties associated with income taxes are reflected in "Income tax expense" on the consolidated statements of income.
Edison International's eligible subsidiaries are included in Edison International's consolidated federal income tax and combined state tax returns. Edison International has tax-allocation and payment agreements with certain of its subsidiaries. Pursuant to an income tax-allocation agreement approved by the CPUC, SCE's tax liability is computed as if it filed its federal and state income tax returns on a separate return basis.
Noncontrolling Interest
Noncontrolling interest represents the portion of equity ownership in an entity that is not attributable to the equity holders of Edison International. Noncontrolling interests held by third parties that have rights to put their ownership back to a subsidiary of Edison International are classified outside shareholders' equity as redeemable noncontrolling interest. Noncontrolling interest is initially recorded at fair value and is subsequently adjusted for income allocated to the noncontrolling interest and any distributions paid to the noncontrolling interest.
Prior to the April 2018 sale of SoCore energy, certain solar projects for commercial customers are organized as limited liability companies and have noncontrolling equity investors (referred to as tax equity investors) which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements that vary over time. These entities were consolidated for financial reporting purposes but were not subject to income taxes as the taxable income (loss) and investment tax credits are allocated to the respective owners. The total consolidated assets and liabilities of these entities were $299 million and $41 million, respectively, at December 31, 2017. Income (loss) of these entities is allocated to the noncontrolling interest based on the hypothetical liquidation at book value accounting method. During the years ended December 31, 2018, 2017 and 2016, the allocation of tax benefits resulted in additional non-operating income allocated to Edison International of $14 million, $21 million and $9 million, respectively.
New Accounting Guidance
Accounting Guidance Adopted
In May 2014, the Financial Accounting Standards Board ("FASB") issued an accounting standards update on revenue recognition and further amended the standard in 2016 and 2017. Under the new standard, revenue is recognized when a good or service is transferred to the customer and the customer obtains control of the good or service. Some revenue arrangements, such as alternative revenue programs which include balancing account overcollections and undercollections, are excluded from the scope of the new standard and, therefore, will be accounted for and presented separately from revenue recognized from contracts with customers in the disclosures.On January 1, 2019, Edison International and SCE adopted this standard effective January 1, 2018, using the modified retrospective method for contracts that were not completed as of the adoption date. Edison International recognized a cumulative effect adjustment to increase the opening balance of retained earnings by approximately $5 million ($7 million pre-tax) on January 1, 2018. This adjustment is related to variable consideration recognized at Edison Energy which is not subject to potential significant reversal and has no further performance obligations. See Note 7 for further details.
In January 2016, the FASB issued an accounting standards updateupdates that amends the guidancerequire lessees to recognize a lease on the classificationbalance sheet as a ROU asset and measurement of financial instruments,related lease liability and further amendedclassify the guidance in 2018. Under the new guidance, equity investments (excluding those accounted for under the equity methodlease as either operating or those that result in consolidation) are required to be measured at fair value, with changes in fair value recognized in net income. The new guidance also amends certain disclosure requirements associated with the fair value of financial instruments and requires financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial assets.finance. Edison International and SCE adopted this guidance effective January 1, 2018.using the modified retrospective approach for leases that existed as of the adoption date and elected the optional transition method not to restate periods prior to the adoption date. Edison International and SCE recognized a cumulative effect adjustment to increase the opening balance of retained earnings and accumulated other comprehensive loss by $5 million ($8 million pre-tax) on January 1, 2018. See Edison International's and SCE's consolidated statements of changes in equity for further details.
In August and November 2016, the FASB issued two accounting standards updates to clarify the presentation and classification of certain cash receipts and payments in the statement of cash flows and to require restricted cash to be presented with cash and cash equivalents in the statement of cash flows. Edison International and SCE adopted these standards effective January 1, 2018, using the retrospective approach. The adoption of these standards did not have a material impact on Edison International's and SCE's consolidated statement of cash flows.
In March 2017, the FASB issued an accounting standards update on the presentation of the components of net periodic benefit cost for an entity's defined benefit pension and other postretirement plans. Edison International and SCE adopted this guidance retrospectively with respect to the income statement presentation requirement and prospectively for the capitalization requirement, effective January 1, 2018. The adoption of this standard did not have a material impact on Edison International's and SCE's consolidated financial statements, but did result in the separate presentation of service costs as an
operating expense and non-service costs within other income and expenses and the limitation of the capitalization of benefit costs to the service cost component. During the year ended December 31, 2017 and 2016, non-service benefits totaled $37 million and $30 million for Edison International, respectively, and $51 million and $35 million for SCE, respectively, which were reclassified from "Operation and maintenance" to "Other income and expenses." See Notes 9 and 15 for further details.
Accounting Guidance Not Yet Adopted
In February 2016, the FASB issued an accounting standards update related to lease accounting and further amended the standard in 2018. The new guidance is effective January 1, 2019. Under the new standard, a lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified assets and obtain all the economic benefits for a period of time in exchange for consideration. Lessees are required to recognize leases on the balance sheet as a right-of-use asset and a related lease liability, and classify the leases as either operating or finance. The liability will be equal to the present value of the lease payments. The asset will be based on the liability, subject to adjustments, such as lease incentives. SCE, as a regulated entity, is permitted to continue to recognize expense using the timing that conforms to the regulatory rate treatment. In accordance with the new guidance, Edison International and SCE will electalso elected the package of practical expedients not to reassess prior conclusions related to contracts containing leases, lease classification and initial direct costs, and the practical expedient not to assess whetherreassess existing land easements areeasements. Adoption of this standard increased ROU assets and lease liabilities on the consolidated balance sheets by $956 million and $951 million as of January 1, 2019 for Edison International and SCE, respectively. The standard did not materially impact the consolidated statements of income for Edison International or containSCE. See "Leases" above and Note 13 for further information.
In February 2018, the Financial Accounting Standards Board ("FASB") issued an accounting standards update to provide entities an election to reclassify stranded tax effects resulting from Tax Reform from accumulated other comprehensive income to retained earnings. Stranded tax effects originated in December 2017 when deferred taxes were re-measured at the lower federal corporate tax rate with the impact included in operating income, while the tax effects of items within accumulated other comprehensive income were not similarly adjusted. Edison International and SCE adopted this guidance on January 1, 2019 and reclassified stranded tax effects of $10 million and $5 million, respectively, from accumulated other comprehensive loss to retained earnings. See Note 15 for further information.
In August 2018, the FASB issued an accounting standards update to remove, modify, and add certain disclosure requirements related to fair value measurement. Edison International and SCE adopted this guidance effective January 1, 2019. The adoption of this guidance did not have a lease.material impact on Edison International's and SCE's disclosures. See Note 4 for further information.
Accounting Guidance Not Yet Adopted
In June 2016, the FASB issued an accounting standards update to require the use of the current expected credit loss model to measure impairment of financial instruments and the use of an allowance to record estimated credit losses on available-for-sale debt securities. The guidance, as later amended, allows entities to irrevocably elect the fair value option for any financial instrument previously measured on an amortized costs basis. Edison International and SCE do not believe the adoption of the standard will have a material impact on financial position or results of operations. Edison International and SCE will apply a prospective adoption approach to available-for-sale debt securities and a modified retrospective approach to all other financial assets. Edison International and SCE will not elect the fair value option. Edison International and SCE will adopt this guidance effective January 1, 2019, using the modified retrospective approach, for leases that existed as of the adoption date and will elect the optional transition method not to restate periods prior to the adoption date. The adoption of this standard is expected to increase right-of-use assets and lease liabilities in the consolidated balance sheets by approximately $1 billion as of January 1, 2019 for both Edison International and SCE. Edison International and SCE have implemented a new lease accounting system and are in the process of finalizing the impact this standard will have on the lease disclosures.
The FASB issued an accounting standards update in June 2016, and further amended the guidance in November 2018, related to the impairment of financial instruments, effective January 1, 2020. The new guidance provides an impairment model, known as the current expected credit loss model, which is based on expected credit losses rather than incurred losses. Edison International and SCE are currently evaluating the impact of this new guidance.
In January 2017, the FASB issued an accounting standards update to simplify the accounting for goodwill impairment by changing the procedural steps to apply the goodwill impairment test. After the adoption of this accounting standards update, goodwill impairment will be measured as the amount by which a reporting unit's carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Edison International will apply this guidance to goodwill impairment tests beginning in 2020.
In February 2018, the FASB issued an accounting standards update to provide entities an election to reclassify stranded tax effects resulting from Tax Reform from accumulated other comprehensive income to retained earnings. Stranded tax effects originated in December 2017 when deferred taxes were re-measured at the lower federal corporate tax rate with the impact included in operating income but the tax effects of items within accumulated other comprehensive income were not similarly adjusted. Edison International and SCE will adopt this guidance on January 1, 2019 and reclassify stranded tax effects of $10 million and $5 million, respectively, from accumulated other comprehensive income to retained earnings in the period of adoption.
In August 2018, the FASB issued an accounting standards update which aligns the requirement for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs incurred to develop or obtain internal-useinternal use software. The guidance also clarified presentation requirements for reporting implementation costs in the financial statements. Edison International and SCE do not believe the adoption of the standard will have a material impact on financial position or results of operations and will apply this guidance prospectively, effective January 1, 2020.
In August 2018, the FASB issued an accounting standards update to remove, modify, and add certain disclosure requirements related to employer-sponsored defined benefit pension or other postretirement plans. The guidance is effective January 1, 20202021 with early adoption permitted. Edison International and SCE are currently evaluating the impact of the guidance.guidance and do not expect the adoption of this standard will materially affect disclosures.
In August 2018, the FASB issued two accounting standards updates to remove, modify, and add certain disclosure requirements related to fair value measurement and employer-sponsored defined benefit pension or other postretirement plans. The guidance is effective January 1, 2020 and 2021, respectively, with early adoption permitted. Edison International and SCE are currently evaluating the impact of the guidance.
Note 2. Property, Plant and Equipment
SCE's property, plant and equipment included in the consolidated balance sheets is composed of the following:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Distribution | $ | 26,929 |
| | $ | 25,026 |
|
| Transmission | 14,720 |
| | 13,800 |
|
| Generation | 3,664 |
| | 3,598 |
|
| General plant and other | 4,583 |
| | 4,398 |
|
| Accumulated depreciation | (9,958 | ) | | (9,566 | ) |
| | 39,938 |
| | 37,256 |
|
| Construction work in progress | 4,131 |
| | 3,883 |
|
| Nuclear fuel, at amortized cost | 129 |
| | 130 |
|
| Total utility property, plant and equipment | $ | 44,198 |
| | $ | 41,269 |
|
|
| | | | | | | |
| | December 31, |
| (in millions) | 2018 | | 2017 |
| Distribution | $ | 25,026 |
| | $ | 23,633 |
|
| Transmission | 13,800 |
| | 13,127 |
|
| Generation | 3,598 |
| | 3,468 |
|
| General plant and other | 4,398 |
| | 4,534 |
|
| Accumulated depreciation | (9,566 | ) | | (9,355 | ) |
| | 37,256 |
| | 35,407 |
|
| Construction work in progress | 3,883 |
| | 3,175 |
|
| Nuclear fuel, at amortized cost | 130 |
| | 126 |
|
| Total utility property, plant and equipment | $ | 41,269 |
| | $ | 38,708 |
|
Capitalized Software Costs
SCE capitalizes costs incurred during the application development stage of internal use software projects to property, plant and equipment. SCE amortizes capitalized software costs ratably over the expected lives of the software, primarily ranging from 5 to 7 years and commencing upon operational use. Capitalized software costs, included in general plant and other above, were $1.0 billion and $1.1$1.0 billion at December 31, 20182019 and 2017,2018, respectively, and accumulated amortization was $0.4 billion and $0.5 billion and $0.6 billion, at December 31, 20182019 and 2017,2018, respectively. Amortization expense for capitalized software was $190 million, $198 million, and $233 million in 2019, 2018 and $249 million in 2018, 2017, and 2016, respectively. At December 31, 2018,2019, amortization expense is estimated to be $180$191 million, $145$163 million, $107$116 million, $59$76 million and $20$27 million for 20192020 through 2023,2024, respectively.
Jointly Owned Utility Projects
SCE owns undivided interests in severaltransmission and generating assets for which each participant provides its own financing. SCE's proportionate share of these assets is reflected in the consolidated balance sheets and included in the above table. SCE's proportionate share of expenses for each project is reflected in the consolidated statements of income.
The following is SCE's investment in each asset as of December 31, 2018:2019:
|
| | | | | | | | | | | | | | | | | |
| (in millions) | Plant in Service | Construction Work in Progress | Accumulated Depreciation | Nuclear Fuel (at amortized cost) | Net Book Value | Ownership Interest |
| Transmission systems: | | | | | | |
| Eldorado | $ | 257 |
| $ | 94 |
| $ | 35 |
| $ | — |
| $ | 316 |
| 80 | % |
| Pacific Intertie | 248 |
| 80 |
| 72 |
| — |
| 256 |
| 50 | % |
| Generating station: | | | | | | |
| Palo Verde (nuclear) | 2,065 |
| 61 |
| 1,586 |
| 129 |
| 669 |
| 16 | % |
| Total | $ | 2,570 |
| $ | 235 |
| $ | 1,693 |
| $ | 129 |
| $ | 1,241 |
| |
|
| | | | | | | | | | | | | | | | | |
| (in millions) | Plant in Service | Construction Work in Progress | Accumulated Depreciation | Nuclear Fuel (at amortized cost) | Net Book Value | Ownership Interest |
| Transmission systems: | | | | | | |
| Eldorado | $ | 245 |
| $ | 13 |
| $ | 29 |
| $ | — |
| $ | 229 |
| 59 | % |
| Pacific Intertie | 217 |
| 73 |
| 75 |
| — |
| 215 |
| 50 | % |
| Generating station: | | | | | | |
| Palo Verde (nuclear) | 2,024 |
| 63 |
| 1,567 |
| 130 |
| 650 |
| 16 | % |
| Total | $ | 2,486 |
| $ | 149 |
| $ | 1,671 |
| $ | 130 |
| $ | 1,094 |
| |
In addition, SCE has ownership interests in jointly owned power poles with other companies.
Note 3. Variable Interest Entities
A VIE is defined as a legal entity that meets one of two conditions: (1) the equity owners do not have sufficient equity at risk, or (2) the holders of the equity investment at risk, as a group, lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that most significantly impact the economic performance of such VIEs. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
Variable Interest in VIEs that are not Consolidated
Power Purchase Agreements
SCE has PPAs that are classified as variable interests in VIEs, including tolling agreements through which SCE provides the natural gas to fuel the plants and contracts with qualifying facilities ("QF") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. Since payments for capacity are the primary source of income, the most significant economic activity for these VIEs is the operation and maintenance of the power plants.
As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to involvement with VIEs result from amounts due under the PPAs. Under these contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 12. As a result, there is no significant potential exposure to loss to SCE from its variable interest in these VIEs. The aggregate contracted capacity dedicated to SCE from these VIE projects was 3,6024,497 megawatts ("MW") and 4,8983,602 MW at December 31, 20182019 and 2017,2018, respectively, and the amounts that SCE paid to these projects were $762$833 million and $767$762 million for the years ended December 31, 20182019 and 2017,2018, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.
Unconsolidated Trusts of SCE
SCE Trust II, Trust III, Trust IV, Trust V and Trust VI were formed in 2013, 2014, 2015, 2016 and 2017, respectively, for the exclusive purpose of issuing the 5.10%, 5.75%, 5.375%, 5.45% and 5.00% trust preference securities, respectively ("trust securities"). The trusts are VIEs. SCE has concluded that it is not the primary beneficiary of these VIEs as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trusts. SCE Trust II, Trust III, Trust IV, Trust V and Trust VI issued to the public trust securities in the face amounts of $400 million, $275 million, $325 million, $300 million and $475 million (cumulative, liquidation amounts of $25 per share), respectively, and $10,000 of common stock each to SCE. The trusts invested the proceeds of these trust securities in Series G, Series H, Series J, Series K and Series L Preference Stock issued by SCE in the principal amounts of $400 million, $275 million, $325 million, $300 million and $475 million (cumulative, $2,500 per share liquidation values), respectively, which have substantially the same payment terms as the respective trust securities.
The Series G, Series H, Series J, Series K and Series L Preference Stock and the corresponding trust securities do not have a maturity date. Upon any redemption of any shares of the Series G, Series H, Series J, Series K or Series L Preference Stock, a corresponding dollar amount of trust securities will be redeemed by the applicable trust (see Note 1314 for further information). The applicable trust will make distributions at the same rate and on the same dates on the applicable series of trust securities if and when the SCE board of directors declares and makes dividend payments on the related Preference Stock. The applicable trust will use any dividends it receives on the related Preference Stock to make its corresponding distributions on the applicable series of trust securities. If SCE does not make a dividend payment to any of these trusts, SCE would be prohibited from paying dividends on its common stock. SCE has fully and unconditionally guaranteed the payment of the trust securities and trust distributions, if and when SCE pays dividends on the related Preference Stock.
SCE formed Trust I, a VIE, in 2012 for the exclusive purpose of issuing 5.625% trust preference securities. SCE Trust I issued trust securities in the face amounts of $475 million to the public and $10,000 of common stock to SCE. SCE Trust I invested the proceeds of these trust securities in Series F Preference Stock issued by SCE in the principal amount of $475 million. In July 2017, all of the outstanding Series F Preference Stock was redeemed, and accordingly, SCE Trust I
redeemed $475 million of trust securities from the public and $10,000 of common stock from SCE. As a result in September 2017, SCE Trust I was terminated.
The Trust II, Trust III, Trust IV, Trust V and Trust VI balance sheets as of December 31, 20182019 and 2017,2018, consisted of investments of $400 million, $275 million, $325 million, $300 million and $475 million in the Series G, Series H, Series J, Series K and Series L Preference Stock, respectively, $400 million, $275 million, $325 million, $300 million and $475 million of trust securities, respectively, and $10,000 each of common stock.
The followingtable provides a summary of the trusts' income statements:
| |
| Years ended December 31, | Years ended December 31, |
| (in millions) | Trust I | | Trust II | | Trust III | | Trust IV | | Trust V | | Trust VI | Trust I | | Trust II | | Trust III | | Trust IV | | Trust V | | Trust VI |
| 2019 | | | | | | | | | | | | |
| Dividend income | | * |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 24 |
|
| Dividend distributions | | * |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 24 |
|
| 2018 | | | | | | | | | | | | | | | | | | | | | | |
| Dividend income | * |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 24 |
| * |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 24 |
|
| Dividend distributions | * |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 24 |
| * |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 24 |
|
| 2017 | | | | | | | | | | | | | | | | | | | | | | |
| Dividend income | $ | 14 |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 12 |
| $ | 14 |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 12 |
|
| Dividend distributions | 14 |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 12 |
| 14 |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 12 |
|
| 2016 | | | | | | | | | | | | |
| Dividend income | $ | 27 |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 13 |
| | * |
| |
| Dividend distributions | 27 |
| | 20 |
| | 16 |
| | 17 |
| | 13 |
| | * |
| |
* Not applicable
Note 4. Fair Value Measurements
Recurring Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or liability considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. As of December 31, 20182019 and 2017,2018, nonperformance risk was not material for Edison International and SCE.
Assets and liabilities are categorized into a three-level fair value hierarchy based on valuation inputs used to determine fair value.
Level 1 – The fair value of Edison International's and SCE's Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded equity securities, U.S. treasury securities, mutual funds and money market funds.
Level 2 – Edison International's and SCE's Level 2 assets and liabilities include fixed income securities, primarily consisting of U.S. government and agency bonds, municipal bonds and corporate bonds, and over-the-counter derivatives. The fair value of fixed income securities is determined using a market approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument.
The fair value of SCE's over-the-counter derivative contracts is determined using an income approach. SCE uses standard pricing models to determine the net present value of estimated future cash flows. Inputs to the pricing models include forward published or posted clearing prices from an exchange (Intercontinental Exchange) for similar instruments and discount rates. A primary price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity.
Level 3 – The fair value of SCE's Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes derivative contracts that trade infrequently such as congestion revenue rights ("CRRs"). Edison International Parent and Other does not have any Level 3 assets and liabilities.
Assumptions are made in order to value derivative contracts in which observable inputs are not available. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs, and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts. See Note 6 for a discussion of derivative instruments.
SCE
The following table sets forth assets and liabilities of SCE that were accounted for at fair value by level within the fair value hierarchy:
| | | | December 31, 2018 | December 31, 2019 |
| (in millions) | Level 1 | | Level 2 | | Level 3 | | Netting and Collateral1 | | Total | Level 1 | | Level 2 | | Level 3 | | Netting and Collateral1 | | Total |
| Assets at fair value | | | | | | | | | | | | | | | | | | |
| Derivative contracts | $ | — |
| | $ | 32 |
| | $ | 141 |
| | $ | — |
| | $ | 173 |
| $ | — |
| | $ | 19 |
| | $ | 83 |
| | $ | (15 | ) | | $ | 87 |
|
| Other | 9 |
| | 21 |
| | — |
| | — |
| | 30 |
| 4 |
| | 14 |
| | — |
| | — |
| | 18 |
|
| Nuclear decommissioning trusts: | | | | | | | | | | | | | | | | | | |
Stocks2 | 1,382 |
| | — |
| | — |
| | — |
| | 1,382 |
| 1,765 |
| | — |
| | — |
| | — |
| | 1,765 |
|
Fixed Income3 | 1,001 |
| | 1,665 |
| | — |
| | — |
| | 2,666 |
| 738 |
| | 2,024 |
| | — |
| | — |
| | 2,762 |
|
| Short-term investments, primarily cash equivalents | 120 |
| | 95 |
| | — |
| | — |
| | 215 |
| 98 |
| | 48 |
| | — |
| | — |
| | 146 |
|
Subtotal of nuclear decommissioning trusts4 | 2,503 |
| | 1,760 |
| | — |
| | — |
| | 4,263 |
| 2,601 |
| | 2,072 |
| | — |
| | — |
| | 4,673 |
|
| Total assets | 2,512 |
| | 1,813 |
| | 141 |
| | — |
| | 4,466 |
| 2,605 |
| | 2,105 |
| | 83 |
| | (15 | ) | | 4,778 |
|
| Liabilities at fair value | | | | | | | | | | | | | | | | | | |
| Derivative contracts | — |
| | 13 |
| | — |
| | (7 | ) | | 6 |
| — |
| | 11 |
| | 5 |
| | (15 | ) | | 1 |
|
| Total liabilities | — |
| | 13 |
| | — |
| | (7 | ) | | 6 |
| — |
| | 11 |
| | 5 |
| | (15 | ) | | 1 |
|
| Net assets | $ | 2,512 |
| | $ | 1,800 |
| | $ | 141 |
| | $ | 7 |
| | $ | 4,460 |
| $ | 2,605 |
| | $ | 2,094 |
| | $ | 78 |
| | $ | — |
| | $ | 4,777 |
|
| | | | December 31, 2017 | December 31, 2018 |
| (in millions) | Level 1 | | Level 2 | | Level 3 | | Netting and Collateral1 | | Total | Level 1 | | Level 2 | | Level 3 | | Netting and Collateral1 | | Total |
| Assets at fair value | | | | | | | | | |
| | | | | | | | | |
|
| Derivative contracts | $ | — |
| | $ | 9 |
| | $ | 102 |
| | $ | (1 | ) | | $ | 110 |
| $ | — |
| | $ | 32 |
| | $ | 141 |
| | $ | — |
| | $ | 173 |
|
| Money market funds and other | 495 |
| | — |
| | — |
| | — |
| | 495 |
| |
| Other | | 9 |
| | 21 |
| | — |
| | — |
| | 30 |
|
| Nuclear decommissioning trusts: | | | | | | | | | | | | | | | | | | |
Stocks2 | 1,596 |
| | — |
| | — |
| | — |
| | 1,596 |
| 1,382 |
| | — |
| | — |
| | — |
| | 1,382 |
|
Fixed Income3 | 1,065 |
| | 1,665 |
| | — |
| | — |
| | 2,730 |
| 1,001 |
| | 1,665 |
| | — |
| | — |
| | 2,666 |
|
| Short-term investments, primarily cash equivalents | 101 |
| | 72 |
| | — |
| | — |
| | 173 |
| 120 |
| | 95 |
| | — |
| | — |
| | 215 |
|
Subtotal of nuclear decommissioning trusts4 | 2,762 |
| | 1,737 |
| | — |
| | — |
| | 4,499 |
| 2,503 |
| | 1,760 |
| | — |
| | — |
| | 4,263 |
|
| Total assets | 3,257 |
| | 1,746 |
| | 102 |
| | (1 | ) | | 5,104 |
| 2,512 |
| | 1,813 |
| | 141 |
| | — |
| | 4,466 |
|
| Liabilities at fair value | | | | | | | | | | | | | | | | | | |
| Derivative contracts | — |
| | 2 |
| | 1 |
| | (2 | ) | | 1 |
| — |
| | 13 |
| | — |
| | (7 | ) | | 6 |
|
| Total liabilities | — |
| | 2 |
| | 1 |
| | (2 | ) | | 1 |
| — |
| | 13 |
| | — |
| | (7 | ) | | 6 |
|
| Net assets | $ | 3,257 |
| | $ | 1,744 |
| | $ | 101 |
| | $ | 1 |
| | $ | 5,103 |
| $ | 2,512 |
| | $ | 1,800 |
| | $ | 141 |
| | $ | 7 |
| | $ | 4,460 |
|
| |
1 | Represents the netting of assets and liabilities under master netting agreements and cash collateral. |
| |
2 | Approximately 71%72% and 69%71% of SCE's equity investments were located in the United States at December 31, 2019 and 2018, and 2017, respectively. |
| |
3 | Includes corporate bonds, which were diversified and included collateralized mortgage obligations and other asset backed securities of $67$46 million and $102$67 million at December 31, 20182019 and 2017,2018, respectively. |
| |
4 | Excludes net payables of $143$111 million and $59$143 million at December 31, 20182019 and 2017,2018, respectively, which consist of interest and dividend receivables as well as receivables and payables related to SCE's pending securities sales and purchases. |
Edison International Parent and Other
Edison International Parent and Other assets measured at fair value consisted of money market funds of $115$31 million and $541$115 million at December 31, 20182019 and 2017,2018, respectively, classified as Level 1.
SCE Fair Value of Level 3
The following table sets forth a summary of changes in SCE's fair value of Level 3 net derivative assets and liabilities:
|
| | | | | | | | |
| | | December 31, |
| (in millions) | | 2019 | | 2018 |
| Fair value of net assets at beginning of period | | $ | 141 |
| | $ | 101 |
|
| Total realized/unrealized (losses) gains: | | | | |
Included in regulatory assets and liabilities1 | | (63 | ) | | 40 |
|
Fair value of net assets at end of period2 | | 78 |
| | 141 |
|
| Change during the period in unrealized gains and losses related to assets and liabilities held at the end of the period | | $ | 62 |
| | $ | 138 |
|
|
| | | | | | | | |
| | | December 31, |
| (in millions) | | 2018 | | 2017 |
| Fair value of net assets (liabilities) at beginning of period | | $ | 101 |
| | $ | (1,089 | ) |
| Total realized/unrealized gains: | | | | |
Included in regulatory assets and liabilities1 | | 40 |
| | 133 |
|
Contract amendment2 | | — |
| | 143 |
|
Normal purchase and normal sale designation3 | | — |
| | 914 |
|
| Fair value of net assets at end of period | | $ | 141 |
| | $ | 101 |
|
| Change during the period in unrealized gains and losses related to assets and liabilities held at the end of the period | | $ | 138 |
| | $ | 100 |
|
| |
1 | Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities. |
2 Represents a tolling contract that was amended during the second quarter of 2017, which was no longer accounted for as a derivative as of December 31, 2017.
| |
32
| During the third quarterThere were no material transfers into or out of 2017, SCE designated certain derivative contracts as normal purchaseLevel 3 during 2019 and normal sale contracts, which resulted in a reclassification of $914 million from derivative liabilities to other liabilities. These liabilities are amortized over the remaining contract terms.2018. |
Edison International and SCE recognize the fair value for transfers in and transfers out of each level at the end of each reporting period. There were no material transfers between any levels during 2018 and 2017.
Valuation Techniques Used to Determine Fair Value
The process of determining fair value is the responsibility of SCE's risk management department, which reports to SCE's chief financial officer. This department obtains observable and unobservable inputs through broker quotes, exchanges and internal valuation techniques that use both standard and proprietary models to determine fair value. Each reporting period, the risk and finance departments collaborate to determine the appropriate fair value methodologies and classifications for each derivative. Inputs used and valuations are reviewed period-over-period and compared with market conditions to determine reasonableness.
The following table sets forth SCE's valuation techniques and significant unobservable inputs used to determine fair value for significant Level 3 assets and liabilities:
|
| | | | | | | | | | | |
| | Fair Value (in millions) | | Significant | Range | Weighted Average |
| | Assets | | Liabilities | Valuation Technique | Unobservable Input |
| Congestion revenue rights | | | | |
| December 31, 2019 | $ | 83 |
| | $ | 5 |
| Auction prices | CAISO CRR auction clearing prices | $(3.59) - $25.32 | $1.97 |
| December 31, 2018 | 141 |
| | — |
| Auction prices | CAISO CRR auction clearing prices | $(7.41) - $41.52 | $1.62 |
|
| | | | | | | | | | |
| | Fair Value (in millions) | | Significant | |
| | Assets | | Liabilities | Valuation Technique(s) | Unobservable Input | Range
|
| Congestion revenue rights | | | |
| December 31, 2018 | $ | 141 |
| | $ | — |
| Auction prices | CAISO CRR auction clearing prices | $(7.41) - $41.52 |
| December 31, 2017 | 102 |
| | — |
| Auction prices | CAISO CRR auction clearing prices | $(9.41) - $8.66 |
Level 3 Fair Value SensitivityUncertainty
For CRRs, increases or decreases in CAISO auction price would result in higher or lower fair value, respectively.
Nuclear Decommissioning Trusts
SCE's nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information. There are no securities classified as Level 3 in the nuclear decommissioning trusts.
SCE's investment policies and CPUC requirements place limitations on the types and investment grade ratings of the securities that may be held by the nuclear decommissioning trust funds. These policies restrict the trust funds from holding alternative investments and limit the trust funds' exposures to investments in highly illiquid markets. With respect to equity and fixed income securities, the trustee obtains prices from third-party pricing services which SCE is able to independently corroborate as described below. The trustee monitors prices supplied by pricing services, including reviewing prices against defined parameters' tolerances and performs research and resolves variances beyond the set parameters. SCE corroborates the fair values of securities by comparison to other market-based price sources obtained by SCE's investment managers. Differences outside established thresholds are followed-up with the trustee and resolved. For each reporting period, SCE reviews the trustee determined fair value hierarchy and overrides the trustee level classification when appropriate.
Nonrecurring Fair Value Measurements
Edison International assesses goodwill through an annual goodwill impairment test, at the reporting unit level as of October 1st of each year.level. The fair value of the Edison Energy reporting unit is classified as Level 3 and is estimated using the income approach. In OctoberDuring the fourth quarter of 2019 and 2018, Edison International evaluated the recoverability of goodwill and recorded an impairment chargecharges of Edison Energy's goodwill totaling $25 million ($18 million after-tax) and $19 million ($13 million after-tax) during the fourth quarter of 2018., respectively. See Note 1 for further details.
Fair Value of Debt Recorded at Carrying Value
The carrying value and fair value of Edison International's and SCE's long-term debt (including current portion of long-term debt) are as follows:
| | | | December 31, 2018 | | December 31, 2017 | December 31, 2019 | | December 31, 2018 |
| (in millions) | Carrying Value1 | | Fair Value2 | | Carrying Value1 | | Fair Value2 | Carrying Value1 | | Fair Value2 | | Carrying Value1 | | Fair Value2 |
| Edison International | $ | 14,711 |
| | $ | 14,844 |
| | $ | 12,123 |
| | $ | 13,760 |
| $ | 18,343 |
| | $ | 20,137 |
| | $ | 14,711 |
| | $ | 14,844 |
|
| SCE | 12,971 |
| | 13,180 |
| | 10,907 |
| | 12,547 |
| 15,211 |
| | 16,892 |
| | 12,971 |
| | 13,180 |
|
| |
1 | Carrying value is net of debt issuance costs. |
| |
2 | The fair value of Edison International's and SCE's short-term and long-term debt is classified as Level 2. |
Note 5. Debt and Credit Agreements
Long-Term Debt
The following table summarizes long-term debt (rates and terms are as of December 31, 2018)2019) of Edison International and SCE:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Edison International Parent and Other: | | | |
| Debentures and notes: | | | |
| 2020 – 2028 (2.125% to 5.750%) | $ | 3,150 |
| | $ | 1,750 |
|
| Current portion of long-term debt | (400 | ) | | — |
|
| Unamortized debt discount/premium and issuance costs, net | (18 | ) | | (10 | ) |
| Total Edison International Parent and Other | 2,732 |
| | 1,740 |
|
| SCE: | | | |
| First and refunding mortgage bonds: | | | |
| 2021 – 2049 (1.845% to 6.05%) | 14,272 |
| | 12,050 |
|
| Pollution-control bonds: | | | |
| 2028 – 2035 (1.875% to 5.00%) | 752 |
| | 752 |
|
| Debentures and notes: | | | |
| 2029 – 2053 (5.06% to 6.65%) | 306 |
| | 306 |
|
| Current portion of long-term debt | (79 | ) | | (79 | ) |
| Unamortized debt discount/premium and issuance costs, net | (119 | ) | | (137 | ) |
| Total SCE | 15,132 |
| | 12,892 |
|
| Total Edison International | $ | 17,864 |
| | $ | 14,632 |
|
|
| | | | | | | |
| | December 31, |
| (in millions) | 2018 | | 2017 |
| Edison International Parent and Other: | | | |
| Debentures and notes: | | | |
| 2020 – 2028 (2.125% to 4.125%) | $ | 1,750 |
| | $ | 1,200 |
|
Other long-term debt1 | — |
| | 29 |
|
| Current portion of long-term debt | — |
| | (2 | ) |
| Unamortized debt discount and issuance costs, net | (10 | ) | | (13 | ) |
| Total Edison International Parent and Other | 1,740 |
| | 1,214 |
|
| SCE: | | | |
| First and refunding mortgage bonds: | | | |
| 2021 – 2048 (1.845% to 6.05%) | 12,050 |
| | 9,779 |
|
| Pollution-control bonds: | | | |
2028 – 2035 (1.875% to 5.0%)2 | 752 |
| | 909 |
|
| Debentures and notes: | | | |
| 2029 – 2053 (5.06% to 6.65%) | 306 |
| | 307 |
|
| Current portion of long-term debt | (79 | ) | | (479 | ) |
| Unamortized debt discount and issuance costs, net | (137 | ) | | (88 | ) |
| Total SCE | 12,892 |
| | 10,428 |
|
| Total Edison International | $ | 14,632 |
| | $ | 11,642 |
|
| |
1
| Includes $29 million of long-term debt as of December 31, 2017 for SoCore Energy, which was sold in April 2018. See Note 1 for further details on the sale of SoCore Energy. |
| |
2
| Balance as of December 31, 2017 excludes outstanding bonds due in 2031 that may be remarketed to investors in the future. These bonds were retired in April 2018. |
Edison International and SCE long-term debt maturities over the next five years are the following:as follows:
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
| 2020 | $ | 479 |
| | $ | 79 |
|
| 2021 | 1,029 |
| | 1,029 |
|
| 2022 | 1,064 |
| | 364 |
|
| 2023 | 1,300 |
| | 900 |
|
| 2024 | 500 |
| | — |
|
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
| 2019 | $ | 79 |
| | $ | 79 |
|
| 2020 | 479 |
| | 79 |
|
| 2021 | 1,029 |
| | 1,029 |
|
| 2022 | 764 |
| | 364 |
|
| 2023 | 1,300 |
| | 900 |
|
Liens and Security Interests
Almost all of SCE's properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage bonds as collateral for borrowed funds obtained from pollution-control bonds issued by government agencies. SCE has a debt covenant that requires a debt to total capitalization ratio to be less than or equal to 0.65 to 1. At December 31, 2018,2019, SCE was in compliance with this debt covenant and all other financial covenants that affect access to capital.
Credit Agreements and Short-Term Debt
The following table summarizes the status of the credit facilities at December 31, 2018:2019:
|
| | | | | | | |
| (in millions) | Edison International Parent | | SCE |
| Commitment | $ | 1,500 |
| | $ | 3,000 |
|
| Outstanding borrowings (excluding discount) | — |
| | (550 | ) |
| Outstanding letters of credit | — |
| | (152 | ) |
| Amount available | $ | 1,500 |
| | $ | 2,298 |
|
|
| | | | | | | |
| (in millions) | Edison International Parent | | SCE |
| Commitment | $ | 1,500 |
| | $ | 3,000 |
|
| Outstanding borrowings (excluding discount) | — |
| | (721 | ) |
| Outstanding letters of credit | — |
| | (190 | ) |
| Amount available | $ | 1,500 |
| | $ | 2,089 |
|
In May 2018, SCE and Edison International Parent amended their multi-year revolving credit facilities to increase the facilities to $3.0 billion and $1.5 billion from $2.75 billion and $1.25 billion, respectively. Both facilities mature in May 2023 and have two 1-year extension options. SCE's credit facility is generally used to support commercial paper borrowings and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working capital requirements to support operations and capital expenditures. Edison International Parent's credit facility is used to support commercial paper borrowings and for general corporate purposes.
At December 31, 2018, commercial paper, net of discount, was $720 million at a weighted-average interest rate of 3.23%.
At December 31, 2018, letters of credit issued under SCE's credit facility aggregated $190 million and are scheduled to expire in twelve months or less. At December 31, 2017, the outstanding commercial paper, net of discount, was $738 million at a weighted-average interest rate of 1.75%. In December 2017, SCE borrowed $500 million from the credit facility which had an interest rate of 2.46% on December 31, 2017; this borrowing was repaid in January 2018 with cash on hand.
At December 31, 2018, Edison International Parent had no outstanding commercial paper. At December 31, 2017, the outstanding commercial paper, net of discount, was $639 million at a weighted-average interest rate of 1.70%. In December 2017, Edison International borrowed $500 million from the credit facility which had an interest rate of 2.56% on December 31, 2017; this borrowing was repaid in January 2018 with cash on hand.
Debt Financing Subsequent to December 31, 2018
In February 2019, SCE borrowed $750 million under a Term Loan Agreement due in February 2020 ("February 2019 SCE Term Loan"), with a variable interest rate based on the London Interbank Offered Rate plus 70 basis points. The proceeds were used to repay SCE's commercial paper borrowings and for general corporate purposes. As noted below, the February 2019 SCE Term Loan was fully repaid in April 2019.
In April 2019, Edison International Parent borrowed $1.0 billion under a Term Loan Agreement due in April 2020 ("April 2019 Edison International Parent Term Loan"), with a variable interest rate based on the London Interbank Offered Rate plus 90 basis points. Of the proceeds, $750 million was contributed to SCE and SCE used this contribution to repay the February 2019 SCE Term Loan as discussed above. The remainder of the proceeds were used for general corporate and working capital purposes. The April 2019 Edison International Parent Term Loan was fully repaid in December 2019.
In June 2019, SCE and Edison International Parent amended the maturity date of their multi-year revolving credit facilities of
76$3.0 billion and $1.5 billion, respectively. The facilities now mature in May 2024, with an option to extend for an additional
year, which may be exercised upon agreement between SCE or Edison International Parent and their respective lenders.
SCE's credit facility is generally used to support commercial paper borrowings and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working
capital requirements to support operations and capital expenditures. Edison International Parent's credit facility is used to
support commercial paper borrowings and for general corporate purposes.
At December 31, 2019, SCE's commercial paper, net of discount, was $550 million at a weighted average interest rate of 2.24%. At December 31, 2019, letters of credit issued under SCE's credit facility aggregated $152 million and are scheduled to expire in twelve months or less. At December 31, 2018, the outstanding commercial paper, net of discount, was $720 million at a weighted average interest rate of 3.23%.
At December 31, 2019 and December 31, 2018, Edison International Parent had 0 outstanding commercial paper.
Debt Financing Subsequent to December 31, 2019
In January 2020, SCE issued $100 million of 2.85% first and refunding mortgage bonds due in 2029 and $500 million of 3.65% first and refunding mortgage bonds due in 2050. The proceeds were primarily used to repay SCE's commercial
paper borrowings.
Note 6. Derivative Instruments
Derivative financial instruments are used to manage exposure to commodity price risk. These risks are managed in part by entering into forward commodity transactions, including options, swaps and futures. To mitigate credit risk from counterparties in the event of nonperformance, master netting agreements are used whenever possible and counterparties may be required to pledge collateral depending on the creditworthiness of each counterparty and the risk associated with the transaction.
Commodity Price Risk
Commodity price risk represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's electricity price exposure arises from energy purchased from and sold to wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities and PPAs. SCE's natural gas price exposure arises from natural gas purchased for the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and PPAs in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.
CreditSales and Default RiskUse Taxes
CreditSCE bills certain sales and default risk representuse taxes levied by state or local governments to its customers. Included in these sales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to operate within the potentiallimits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE's ability to collect from the customer, are accounted for on a gross basis. SCE's franchise fees billed to customers were $122 million, $133 million and $133 million for the years ended December 31, 2019, 2018 and 2017, respectively. When SCE acts as an agent for sales and use tax, the taxes are accounted for on a net basis. Amounts billed to and collected from customers for these taxes are remitted to the taxing authorities and are not recognized as electric utility revenue.
SCE's Alternative Revenue Programs
The CPUC and FERC have authorized additional, alternative revenue programs which adjust billings for the effects of broad external factors or compensate SCE for demand-side management initiatives and provide for incentive awards if SCE achieves certain objectives. These alternative revenue programs allow SCE to recover costs that SCE has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, revenue is recognized for these alternative revenue programs at the time the costs are incurred and, for incentive-based programs, at the time the awards are approved by the CPUC. SCE begins recognizing revenues for these programs when a program has been established by an order from either the CPUC or FERC that allows for automatic adjustment of future rates, the amount of revenue for the period is objectively determinable and probable of recovery and the revenue will be collected within 24 months following the end of the annual period.
Regulatory Proceedings
2018 General Rate Case
In the absence of a 2018 GRC final decision, SCE recognized revenue in 2018 and the first quarter of 2019 based on the 2017 authorized revenue requirement, adjusted for items SCE determined to be probable of occurring, primarily the July 2017 cost of capital decision and the Tax Cuts and Jobs Act ("Tax Reform"). Adjustments were also made to 2017 authorized revenue to reflect changes in authorized tax benefits for certain balancing accounts. See Note 11 for further information.
In May 2019, the CPUC approved a final decision in SCE's 2018 GRC. The final decision authorized a revenue requirement of $5.1 billion for 2018 and identified changes to certain balancing accounts, including the expansion of the TAMA to include the impacts of all differences between forecast and recorded tax expense. The final decision also disallowed certain historical spending, largely related to specific pole replacements the CPUC determined were performed prematurely.
The final decision allows a post-test year rate making mechanism that escalates capital additions by 2.49% for both 2019 and 2020. It also allows operation and maintenance expenses to be escalated for 2019 and 2020 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology set forth in the final decision results in a revenue requirement of $5.5 billion in 2019 and $5.9 billion in 2020.
The revenue requirements in the 2018 GRC final decision are retroactive to January 1, 2018. SCE recorded the prior period impact of the 2018 GRC final decision in 2019 including:
An increase to earnings of $131 million from the application of the decision to revenue, depreciation expense and income tax expense. Depreciation expense decreased as a result of lower authorized depreciation rates. An increase in the authorized revenue requirement for income tax expense offsets income tax expense recognized during 2018 and the first quarter of 2019. The reduction of revenue of $265 million reflected $289 million of lower authorized revenue related to 2018 and $24 million of higher authorized revenue in 2019. The reduction in revenue contributed to a refund to customers of $554 million, which SCE recorded as a regulatory liability. SCE expects to refund these amounts to customers through December 2020.
An impairment of utility property, plant and equipment of $170 million ($123 million after-tax) related to disallowed historical capital expenditures, primarily the write-off of specific pole replacements the CPUC determined were performed prematurely.
2018 and 2019 FERC Formula Rate
In December 2019, the FERC approved a settlement on SCE's formula rates for the 2018 Formula Rate case that can be caused if a counterparty wereestablished SCE's FERC transmission revenue requirement for January 1, 2018 through November 11, 2019 (the "FERC 2018 Settlement Period"). Prior to defaultthe settlement, SCE had been recognizing revenue during the FERC 2018 Settlement Period based on its contractual obligationsexpectations of the probable outcome of the 2018 Formula Rate case. Regulatory assets and SCE would be exposed to spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed toliabilities were adjusted based on the risksettlement of non-paymentthe 2018 Formula Rate case, which resulted in an increase in net income of accounts receivable, primarily$29 million related to 2018, being recorded in 2019. The 2019 Formula Rate remains subject to hearing and settlement procedures and amounts billed to customers under the sales2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved. Pending resolution of excessthe 2019 Formula Rate case, SCE is recognizing revenue based on the return on equity established in the 2020 Cost of Capital decision of the CPUC.
Power Purchase Agreements
SCE enters into power purchase agreements ("PPAs") in the normal course of business. A power purchase agreement may be considered a variable interest in a variable interest entity ("VIE"). If SCE is the primary beneficiary in the VIE, SCE should consolidate the VIE. None of SCE's PPAs resulted in consolidation of a VIE at December 31, 2019 and realized gains2018. See Note 3 for further discussion of PPAs that are considered variable interests.
A PPA may also contain a lease for accounting purposes. See "Leases" below and Note 12 and Note 13 for further discussion of SCE's PPAs, including agreements that are classified as operating and finance leases for accounting purposes.
A PPA that does not contain a lease may be classified as a derivative which is recorded at fair value on the consolidated balance sheets. These PPAs may be eligible for an election to designate as a normal purchase and sale, which is accounted for on an accrual basis as an executory contract. See Note 6 for further information on derivative instruments.
CertainPPAs that do not meet the above classifications are accounted for on an accrual basis.
Derivative Instruments
SCE records derivative instruments on its consolidated balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as normal purchases or sales. The normal purchases and sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business.
Realized gains and losses from SCE's derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no impact on purchased power and gas contracts containexpense or earnings. SCE does not use hedge accounting for derivative transactions due to regulatory accounting treatment.
Where SCE's derivative instruments are subject to a master netting agreements or similar agreements, which generally allow counterparties subject to the agreement to offset amounts whenand certain criteria are met, SCE presents its derivative assets and liabilities on a net basis on its consolidated balance sheets. In addition, derivative positions are offset against margin and cash collateral deposits. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. See Note 6 for further information on derivative instruments.
Leases
A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified assets for a period of time in exchange for consideration. An entity controls the use when it has a right to obtain substantially all of the benefits from the use of the identified asset and has the right to direct the use of the asset. SCE determines if an arrangement is a lease at contract inception. For all classes of underlying assets, SCE includes both the lease and non-lease components as a single component and accounts for it as a lease. Lease liabilities are recognized based on the present value of the lease payments over the lease term at the commencement date. SCE calculates and uses the rate implicit in the lease if the information is readily available or if not available, SCE uses its incremental borrowing rate in determining the present value of lease payments. Incremental borrowing rates are comprised of underlying risk-free rates and secured credit spreads relative to first mortgage bonds with like tenors of lease term durations. Lease right-of-use ("ROU") assets are based on the liability, subject to adjustments, such as lease incentives. The ROU assets also include any lease payments made at or before the commencement date. SCE excludes variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. SCE's lease terms include options to extend or terminate the lease when it is reasonably certain that such options will be exercised. Operating leases are included in "Operating lease right-of-use assets," "Current portion of operating lease liabilities" and "Operating lease liabilities" on the consolidated balance sheets. Finance leases are included in "Utility property, plant and equipment," "Other current liabilities" and "Other deferred credits and other long-term liabilities" on the consolidated balance sheets.
SCE enters into power purchase agreements that may contain leases. This occurs when a power purchase agreement designates a specific power plant, SCE obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. Leases that commenced before January 1, 2019 were not reassessed as SCE elected the package of practical expedients (see "Accounting Guidance Adopted" below for more information). Prior to January 1, 2019, a power purchase agreement contained a lease when SCE purchased substantially all of the output from a specific plant and did not otherwise meet a fixed price per unit of output exception. SCE also enters into a number of agreements to lease property and equipment in the normal course of business, primarily related to vehicles, office space and other equipment. See Note 13 for further discussion of SCE's contracts that are classified as operating and finance leases.
Edison International Parent and Other's leases primarily relate to Edison Energy Group. The leases for Edison International Parent and Other are immaterial to Edison International.
Stock-Based Compensation
Stock options, performance shares, deferred stock units and restricted stock units have been granted under Edison International's long-term incentive compensation programs. For equity awards that are settled in common stock, Edison International either issues new common stock, or uses a third party to purchase shares from the market and deliver such shares for the settlement of the awards. The performance shares granted during 2017 to 2018 that are earned, have been or will be settled solely in cash. The performance shares granted in 2019 that are earned, will be settled in common stock. Stock options, deferred stock units and restricted stock units are settled in common stock. However, for awards that are otherwise settled entirely in common stock, Edison International substitutes cash awards to the extent necessary to satisfy applicable tax withholding obligations or government levies.
Stock-based compensation expense is recognized, net of estimated forfeitures, on a straight-line basis over the requisite service period based on estimated fair values. For equity awards paid in common stock, fair value is determined at the grant date. However, with respect to the portion of the performance shares payable in common stock that are subject to market and financial performance conditions defined in the grants, the number of performance shares expected to be earned is subject to revision and updated at each reporting period, with a related adjustment to compensation expense. Awards paid in cash are classified as share-based liability awards and fair value is remeasured at each reporting date with the related compensation cost adjusted. For awards granted to retirement-eligible participants, stock compensation expense is recognized on a prorated basis over the initial year. For awards granted to participants who become eligible for retirement during the requisite service period, stock compensation expense is recognized over the period between the date of grant and the date the participant first becomes eligible for retirement. Edison International and SCE estimate the number of awards that are expected to vest rather than account for forfeitures when they occur. Share-based payments may create a permanent difference between the amount of compensation expense recognized for book and tax purposes. The tax impact of this permanent difference is recognized in earnings in the period it is created. See Note 9 for further information.
SCE Dividends
CPUC holding company rules require that SCE's dividend policy be established by SCE's Board of Directors on the same basis as if SCE were a stand-alone utility company, and that the capital requirements of SCE, as deemed to be necessary to meet SCE's electricity service obligations, shall receive first priority from the Boards of Directors of both Edison International and SCE. In addition, the CPUC regulates SCE's capital structure which limits the dividends it may pay to its shareholders.
Prior to January 1, 2020, under SCE's interpretation of CPUC regulations and capital structure decisions, the common equity component of SCE's capital structure was required to remain at or above 48% on a weighted average basis over the 37-month period that SCE's capital structure was in effect for ratemaking purposes and SCE was required to file an application for a waiver of the 48% equity ratio condition discussed above if an adverse financial event reduces its spot equity ratio below 47%. Effective January 1, 2020, the common equity component of SCE's authorized capital structure was increased from 48% to 52%. Under AB 1054, the impact of SCE's contributions to the Wildfire Insurance Fund are excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. For further information, see Note 12.
On February 28, 2019, SCE submitted an application to the CPUC for waiver of compliance with this equity ratio requirement, describing that while the charge accrued in connection with the 2017/2018 Wildfire/Mudslide Events caused its equity ratio to fall below 47% on a spot basis as of December 31, 2018, SCE remains in compliance with the 48% equity ratio over the applicable 37-month average basis. In its application, SCE requested a limited waiver to exclude wildfire-related charges and wildfire-related debt issuances from its equity ratio calculations until a determination regarding cost recovery is made. The CPUC has ruled that while the application is pending resolution, SCE must notify the CPUC if an adverse financial event reduces SCE's spot equity ratio by more than one percent from the level most recently filed with the CPUC in the proceeding. The last spot equity ratio SCE filed with the CPUC in the proceeding was 45.2% as of December 31, 2018. Under the CPUC's rules, SCE will not be deemed to be in violation of the equity ratio requirement, and therefore may continue to issue debt and dividends, while the waiver application is pending resolution. For further information, see Note 12. At December 31, 2019, without excluding the $2.0 billion after-tax wildfire-related charges incurred in 2018 and 2019, SCE's 37-month average common equity component of total capitalization was 48.5% and the maximum additional dividend that SCE could pay to Edison International under this limitation was $179 million, resulting in a restriction on net assets of approximately $17.6 billion. If the wildfire-related charges were excluded at December 31, 2019, SCE's 37-month average common equity component of total capitalization would have been 49.6%.
As a California corporation, SCE's ability to pay dividends is also governed by the California General Corporation Law. California law requires that for a dividend to be declared: (a) retained earnings must equal or exceed the proposed dividend, or (b) immediately after the dividend is made, the value of the corporation's assets must exceed the value of its liabilities plus amounts required to be paid, if any, in order to liquidate stock senior to the shares receiving the dividend. Additionally, a California corporation may not declare a dividend if it is, or as a result of the dividend would be, likely to be unable to meet its liabilities as they mature. Prior to declaring dividends, SCE's Board of Directors evaluates available information, including when applicable, information pertaining to the 2017/2018 Wildfire/Mudslide Events, to ensure that the California law requirements for the declarations are met. On February 27, 2020, SCE declared a dividend to Edison International of $269 million.
The timing and amount of future dividends are also dependent on a number of other factors including SCE's requirements to fund other obligations and capital expenditures, its ability to access the capital markets, and generate operating cash flows and earnings. If SCE incurs significant costs related to catastrophic wildfires, including the 2017/2018 Wildfire/Mudslide Events, and is unable to recover such costs through insurance, the Wildfire Insurance Fund (for fires after July 12, 2019), or from customers or access capital markets on reasonable terms, SCE may be limited in its ability to pay future dividends to Edison International and its preferred and preference shareholders.
Earnings Per Share
Edison International computes earnings per common share ("EPS") using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's participating securities are stock-based compensation awards, payable in common shares, which earn dividend equivalents on an equal basis with common shares once the awards are vested. See Note 9 and Note 14 for further information.
EPS attributable to Edison International common shareholders was computed as follows:
|
| | | | | | | | | | | |
| | Years ended December 31, |
| (in millions, except per share amounts) | 2019 | | 2018 | | 2017 |
| Basic earnings (loss) per share – continuing operations: | | | | | |
| Income (loss) from continuing operations attributable to common shareholders | $ | 1,284 |
| | $ | (457 | ) | | $ | 565 |
|
| Participating securities dividends | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Weighted average common shares outstanding | 340 |
| | 326 |
| | 326 |
|
| Basic earnings (loss) per share – continuing operations | 3.78 |
| | (1.40 | ) | | 1.73 |
|
| Diluted earnings (loss) per share – continuing operations: | | | | | |
| Income (loss) from continuing operations attributable to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Participating securities dividends | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Income impact of assumed conversions | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders and assumed conversions | 1,284 |
| | (457 | ) | | 565 |
|
| Weighted average common shares outstanding | 340 |
| | 326 |
| | 326 |
|
Incremental shares from assumed conversions1 | 1 |
| | — |
| | 2 |
|
| Adjusted weighted average shares – diluted | 341 |
| | 326 |
| | 328 |
|
| Diluted earnings (loss) per share – continuing operations | $ | 3.77 |
| | $ | (1.40 | ) | | $ | 1.72 |
|
| |
1 | Due to the loss reported for the year ended December 31, 2018, incremental shares were not included as the effect would be antidilutive. |
In addition to the participating securities discussed above, Edison International also may award stock options, which are payable in common shares and are included in the diluted earnings per share calculation. Stock option awards to purchase 4,511,802, 8,852,706 and 1,334,451 shares of common stock for the years ended December 31, 2019, 2018 and 2017, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the effect would have been antidilutive.
Income Taxes
Edison International and SCE estimate their income taxes for each jurisdiction in which they operate. This involves estimating current period tax expense along 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 in the consolidated balance sheets. 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% which resulted in the re-measurement of deferred taxes using the new tax rate. See Note 8 for further information.
Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Interest income, interest expense and penalties associated with income taxes are reflected in "Income tax expense" on the consolidated statements of income.
Edison International's eligible subsidiaries are included in Edison International's consolidated federal income tax and combined state tax returns. Edison International has tax-allocation and payment agreements with certain of its subsidiaries. Pursuant to an income tax-allocation agreement approved by the CPUC, SCE's tax liability is computed as if it filed its federal and state income tax returns on a separate return basis.
New Accounting Guidance
Accounting Guidance Adopted
On January 1, 2019, Edison International and SCE adopted accounting standards updates that require lessees to recognize a lease on the balance sheet as a ROU asset and related lease liability and classify the lease as either operating or finance. Edison International and SCE adopted this guidance using the modified retrospective approach for leases that existed as of the adoption date and elected the optional transition method not to restate periods prior to the adoption date. Edison International and SCE also elected the package of practical expedients not to reassess prior conclusions related to contracts containing leases, lease classification and initial direct costs, and the practical expedient not to reassess existing land easements. Adoption of this standard increased ROU assets and lease liabilities on the consolidated balance sheets by $956 million and $951 million as of January 1, 2019 for Edison International and SCE, respectively. The standard did not materially impact the consolidated statements of income for Edison International or SCE. See "Leases" above and Note 13 for further information.
In February 2018, the Financial Accounting Standards Board ("FASB") issued an accounting standards update to provide entities an election to reclassify stranded tax effects resulting from Tax Reform from accumulated other comprehensive income to retained earnings. Stranded tax effects originated in December 2017 when deferred taxes were re-measured at the lower federal corporate tax rate with the impact included in operating income, while the tax effects of items within accumulated other comprehensive income were not similarly adjusted. Edison International and SCE adopted this guidance on January 1, 2019 and reclassified stranded tax effects of $10 million and $5 million, respectively, from accumulated other comprehensive loss to retained earnings. See Note 15 for further information.
In August 2018, the FASB issued an accounting standards update to remove, modify, and add certain disclosure requirements related to fair value measurement. Edison International and SCE adopted this guidance effective January 1, 2019. The adoption of this guidance did not have a material impact on Edison International's and SCE's disclosures. See Note 4 for further information.
Accounting Guidance Not Yet Adopted
In June 2016, the FASB issued an accounting standards update to require the use of the current expected credit loss model to measure impairment of financial instruments and the use of an allowance to record estimated credit losses on available-for-sale debt securities. The guidance, as later amended, allows entities to irrevocably elect the fair value option for any financial instrument previously measured on an amortized costs basis. Edison International and SCE do not believe the adoption of the standard will have a material impact on financial position or results of operations. Edison International and SCE will apply a prospective adoption approach to available-for-sale debt securities and a modified retrospective approach to all other financial assets. Edison International and SCE will not elect the fair value option. Edison International and SCE will adopt this guidance effective January 1, 2020.
In January 2017, the FASB issued an accounting standards update to simplify the accounting for goodwill impairment by changing the procedural steps to apply the goodwill impairment test. After the adoption of this accounting standards update, goodwill impairment will be measured as the amount by which a reporting unit's carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Edison International will apply this guidance to goodwill impairment tests beginning in 2020.
In August 2018, the FASB issued an accounting standards update which aligns the requirement for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs incurred to develop or obtain internal use software. The guidance also clarified presentation requirements for reporting implementation costs in the financial statements. Edison International and SCE do not believe the adoption of the standard will have a material impact on financial position or results of operations and will apply this guidance prospectively, effective January 1, 2020.
In August 2018, the FASB issued an accounting standards update to remove, modify, and add certain disclosure requirements related to employer-sponsored defined benefit pension or other postretirement plans. The guidance is effective January 1, 2021 with early adoption permitted. Edison International and SCE are currently evaluating the impact of the guidance and do not expect the adoption of this standard will materially affect disclosures.
Note 2. Property, Plant and Equipment
SCE's property, plant and equipment included in the consolidated balance sheets is composed of the following:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Distribution | $ | 26,929 |
| | $ | 25,026 |
|
| Transmission | 14,720 |
| | 13,800 |
|
| Generation | 3,664 |
| | 3,598 |
|
| General plant and other | 4,583 |
| | 4,398 |
|
| Accumulated depreciation | (9,958 | ) | | (9,566 | ) |
| | 39,938 |
| | 37,256 |
|
| Construction work in progress | 4,131 |
| | 3,883 |
|
| Nuclear fuel, at amortized cost | 129 |
| | 130 |
|
| Total utility property, plant and equipment | $ | 44,198 |
| | $ | 41,269 |
|
Capitalized Software Costs
SCE capitalizes costs incurred during the application development stage of internal use software projects to property, plant and equipment. SCE amortizes capitalized software costs ratably over the expected lives of the software, primarily ranging from 5 to 7 years and commencing upon operational use. Capitalized software costs, included in general plant and other above, were $1.0 billion and $1.0 billion at December 31, 2019 and 2018, respectively, and accumulated amortization was $0.4 billion and $0.5 billion, at December 31, 2019 and 2018, respectively. Amortization expense for capitalized software was $190 million, $198 million and $233 million in 2019, 2018 and 2017, respectively. At December 31, 2019, amortization expense is estimated to be $191 million, $163 million, $116 million, $76 million and $27 million for 2020 through 2024, respectively.
Jointly Owned Utility Projects
SCE owns undivided interests in transmission and generating assets for which each participant provides its own financing. SCE's proportionate share of these assets is reflected in the consolidated balance sheets and included in the above table. SCE's proportionate share of expenses for each project is reflected in the consolidated statements of income.
The following is SCE's investment in each asset as of December 31, 2019:
|
| | | | | | | | | | | | | | | | | |
| (in millions) | Plant in Service | Construction Work in Progress | Accumulated Depreciation | Nuclear Fuel (at amortized cost) | Net Book Value | Ownership Interest |
| Transmission systems: | | | | | | |
| Eldorado | $ | 257 |
| $ | 94 |
| $ | 35 |
| $ | — |
| $ | 316 |
| 80 | % |
| Pacific Intertie | 248 |
| 80 |
| 72 |
| — |
| 256 |
| 50 | % |
| Generating station: | | | | | | |
| Palo Verde (nuclear) | 2,065 |
| 61 |
| 1,586 |
| 129 |
| 669 |
| 16 | % |
| Total | $ | 2,570 |
| $ | 235 |
| $ | 1,693 |
| $ | 129 |
| $ | 1,241 |
| |
In addition, SCE has ownership interests in jointly owned power poles with other companies.
Note 3. Variable Interest Entities
A VIE is defined as a legal entity that meets one of two conditions: (1) the equity owners do not have sufficient equity at risk, or (2) the holders of the equity investment at risk, as a group, lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that most significantly impact the economic performance of such VIEs. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
Variable Interest in VIEs that are not Consolidated
Power Purchase Agreements
SCE has PPAs that are classified as variable interests in VIEs, including tolling agreements through which SCE provides the natural gas to fuel the plants and contracts with qualifying facilities ("QF") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. Since payments for capacity are the primary source of income, the most significant economic activity for these VIEs is the operation and maintenance of the power plants.
As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to involvement with VIEs result from amounts due under the PPAs. Under these contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 12. As a result, there is no significant potential exposure to loss to SCE from its variable interest in these VIEs. The aggregate contracted capacity dedicated to SCE from these VIE projects was 4,497 megawatts ("MW") and 3,602 MW at December 31, 2019 and 2018, respectively, and the amounts that SCE paid to these projects were $833 million and $762 million for the years ended December 31, 2019 and 2018, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.
Unconsolidated Trusts of SCE
SCE Trust II, Trust III, Trust IV, Trust V and Trust VI were formed in 2013, 2014, 2015, 2016 and 2017, respectively, for the exclusive purpose of issuing the 5.10%, 5.75%, 5.375%, 5.45% and 5.00% trust preference securities, respectively ("trust securities"). The trusts are VIEs. SCE has concluded that it is not the primary beneficiary of these VIEs as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trusts. SCE Trust II, Trust III, Trust IV, Trust V and Trust VI issued to the public trust securities in the face amounts of $400 million, $275 million, $325 million, $300 million and $475 million (cumulative, liquidation amounts of $25 per share), respectively, and $10,000 of common stock each to SCE. The trusts invested the proceeds of these trust securities in Series G, Series H, Series J, Series K and Series L Preference Stock issued by SCE in the principal amounts of $400 million, $275 million, $325 million, $300 million and $475 million (cumulative, $2,500 per share liquidation values), respectively, which have substantially the same payment terms as the respective trust securities.
The Series G, Series H, Series J, Series K and Series L Preference Stock and the corresponding trust securities do not have a maturity date. Upon any redemption of any shares of the Series G, Series H, Series J, Series K or Series L Preference Stock, a corresponding dollar amount of trust securities will be redeemed by the applicable trust (see Note 14 for further information). The applicable trust will make distributions at the same rate and on the same dates on the applicable series of trust securities if and when the SCE board of directors declares and makes dividend payments on the related Preference Stock. The applicable trust will use any dividends it receives on the related Preference Stock to make its corresponding distributions on the applicable series of trust securities. If SCE does not make a dividend payment to any of these trusts, SCE would be prohibited from paying dividends on its common stock. SCE has fully and unconditionally guaranteed the payment of the trust securities and trust distributions, if and when SCE pays dividends on the related Preference Stock.
SCE formed Trust I, a VIE, in 2012 for the exclusive purpose of issuing 5.625% trust preference securities. SCE Trust I issued trust securities in the face amounts of $475 million to the public and $10,000 of common stock to SCE. SCE Trust I invested the proceeds of these trust securities in Series F Preference Stock issued by SCE in the principal amount of $475 million. In July 2017, all of the outstanding Series F Preference Stock was redeemed, and accordingly, SCE Trust I
redeemed $475 million of trust securities from the public and $10,000 of common stock from SCE. As a result in September 2017, SCE Trust I was terminated.
The Trust II, Trust III, Trust IV, Trust V and Trust VI balance sheets as of December 31, 2019 and 2018, consisted of investments of $400 million, $275 million, $325 million, $300 million and $475 million in the Series G, Series H, Series J, Series K and Series L Preference Stock, respectively, $400 million, $275 million, $325 million, $300 million and $475 million of trust securities, respectively, and $10,000 each of common stock.
The followingtable provides a summary of the trusts' income statements:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Years ended December 31, |
| (in millions) | Trust I | | Trust II | | Trust III | | Trust IV | | Trust V | | Trust VI |
| 2019 | | | | | | | | | | | |
| Dividend income | * |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 24 |
|
| Dividend distributions | * |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 24 |
|
| 2018 | | | | | | | | | | | |
| Dividend income | * |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 24 |
|
| Dividend distributions | * |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 24 |
|
| 2017 | | | | | | | | | | | |
| Dividend income | $ | 14 |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 12 |
|
| Dividend distributions | 14 |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 12 |
|
* Not applicable
Note 4. Fair Value Measurements
Recurring Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or liability considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. As of December 31, 2019 and 2018, nonperformance risk was not material for Edison International and SCE.
Assets and liabilities are categorized into a three-level fair value hierarchy based on valuation inputs used to determine fair value.
Level 1 – The fair value of Edison International's and SCE's Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded equity securities, U.S. treasury securities, mutual funds and money market funds.
Level 2 – Edison International's and SCE's Level 2 assets and liabilities include fixed income securities, primarily consisting of U.S. government and agency bonds, municipal bonds and corporate bonds, and over-the-counter derivatives. The fair value of fixed income securities is determined using a market approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument.
The fair value of SCE's over-the-counter derivative contracts is determined using an income approach. SCE uses standard pricing models to determine the net present value of estimated future cash flows. Inputs to the pricing models include forward published or posted clearing prices from an exchange (Intercontinental Exchange) for similar instruments and discount rates. A primary price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity.
Level 3 – The fair value of SCE's Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes derivative contracts that trade infrequently such as congestion revenue rights ("CRRs"). Edison International Parent and Other does not have any Level 3 assets and liabilities.
Assumptions are made in order to value derivative contracts in which observable inputs are not available. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs, and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts. See Note 6 for a discussion of derivative instruments.
SCE
The following table sets forth assets and liabilities of SCE that were accounted for at fair value by level within the fair value hierarchy:
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 |
| (in millions) | Level 1 | | Level 2 | | Level 3 | | Netting and Collateral1 | | Total |
| Assets at fair value | | | | | | | | | |
| Derivative contracts | $ | — |
| | $ | 19 |
| | $ | 83 |
| | $ | (15 | ) | | $ | 87 |
|
| Other | 4 |
| | 14 |
| | — |
| | — |
| | 18 |
|
| Nuclear decommissioning trusts: | | | | | | | | | |
Stocks2 | 1,765 |
| | — |
| | — |
| | — |
| | 1,765 |
|
Fixed Income3 | 738 |
| | 2,024 |
| | — |
| | — |
| | 2,762 |
|
| Short-term investments, primarily cash equivalents | 98 |
| | 48 |
| | — |
| | — |
| | 146 |
|
Subtotal of nuclear decommissioning trusts4 | 2,601 |
| | 2,072 |
| | — |
| | — |
| | 4,673 |
|
| Total assets | 2,605 |
| | 2,105 |
| | 83 |
| | (15 | ) | | 4,778 |
|
| Liabilities at fair value | | | | | | | | | |
| Derivative contracts | — |
| | 11 |
| | 5 |
| | (15 | ) | | 1 |
|
| Total liabilities | — |
| | 11 |
| | 5 |
| | (15 | ) | | 1 |
|
| Net assets | $ | 2,605 |
| | $ | 2,094 |
| | $ | 78 |
| | $ | — |
| | $ | 4,777 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| (in millions) | Level 1 | | Level 2 | | Level 3 | | Netting and Collateral1 | | Total |
| Assets at fair value | | | | | | | | | |
|
| Derivative contracts | $ | — |
| | $ | 32 |
| | $ | 141 |
| | $ | — |
| | $ | 173 |
|
| Other | 9 |
| | 21 |
| | — |
| | — |
| | 30 |
|
| Nuclear decommissioning trusts: | | | | | | | | | |
Stocks2 | 1,382 |
| | — |
| | — |
| | — |
| | 1,382 |
|
Fixed Income3 | 1,001 |
| | 1,665 |
| | — |
| | — |
| | 2,666 |
|
| Short-term investments, primarily cash equivalents | 120 |
| | 95 |
| | — |
| | — |
| | 215 |
|
Subtotal of nuclear decommissioning trusts4 | 2,503 |
| | 1,760 |
| | — |
| | — |
| | 4,263 |
|
| Total assets | 2,512 |
| | 1,813 |
| | 141 |
| | — |
| | 4,466 |
|
| Liabilities at fair value | | | | | | | | | |
| Derivative contracts | — |
| | 13 |
| | — |
| | (7 | ) | | 6 |
|
| Total liabilities | — |
| | 13 |
| | — |
| | (7 | ) | | 6 |
|
| Net assets | $ | 2,512 |
| | $ | 1,800 |
| | $ | 141 |
| | $ | 7 |
| | $ | 4,460 |
|
| |
1 | Represents the netting of assets and liabilities under master netting agreements and cash collateral. |
| |
2 | Approximately 72% and 71% of SCE's equity investments were located in the United States at December 31, 2019 and 2018, respectively. |
| |
3 | Includes corporate bonds, which were diversified and included collateralized mortgage obligations and other asset backed securities of $46 million and $67 million at December 31, 2019 and 2018, respectively. |
| |
4 | Excludes net payables of $111 million and $143 million at December 31, 2019 and 2018, respectively, which consist of interest and dividend receivables as well as receivables and payables related to SCE's pending securities sales and purchases. |
Edison International Parent and Other
Edison International Parent and Other assets measured at fair value consisted of money market funds of $31 million and $115 million at December 31, 2019 and 2018, respectively, classified as Level 1.
SCE Fair Value of Level 3
The following table sets forth a summary of changes in SCE's fair value of Level 3 net derivative assets and liabilities:
|
| | | | | | | | |
| | | December 31, |
| (in millions) | | 2019 | | 2018 |
| Fair value of net assets at beginning of period | | $ | 141 |
| | $ | 101 |
|
| Total realized/unrealized (losses) gains: | | | | |
Included in regulatory assets and liabilities1 | | (63 | ) | | 40 |
|
Fair value of net assets at end of period2 | | 78 |
| | 141 |
|
| Change during the period in unrealized gains and losses related to assets and liabilities held at the end of the period | | $ | 62 |
| | $ | 138 |
|
| |
1 | Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities. |
| |
2 | There were no material transfers into or out of Level 3 during 2019 and 2018. |
The following table sets forth SCE's valuation techniques and significant unobservable inputs used to determine fair value for significant Level 3 assets and liabilities:
|
| | | | | | | | | | | |
| | Fair Value (in millions) | | Significant | Range | Weighted Average |
| | Assets | | Liabilities | Valuation Technique | Unobservable Input |
| Congestion revenue rights | | | | |
| December 31, 2019 | $ | 83 |
| | $ | 5 |
| Auction prices | CAISO CRR auction clearing prices | $(3.59) - $25.32 | $1.97 |
| December 31, 2018 | 141 |
| | — |
| Auction prices | CAISO CRR auction clearing prices | $(7.41) - $41.52 | $1.62 |
Level 3 Fair Value Uncertainty
For CRRs, increases or decreases in CAISO auction price would result in higher or lower fair value, respectively.
Nuclear Decommissioning Trusts
SCE's nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information. There are no securities classified as Level 3 in the nuclear decommissioning trusts.
SCE's investment policies and CPUC requirements place limitations on the types and investment grade ratings of the securities that may be held by the nuclear decommissioning trust funds. These policies restrict the trust funds from holding alternative investments and limit the trust funds' exposures to investments in highly illiquid markets. With respect to equity and fixed income securities, the trustee obtains prices from third-party pricing services which SCE is able to independently corroborate as described below. The trustee monitors prices supplied by pricing services, including reviewing prices against defined parameters' tolerances and performs research and resolves variances beyond the set parameters. SCE corroborates the fair values of securities by comparison to other market-based price sources obtained by SCE's investment managers. Differences outside established thresholds are followed-up with the trustee and resolved. For each reporting period, SCE reviews the trustee determined fair value hierarchy and overrides the trustee level classification when appropriate.
Nonrecurring Fair Value Measurements
Edison International assesses goodwill at the reporting unit level. The fair value of the Edison Energy reporting unit is classified as Level 3 and is estimated using the income approach. During the fourth quarter of 2019 and 2018, Edison International evaluated the recoverability of goodwill and recorded impairment charges of Edison Energy's goodwill totaling $25 million ($18 million after-tax) and $19 million ($13 million after-tax), respectively. See Note 1 for further details.
Fair Value of Debt Recorded at Carrying Value
The carrying value and fair value of Edison International's and SCE's long-term debt (including current portion of long-term debt) are as follows:
|
| | | | | | | | | | | | | | | |
| | December 31, 2019 | | December 31, 2018 |
| (in millions) | Carrying Value1 | | Fair Value2 | | Carrying Value1 | | Fair Value2 |
| Edison International | $ | 18,343 |
| | $ | 20,137 |
| | $ | 14,711 |
| | $ | 14,844 |
|
| SCE | 15,211 |
| | 16,892 |
| | 12,971 |
| | 13,180 |
|
| |
1 | Carrying value is net of debt issuance costs. |
| |
2 | The fair value of Edison International's and SCE's long-term debt is classified as Level 2. |
Note 5. Debt and Credit Agreements
Long-Term Debt
The following table summarizes long-term debt (rates and terms are as of December 31, 2019) of Edison International and SCE:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Edison International Parent and Other: | | | |
| Debentures and notes: | | | |
| 2020 – 2028 (2.125% to 5.750%) | $ | 3,150 |
| | $ | 1,750 |
|
| Current portion of long-term debt | (400 | ) | | — |
|
| Unamortized debt discount/premium and issuance costs, net | (18 | ) | | (10 | ) |
| Total Edison International Parent and Other | 2,732 |
| | 1,740 |
|
| SCE: | | | |
| First and refunding mortgage bonds: | | | |
| 2021 – 2049 (1.845% to 6.05%) | 14,272 |
| | 12,050 |
|
| Pollution-control bonds: | | | |
| 2028 – 2035 (1.875% to 5.00%) | 752 |
| | 752 |
|
| Debentures and notes: | | | |
| 2029 – 2053 (5.06% to 6.65%) | 306 |
| | 306 |
|
| Current portion of long-term debt | (79 | ) | | (79 | ) |
| Unamortized debt discount/premium and issuance costs, net | (119 | ) | | (137 | ) |
| Total SCE | 15,132 |
| | 12,892 |
|
| Total Edison International | $ | 17,864 |
| | $ | 14,632 |
|
Edison International and SCE long-term debt maturities over the next five years are as follows:
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
| 2020 | $ | 479 |
| | $ | 79 |
|
| 2021 | 1,029 |
| | 1,029 |
|
| 2022 | 1,064 |
| | 364 |
|
| 2023 | 1,300 |
| | 900 |
|
| 2024 | 500 |
| | — |
|
Liens and Security Interests
Almost all of SCE's properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage bonds as collateral for borrowed funds obtained from pollution-control bonds issued by government agencies. SCE has a debt covenant that requires a debt to total capitalization ratio to be less than or equal to 0.65 to 1. At December 31, 2019, SCE was in compliance with this debt covenant and all other financial covenants that affect access to capital.
Credit Agreements and Short-Term Debt
The following table summarizes the status of the credit facilities at December 31, 2019:
|
| | | | | | | |
| (in millions) | Edison International Parent | | SCE |
| Commitment | $ | 1,500 |
| | $ | 3,000 |
|
| Outstanding borrowings (excluding discount) | — |
| | (550 | ) |
| Outstanding letters of credit | — |
| | (152 | ) |
| Amount available | $ | 1,500 |
| | $ | 2,298 |
|
In February 2019, SCE borrowed $750 million under a Term Loan Agreement due in February 2020 ("February 2019 SCE Term Loan"), with a variable interest rate based on the London Interbank Offered Rate plus 70 basis points. The proceeds were used to repay SCE's commercial paper borrowings and for general corporate purposes. As noted below, the February 2019 SCE Term Loan was fully repaid in April 2019.
In April 2019, Edison International Parent borrowed $1.0 billion under a Term Loan Agreement due in April 2020 ("April 2019 Edison International Parent Term Loan"), with a variable interest rate based on the London Interbank Offered Rate plus 90 basis points. Of the proceeds, $750 million was contributed to SCE and SCE used this contribution to repay the February 2019 SCE Term Loan as discussed above. The remainder of the proceeds were used for general corporate and working capital purposes. The April 2019 Edison International Parent Term Loan was fully repaid in December 2019.
In June 2019, SCE and Edison International Parent amended the maturity date of their multi-year revolving credit facilities of
$3.0 billion and $1.5 billion, respectively. The facilities now mature in May 2024, with an option to extend for an additional
year, which may be exercised upon agreement between SCE or Edison International Parent and their respective lenders.
SCE's credit facility is generally used to support commercial paper borrowings and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working
capital requirements to support operations and capital expenditures. Edison International Parent's credit facility is used to
support commercial paper borrowings and for general corporate purposes.
At December 31, 2019, SCE's commercial paper, net of discount, was $550 million at a weighted average interest rate of 2.24%. At December 31, 2019, letters of credit issued under SCE's credit facility aggregated $152 million and are scheduled to expire in twelve months or less. At December 31, 2018, the outstanding commercial paper, net of discount, was $720 million at a weighted average interest rate of 3.23%.
At December 31, 2019 and December 31, 2018, Edison International Parent had 0 outstanding commercial paper.
Debt Financing Subsequent to December 31, 2019
In January 2020, SCE issued $100 million of 2.85% first and refunding mortgage bonds due in 2029 and $500 million of 3.65% first and refunding mortgage bonds due in 2050. The proceeds were primarily used to repay SCE's commercial
paper borrowings.
Note 6. Derivative Instruments
Derivative financial instruments are used to manage exposure to commodity price risk. These risks are managed in part by entering into forward commodity transactions, including options, swaps and futures. To mitigate credit risk from counterparties in the event of default. The objective ofnonperformance, master netting is to reduce credit exposure. Additionally, to reduce SCE's risk exposuresagreements are used whenever possible and counterparties may be required to pledge collateral depending on the creditworthiness of each counterparty and the risk associated with the transaction.
CertainCommodity Price Risk
Commodity price risk represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's electricity price exposure arises from energy purchased from and sold to wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities and PPAs. SCE's natural gas price exposure arises from natural gas purchased for the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas contracts contain a provision that requiresindex and PPAs in which SCE has agreed to maintain an investment grade rating from each ofprovide the major credit rating agencies,natural gas needed for generation, referred to as a credit-risk-related contingent feature. If SCE's credit rating were to fall below investment grade, SCE may be required to post additional collateral to cover derivative liabilities and the related outstanding payables. The net fair value of all derivative liabilities with these credit-risk-related contingent features was $4 million and $1 million as of December 31, 2018 and 2017, respectively, for which SCE has posted collateral of $17 million and less than $1 million collateral to its counterparties at the respective dates for its derivative liabilities and related outstanding payables. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2018, SCE would be required to post less than $1 million of additional collateral.tolling arrangements.
Fair Value of Derivative Instruments
SCE presents its derivative assets and liabilities on a net basis on its consolidated balance sheets when subject to master netting agreements or similar agreements. Derivative positions are also offset against margin and cash collateral deposits. In addition, SCE has provided collateral in the form of letters of credit. Collateral requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments and other factors. See Note 4 for a discussion of fair value of derivative instruments. The following table summarizes the gross and net fair values of SCE's commodity derivative instruments:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | |
| | | Derivative Assets | | Derivative Liabilities | | Net Asset |
| (in millions) | | Short-Term | | Long-Term | | Subtotal | | Short-Term | | Long-Term | | Subtotal | |
| Commodity derivative contracts | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 171 |
| | $ | 2 |
| | $ | 173 |
| | $ | 13 |
| | $ | — |
| | $ | 13 |
| | $ | 160 |
|
| Gross amounts offset in the consolidated balance sheets | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Cash collateral posted | | — |
| | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) | | 7 |
|
| Net amounts presented in the consolidated balance sheets | | $ | 171 |
| | $ | 2 |
| | $ | 173 |
| | $ | 6 |
| | $ | — |
| | $ | 6 |
| | $ | 167 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2017 | | |
| | | Derivative Assets | | Derivative Liabilities | | Net Asset |
| (in millions) | | Short-Term | | Long-Term | | Subtotal | | Short-Term | | Long-Term | | Subtotal | |
| Commodity derivative contracts | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 106 |
| | $ | 5 |
| | $ | 111 |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
| | $ | 108 |
|
| Gross amounts offset in the consolidated balance sheets | | (1 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | (1 | ) | | — |
|
| Cash collateral posted | | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) | | 1 |
|
| Net amounts presented in the consolidated balance sheets | | $ | 105 |
| | $ | 5 |
| | $ | 110 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | 109 |
|
Income Statement Impact of Derivative Instruments
SCE recognizes realized gains and losses on derivative instruments as purchased power expense and expects that such gains or losses will be part of the purchased power costs recovered from customers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from customers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings. The remaining effects of derivative activities and related regulatory offsets are reported in cash flows from operating activities in the consolidated statements of cash flows.
The following table summarizes the components of SCE's economic hedging activity:
|
| | | | | | | | | | | | |
| | | Years ended December 31, |
| (in millions) | | 2018 | | 2017 | | 2016 |
| Realized gains (losses) | | $ | 26 |
| | $ | (14 | ) | | $ | (59 | ) |
| Unrealized gains | | 82 |
| | 106 |
| | 84 |
|
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for SCE economic hedging activities:
|
| | | | | |
| | | Economic Hedges |
| | Unit of | December 31, |
| Commodity | Measure | 2018 | | 2017 |
| Electricity options, swaps and forwards | GWh | 2,786 |
| | 475 |
| Natural gas options, swaps and forwards | Bcf | 20 |
| | 143 |
| Congestion revenue rights | GWh | 54,453 |
| | 78,765 |
Note 7. Revenue
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 revenues 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.
The following table is a summary of SCE's revenue:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years ended December 31, |
| | 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 |
Revenues from contracts with customers1,2 | $ | 6,519 |
| $ | 5,611 |
| $ | 12,130 |
| * |
| * |
| * |
| * |
| * |
| * |
|
| Alternative revenue programs and other operating revenue | 41 |
| 440 |
| 481 |
| * |
| * |
| * |
| * |
| * |
| * |
|
| Total operating revenue | $ | 6,560 |
| $ | 6,051 |
| $ | 12,611 |
| $ | 6,611 |
| $ | 5,643 |
| $ | 12,254 |
| $ | 6,504 |
| $ | 5,326 |
| $ | 11,830 |
|
* As discussed in Note 1, prior period amounts have not been adjusted under the modified retrospective method.
| |
1
| During the year ended December 31, 2018, SCE recorded CPUC revenue based on the 2017 authorized revenue requirements adjusted for the July 2017 cost of capital decision and Tax Reform pending the outcome of the 2018 GRC. These revenue adjustments are included in "Revenues from contracts with customers." For further information, see Note 1. |
| |
2
| At December 31, 2018 and 2017, SCE's receivables related to contracts from customers were $1.1 billion and $825 million, respectively, which include accrued unbilled revenue of $482 million and $212 million, respectively. |
SCE's Revenue from Contracts with Customers
Provision of Electricity
SCE principally generates revenue through supplying and delivering electricity to its customers. Rates charged to customers are based on tariff rates, approved by the CPUC and FERC. Revenue is authorized by the CPUC through triennial GRC proceedings which are intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its CPUC-jurisdictional rate base. The CPUC sets an annual revenue requirement for the base year and the remaining two years are set by a methodology established in the GRC proceeding. As described above, SCE also earns revenue, with no return, to recover costs for power procurement and other activities.
Revenue is authorized by the FERC through a formula rate which is intended to provide SCE a reasonable opportunity to recover transmission capital and operating costs that are prudently incurred, including a return on its FERC-jurisdictional rate base. Under the operation of the formula rate, transmission revenue is updated to actual cost of service annually.
For SCE's electricity sales for non-residential customers, SCE satisfies the performance obligation of delivering electricity over time as the customers simultaneously receive and consume the delivered electricity.
Energy sales are typically on a month-to-month implied contract for transmission, distribution and generation services. Revenue is recognized over time as the energy is supplied and delivered to customers and the respective revenue is billed and paid on a monthly basis.
Sales and Use Taxes
SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE's ability to collect from the customer, are accounted for on a gross basis. SCE's franchise fees billed to customers were $133$122 million, $133 million and $111$133 million for the years ended December 31, 2019, 2018 2017 and 2016,2017, respectively. When SCE acts as an agent for sales and use tax, the taxes are accounted for on a net basis. Amounts billed to and collected from customers for these taxes are remitted to the taxing authorities and are not recognized as electric utility revenue.
SCE's Alternative Revenue Programs
The CPUC and FERC have authorized additional, alternative revenue programs which adjustsadjust billings for the effects of broad external factors or compensatescompensate SCE for demand-side management initiatives and providesprovide for incentive awards if SCE achieves certain objectives. These alternative revenue programs allow SCE to recover costs that SCE has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, revenue is recognized for these alternative revenue programs at the time the costs are incurred and, for incentive-based programs, at the time the awards are approved by the CPUC. SCE begins recognizing revenues for these programs when a program has been established by an order from either the CPUC or FERC that allows for automatic adjustment of future rates, the amount of revenue for the period is objectively determinable and probable of recovery and the revenue will be collected within 24 months following the end of the annual period.
Regulatory Proceedings
2018 General Rate Case
In the absence of a 2018 GRC final decision, SCE recognized revenue in 2018 and the first quarter of 2019 based on the 2017 authorized revenue requirement, adjusted for items SCE determined to be probable of occurring, primarily the July 2017 cost of capital decision and the Tax Cuts and Jobs Act ("Tax Reform"). Adjustments were also made to 2017 authorized revenue to reflect changes in authorized tax benefits for certain balancing accounts. See Note 11 for further information.
In May 2019, the CPUC approved a final decision in SCE's 2018 GRC. The final decision authorized a revenue requirement of $5.1 billion for 2018 and identified changes to certain balancing accounts, including the expansion of the TAMA to include the impacts of all differences between forecast and recorded tax expense. The final decision also disallowed certain historical spending, largely related to specific pole replacements the CPUC determined were performed prematurely.
The final decision allows a post-test year rate making mechanism that escalates capital additions by 2.49% for both 2019 and 2020. It also allows operation and maintenance expenses to be escalated for 2019 and 2020 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology set forth in the final decision results in a revenue requirement of $5.5 billion in 2019 and $5.9 billion in 2020.
The revenue requirements in the 2018 GRC final decision are retroactive to January 1, 2018. SCE recorded the prior period impact of the 2018 GRC final decision in 2019 including:
An increase to earnings of $131 million from the application of the decision to revenue, depreciation expense and income tax expense. Depreciation expense decreased as a result of lower authorized depreciation rates. An increase in the authorized revenue requirement for income tax expense offsets income tax expense recognized during 2018 and the first quarter of 2019. The reduction of revenue of $265 million reflected $289 million of lower authorized revenue related to 2018 and $24 million of higher authorized revenue in 2019. The reduction in revenue contributed to a refund to customers of $554 million, which SCE recorded as a regulatory liability. SCE expects to refund these amounts to customers through December 2020.
An impairment of utility property, plant and equipment of $170 million ($123 million after-tax) related to disallowed historical capital expenditures, primarily the write-off of specific pole replacements the CPUC determined were performed prematurely.
2018 and 2019 FERC Formula Rate
In December 2019, the FERC approved a settlement on SCE's formula rates for the 2018 Formula Rate case that established SCE's FERC transmission revenue requirement for January 1, 2018 through November 11, 2019 (the "FERC 2018 Settlement Period"). Prior to the settlement, SCE had been recognizing revenue during the FERC 2018 Settlement Period based on its expectations of the probable outcome of the 2018 Formula Rate case. Regulatory assets and liabilities were adjusted based on the settlement of the 2018 Formula Rate case, which resulted in an increase in net income of $29 million related to 2018, being recorded in 2019. The 2019 Formula Rate remains subject to hearing and settlement procedures and amounts billed to customers under the 2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved. Pending resolution of the 2019 Formula Rate case, SCE is recognizing revenue based on the return on equity established in the 2020 Cost of Capital decision of the CPUC.
Power Purchase Agreements
SCE enters into power purchase agreements ("PPAs") in the normal course of business. A power purchase agreement may be considered a variable interest in a variable interest entity ("VIE"). If SCE is the primary beneficiary in the VIE, SCE should consolidate the VIE. None of SCE's PPAs resulted in consolidation of a VIE at December 31, 2019 and 2018. See Note 3 for further discussion of PPAs that are considered variable interests.
A PPA may also contain a lease for accounting purposes. See "Leases" below and Note 12 and Note 13 for further discussion of SCE's PPAs, including agreements that are classified as operating and finance leases for accounting purposes.
A PPA that does not contain a lease may be classified as a derivative which is recorded at fair value on the consolidated balance sheets. These PPAs may be eligible for an election to designate as a normal purchase and sale, which is accounted for on an accrual basis as an executory contract. See Note 6 for further information on derivative instruments.
PPAs that do not meet the above classifications are accounted for on an accrual basis.
Derivative Instruments
SCE records derivative instruments on its consolidated balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as normal purchases or sales. The normal purchases and sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business.
Realized gains and losses from SCE's derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no impact on purchased power expense or earnings. SCE does not use hedge accounting for derivative transactions due to regulatory accounting treatment.
Where SCE's derivative instruments are subject to a master netting agreement and certain criteria are met, SCE presents its derivative assets and liabilities on a net basis on its consolidated balance sheets. In addition, derivative positions are offset against margin and cash collateral deposits. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. See Note 6 for further information on derivative instruments.
Leases
A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified assets for a period of time in exchange for consideration. An entity controls the use when it has a right to obtain substantially all of the benefits from the use of the identified asset and has the right to direct the use of the asset. SCE determines if an arrangement is a lease at contract inception. For all classes of underlying assets, SCE includes both the lease and non-lease components as a single component and accounts for it as a lease. Lease liabilities are recognized based on the present value of the lease payments over the lease term at the commencement date. SCE calculates and uses the rate implicit in the lease if the information is readily available or if not available, SCE uses its incremental borrowing rate in determining the present value of lease payments. Incremental borrowing rates are comprised of underlying risk-free rates and secured credit spreads relative to first mortgage bonds with like tenors of lease term durations. Lease right-of-use ("ROU") assets are based on the liability, subject to adjustments, such as lease incentives. The ROU assets also include any lease payments made at or before the commencement date. SCE excludes variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. SCE's lease terms include options to extend or terminate the lease when it is reasonably certain that such options will be exercised. Operating leases are included in "Operating lease right-of-use assets," "Current portion of operating lease liabilities" and "Operating lease liabilities" on the consolidated balance sheets. Finance leases are included in "Utility property, plant and equipment," "Other current liabilities" and "Other deferred credits and other long-term liabilities" on the consolidated balance sheets.
SCE enters into power purchase agreements that may contain leases. This occurs when a power purchase agreement designates a specific power plant, SCE obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. Leases that commenced before January 1, 2019 were not reassessed as SCE elected the package of practical expedients (see "Accounting Guidance Adopted" below for more information). Prior to January 1, 2019, a power purchase agreement contained a lease when SCE purchased substantially all of the output from a specific plant and did not otherwise meet a fixed price per unit of output exception. SCE also enters into a number of agreements to lease property and equipment in the normal course of business, primarily related to vehicles, office space and other equipment. See Note 13 for further discussion of SCE's contracts that are classified as operating and finance leases.
Edison International Parent and Other's leases primarily relate to Edison Energy Group. The leases for Edison International Parent and Other are immaterial to Edison International.
Stock-Based Compensation
Stock options, performance shares, deferred stock units and restricted stock units have been granted under Edison International's long-term incentive compensation programs. For equity awards that are settled in common stock, Edison International either issues new common stock, or uses a third party to purchase shares from the market and deliver such shares for the settlement of the awards. The performance shares granted during 2017 to 2018 that are earned, have been or will be settled solely in cash. The performance shares granted in 2019 that are earned, will be settled in common stock. Stock options, deferred stock units and restricted stock units are settled in common stock. However, for awards that are otherwise settled entirely in common stock, Edison International substitutes cash awards to the extent necessary to satisfy applicable tax withholding obligations or government levies.
Stock-based compensation expense is recognized, net of estimated forfeitures, on a straight-line basis over the requisite service period based on estimated fair values. For equity awards paid in common stock, fair value is determined at the grant date. However, with respect to the portion of the performance shares payable in common stock that are subject to market and financial performance conditions defined in the grants, the number of performance shares expected to be earned is subject to revision and updated at each reporting period, with a related adjustment to compensation expense. Awards paid in cash are classified as share-based liability awards and fair value is remeasured at each reporting date with the related compensation cost adjusted. For awards granted to retirement-eligible participants, stock compensation expense is recognized on a prorated basis over the initial year. For awards granted to participants who become eligible for retirement during the requisite service period, stock compensation expense is recognized over the period between the date of grant and the date the participant first becomes eligible for retirement. Edison International and SCE estimate the number of awards that are expected to vest rather than account for forfeitures when they occur. Share-based payments may create a permanent difference between the amount of compensation expense recognized for book and tax purposes. The tax impact of this permanent difference is recognized in earnings in the period it is created. See Note 9 for further information.
SCE Dividends
CPUC holding company rules require that SCE's dividend policy be established by SCE's Board of Directors on the same basis as if SCE were a stand-alone utility company, and that the capital requirements of SCE, as deemed to be necessary to meet SCE's electricity service obligations, shall receive first priority from the Boards of Directors of both Edison International and SCE. In addition, the CPUC regulates SCE's capital structure which limits the dividends it may pay to its shareholders.
Prior to January 1, 2020, under SCE's interpretation of CPUC regulations and capital structure decisions, the common equity component of SCE's capital structure was required to remain at or above 48% on a weighted average basis over the 37-month period that SCE's capital structure was in effect for ratemaking purposes and SCE was required to file an application for a waiver of the 48% equity ratio condition discussed above if an adverse financial event reduces its spot equity ratio below 47%. Effective January 1, 2020, the common equity component of SCE's authorized capital structure was increased from 48% to 52%. Under AB 1054, the impact of SCE's contributions to the Wildfire Insurance Fund are excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. For further information, see Note 12.
On February 28, 2019, SCE submitted an application to the CPUC for waiver of compliance with this equity ratio requirement, describing that while the charge accrued in connection with the 2017/2018 Wildfire/Mudslide Events caused its equity ratio to fall below 47% on a spot basis as of December 31, 2018, SCE remains in compliance with the 48% equity ratio over the applicable 37-month average basis. In its application, SCE requested a limited waiver to exclude wildfire-related charges and wildfire-related debt issuances from its equity ratio calculations until a determination regarding cost recovery is made. The CPUC has ruled that while the application is pending resolution, SCE must notify the CPUC if an adverse financial event reduces SCE's spot equity ratio by more than one percent from the level most recently filed with the CPUC in the proceeding. The last spot equity ratio SCE filed with the CPUC in the proceeding was 45.2% as of December 31, 2018. Under the CPUC's rules, SCE will not be deemed to be in violation of the equity ratio requirement, and therefore may continue to issue debt and dividends, while the waiver application is pending resolution. For further information, see Note 12. At December 31, 2019, without excluding the $2.0 billion after-tax wildfire-related charges incurred in 2018 and 2019, SCE's 37-month average common equity component of total capitalization was 48.5% and the maximum additional dividend that SCE could pay to Edison International under this limitation was $179 million, resulting in a restriction on net assets of approximately $17.6 billion. If the wildfire-related charges were excluded at December 31, 2019, SCE's 37-month average common equity component of total capitalization would have been 49.6%.
As a California corporation, SCE's ability to pay dividends is also governed by the California General Corporation Law. California law requires that for a dividend to be declared: (a) retained earnings must equal or exceed the proposed dividend, or (b) immediately after the dividend is made, the value of the corporation's assets must exceed the value of its liabilities plus amounts required to be paid, if any, in order to liquidate stock senior to the shares receiving the dividend. Additionally, a California corporation may not declare a dividend if it is, or as a result of the dividend would be, likely to be unable to meet its liabilities as they mature. Prior to declaring dividends, SCE's Board of Directors evaluates available information, including when applicable, information pertaining to the 2017/2018 Wildfire/Mudslide Events, to ensure that the California law requirements for the declarations are met. On February 27, 2020, SCE declared a dividend to Edison International of $269 million.
The timing and amount of future dividends are also dependent on a number of other factors including SCE's requirements to fund other obligations and capital expenditures, its ability to access the capital markets, and generate operating cash flows and earnings. If SCE incurs significant costs related to catastrophic wildfires, including the 2017/2018 Wildfire/Mudslide Events, and is unable to recover such costs through insurance, the Wildfire Insurance Fund (for fires after July 12, 2019), or from customers or access capital markets on reasonable terms, SCE may be limited in its ability to pay future dividends to Edison International and its preferred and preference shareholders.
Earnings Per Share
Edison International computes earnings per common share ("EPS") using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's participating securities are stock-based compensation awards, payable in common shares, which earn dividend equivalents on an equal basis with common shares once the awards are vested. See Note 9 and Note 14 for further information.
EPS attributable to Edison International common shareholders was computed as follows:
|
| | | | | | | | | | | |
| | Years ended December 31, |
| (in millions, except per share amounts) | 2019 | | 2018 | | 2017 |
| Basic earnings (loss) per share – continuing operations: | | | | | |
| Income (loss) from continuing operations attributable to common shareholders | $ | 1,284 |
| | $ | (457 | ) | | $ | 565 |
|
| Participating securities dividends | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Weighted average common shares outstanding | 340 |
| | 326 |
| | 326 |
|
| Basic earnings (loss) per share – continuing operations | 3.78 |
| | (1.40 | ) | | 1.73 |
|
| Diluted earnings (loss) per share – continuing operations: | | | | | |
| Income (loss) from continuing operations attributable to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Participating securities dividends | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders | 1,284 |
| | (457 | ) | | 565 |
|
| Income impact of assumed conversions | — |
| | — |
| | — |
|
| Income (loss) from continuing operations available to common shareholders and assumed conversions | 1,284 |
| | (457 | ) | | 565 |
|
| Weighted average common shares outstanding | 340 |
| | 326 |
| | 326 |
|
Incremental shares from assumed conversions1 | 1 |
| | — |
| | 2 |
|
| Adjusted weighted average shares – diluted | 341 |
| | 326 |
| | 328 |
|
| Diluted earnings (loss) per share – continuing operations | $ | 3.77 |
| | $ | (1.40 | ) | | $ | 1.72 |
|
| |
1 | Due to the loss reported for the year ended December 31, 2018, incremental shares were not included as the effect would be antidilutive. |
In addition to the participating securities discussed above, Edison International also may award stock options, which are payable in common shares and are included in the diluted earnings per share calculation. Stock option awards to purchase 4,511,802, 8,852,706 and 1,334,451 shares of common stock for the years ended December 31, 2019, 2018 and 2017, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the effect would have been antidilutive.
Income Taxes
Edison International and SCE estimate their income taxes for each jurisdiction in which they operate. This involves estimating current period tax expense along 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 in the consolidated balance sheets. 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% which resulted in the re-measurement of deferred taxes using the new tax rate. See Note 8 for further information.
Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Interest income, interest expense and penalties associated with income taxes are reflected in "Income tax expense" on the consolidated statements of income.
Edison International's eligible subsidiaries are included in Edison International's consolidated federal income tax and combined state tax returns. Edison International has tax-allocation and payment agreements with certain of its subsidiaries. Pursuant to an income tax-allocation agreement approved by the CPUC, SCE's tax liability is computed as if it filed its federal and state income tax returns on a separate return basis.
New Accounting Guidance
Accounting Guidance Adopted
On January 1, 2019, Edison International and SCE adopted accounting standards updates that require lessees to recognize a lease on the balance sheet as a ROU asset and related lease liability and classify the lease as either operating or finance. Edison International and SCE adopted this guidance using the modified retrospective approach for leases that existed as of the adoption date and elected the optional transition method not to restate periods prior to the adoption date. Edison International and SCE also elected the package of practical expedients not to reassess prior conclusions related to contracts containing leases, lease classification and initial direct costs, and the practical expedient not to reassess existing land easements. Adoption of this standard increased ROU assets and lease liabilities on the consolidated balance sheets by $956 million and $951 million as of January 1, 2019 for Edison International and SCE, respectively. The standard did not materially impact the consolidated statements of income for Edison International or SCE. See "Leases" above and Note 13 for further information.
In February 2018, the Financial Accounting Standards Board ("FASB") issued an accounting standards update to provide entities an election to reclassify stranded tax effects resulting from Tax Reform from accumulated other comprehensive income to retained earnings. Stranded tax effects originated in December 2017 when deferred taxes were re-measured at the lower federal corporate tax rate with the impact included in operating income, while the tax effects of items within accumulated other comprehensive income were not similarly adjusted. Edison International and SCE adopted this guidance on January 1, 2019 and reclassified stranded tax effects of $10 million and $5 million, respectively, from accumulated other comprehensive loss to retained earnings. See Note 15 for further information.
In August 2018, the FASB issued an accounting standards update to remove, modify, and add certain disclosure requirements related to fair value measurement. Edison International and SCE adopted this guidance effective January 1, 2019. The adoption of this guidance did not have a material impact on Edison International's and SCE's disclosures. See Note 4 for further information.
Accounting Guidance Not Yet Adopted
In June 2016, the FASB issued an accounting standards update to require the use of the current expected credit loss model to measure impairment of financial instruments and the use of an allowance to record estimated credit losses on available-for-sale debt securities. The guidance, as later amended, allows entities to irrevocably elect the fair value option for any financial instrument previously measured on an amortized costs basis. Edison International and SCE do not believe the adoption of the standard will have a material impact on financial position or results of operations. Edison International and SCE will apply a prospective adoption approach to available-for-sale debt securities and a modified retrospective approach to all other financial assets. Edison International and SCE will not elect the fair value option. Edison International and SCE will adopt this guidance effective January 1, 2020.
In January 2017, the FASB issued an accounting standards update to simplify the accounting for goodwill impairment by changing the procedural steps to apply the goodwill impairment test. After the adoption of this accounting standards update, goodwill impairment will be measured as the amount by which a reporting unit's carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. Edison International will apply this guidance to goodwill impairment tests beginning in 2020.
In August 2018, the FASB issued an accounting standards update which aligns the requirement for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs incurred to develop or obtain internal use software. The guidance also clarified presentation requirements for reporting implementation costs in the financial statements. Edison International and SCE do not believe the adoption of the standard will have a material impact on financial position or results of operations and will apply this guidance prospectively, effective January 1, 2020.
In August 2018, the FASB issued an accounting standards update to remove, modify, and add certain disclosure requirements related to employer-sponsored defined benefit pension or other postretirement plans. The guidance is effective January 1, 2021 with early adoption permitted. Edison International and SCE are currently evaluating the impact of the guidance and do not expect the adoption of this standard will materially affect disclosures.
Note 2. Property, Plant and Equipment
SCE's property, plant and equipment included in the consolidated balance sheets is composed of the following:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Distribution | $ | 26,929 |
| | $ | 25,026 |
|
| Transmission | 14,720 |
| | 13,800 |
|
| Generation | 3,664 |
| | 3,598 |
|
| General plant and other | 4,583 |
| | 4,398 |
|
| Accumulated depreciation | (9,958 | ) | | (9,566 | ) |
| | 39,938 |
| | 37,256 |
|
| Construction work in progress | 4,131 |
| | 3,883 |
|
| Nuclear fuel, at amortized cost | 129 |
| | 130 |
|
| Total utility property, plant and equipment | $ | 44,198 |
| | $ | 41,269 |
|
Capitalized Software Costs
SCE capitalizes costs incurred during the application development stage of internal use software projects to property, plant and equipment. SCE amortizes capitalized software costs ratably over the expected lives of the software, primarily ranging from 5 to 7 years and commencing upon operational use. Capitalized software costs, included in general plant and other above, were $1.0 billion and $1.0 billion at December 31, 2019 and 2018, respectively, and accumulated amortization was $0.4 billion and $0.5 billion, at December 31, 2019 and 2018, respectively. Amortization expense for capitalized software was $190 million, $198 million and $233 million in 2019, 2018 and 2017, respectively. At December 31, 2019, amortization expense is estimated to be $191 million, $163 million, $116 million, $76 million and $27 million for 2020 through 2024, respectively.
Jointly Owned Utility Projects
SCE owns undivided interests in transmission and generating assets for which each participant provides its own financing. SCE's proportionate share of these assets is reflected in the consolidated balance sheets and included in the above table. SCE's proportionate share of expenses for each project is reflected in the consolidated statements of income.
The following is SCE's investment in each asset as of December 31, 2019:
|
| | | | | | | | | | | | | | | | | |
| (in millions) | Plant in Service | Construction Work in Progress | Accumulated Depreciation | Nuclear Fuel (at amortized cost) | Net Book Value | Ownership Interest |
| Transmission systems: | | | | | | |
| Eldorado | $ | 257 |
| $ | 94 |
| $ | 35 |
| $ | — |
| $ | 316 |
| 80 | % |
| Pacific Intertie | 248 |
| 80 |
| 72 |
| — |
| 256 |
| 50 | % |
| Generating station: | | | | | | |
| Palo Verde (nuclear) | 2,065 |
| 61 |
| 1,586 |
| 129 |
| 669 |
| 16 | % |
| Total | $ | 2,570 |
| $ | 235 |
| $ | 1,693 |
| $ | 129 |
| $ | 1,241 |
| |
In addition, SCE has ownership interests in jointly owned power poles with other companies.
Note 3. Variable Interest Entities
A VIE is defined as a legal entity that meets one of two conditions: (1) the equity owners do not have sufficient equity at risk, or (2) the holders of the equity investment at risk, as a group, lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that most significantly impact the economic performance of such VIEs. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
Variable Interest in VIEs that are not Consolidated
Power Purchase Agreements
SCE has PPAs that are classified as variable interests in VIEs, including tolling agreements through which SCE provides the natural gas to fuel the plants and contracts with qualifying facilities ("QF") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. Since payments for capacity are the primary source of income, the most significant economic activity for these VIEs is the operation and maintenance of the power plants.
As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to involvement with VIEs result from amounts due under the PPAs. Under these contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 12. As a result, there is no significant potential exposure to loss to SCE from its variable interest in these VIEs. The aggregate contracted capacity dedicated to SCE from these VIE projects was 4,497 megawatts ("MW") and 3,602 MW at December 31, 2019 and 2018, respectively, and the amounts that SCE paid to these projects were $833 million and $762 million for the years ended December 31, 2019 and 2018, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.
Unconsolidated Trusts of SCE
SCE Trust II, Trust III, Trust IV, Trust V and Trust VI were formed in 2013, 2014, 2015, 2016 and 2017, respectively, for the exclusive purpose of issuing the 5.10%, 5.75%, 5.375%, 5.45% and 5.00% trust preference securities, respectively ("trust securities"). The trusts are VIEs. SCE has concluded that it is not the primary beneficiary of these VIEs as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trusts. SCE Trust II, Trust III, Trust IV, Trust V and Trust VI issued to the public trust securities in the face amounts of $400 million, $275 million, $325 million, $300 million and $475 million (cumulative, liquidation amounts of $25 per share), respectively, and $10,000 of common stock each to SCE. The trusts invested the proceeds of these trust securities in Series G, Series H, Series J, Series K and Series L Preference Stock issued by SCE in the principal amounts of $400 million, $275 million, $325 million, $300 million and $475 million (cumulative, $2,500 per share liquidation values), respectively, which have substantially the same payment terms as the respective trust securities.
The Series G, Series H, Series J, Series K and Series L Preference Stock and the corresponding trust securities do not have a maturity date. Upon any redemption of any shares of the Series G, Series H, Series J, Series K or Series L Preference Stock, a corresponding dollar amount of trust securities will be redeemed by the applicable trust (see Note 14 for further information). The applicable trust will make distributions at the same rate and on the same dates on the applicable series of trust securities if and when the SCE board of directors declares and makes dividend payments on the related Preference Stock. The applicable trust will use any dividends it receives on the related Preference Stock to make its corresponding distributions on the applicable series of trust securities. If SCE does not make a dividend payment to any of these trusts, SCE would be prohibited from paying dividends on its common stock. SCE has fully and unconditionally guaranteed the payment of the trust securities and trust distributions, if and when SCE pays dividends on the related Preference Stock.
SCE formed Trust I, a VIE, in 2012 for the exclusive purpose of issuing 5.625% trust preference securities. SCE Trust I issued trust securities in the face amounts of $475 million to the public and $10,000 of common stock to SCE. SCE Trust I invested the proceeds of these trust securities in Series F Preference Stock issued by SCE in the principal amount of $475 million. In July 2017, all of the outstanding Series F Preference Stock was redeemed, and accordingly, SCE Trust I
redeemed $475 million of trust securities from the public and $10,000 of common stock from SCE. As a result in September 2017, SCE Trust I was terminated.
The Trust II, Trust III, Trust IV, Trust V and Trust VI balance sheets as of December 31, 2019 and 2018, consisted of investments of $400 million, $275 million, $325 million, $300 million and $475 million in the Series G, Series H, Series J, Series K and Series L Preference Stock, respectively, $400 million, $275 million, $325 million, $300 million and $475 million of trust securities, respectively, and $10,000 each of common stock.
The followingtable provides a summary of the trusts' income statements:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Years ended December 31, |
| (in millions) | Trust I | | Trust II | | Trust III | | Trust IV | | Trust V | | Trust VI |
| 2019 | | | | | | | | | | | |
| Dividend income | * |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 24 |
|
| Dividend distributions | * |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 24 |
|
| 2018 | | | | | | | | | | | |
| Dividend income | * |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 24 |
|
| Dividend distributions | * |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 24 |
|
| 2017 | | | | | | | | | | | |
| Dividend income | $ | 14 |
| | $ | 20 |
| | $ | 16 |
| | $ | 17 |
| | $ | 16 |
| | $ | 12 |
|
| Dividend distributions | 14 |
| | 20 |
| | 16 |
| | 17 |
| | 16 |
| | 12 |
|
* Not applicable
Note 4. Fair Value Measurements
Recurring Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or liability considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. As of December 31, 2019 and 2018, nonperformance risk was not material for Edison International and SCE.
Assets and liabilities are categorized into a three-level fair value hierarchy based on valuation inputs used to determine fair value.
Level 1 – The fair value of Edison International's and SCE's Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded equity securities, U.S. treasury securities, mutual funds and money market funds.
Level 2 – Edison International's and SCE's Level 2 assets and liabilities include fixed income securities, primarily consisting of U.S. government and agency bonds, municipal bonds and corporate bonds, and over-the-counter derivatives. The fair value of fixed income securities is determined using a market approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument.
The fair value of SCE's over-the-counter derivative contracts is determined using an income approach. SCE uses standard pricing models to determine the net present value of estimated future cash flows. Inputs to the pricing models include forward published or posted clearing prices from an exchange (Intercontinental Exchange) for similar instruments and discount rates. A primary price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity.
Level 3 – The fair value of SCE's Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes derivative contracts that trade infrequently such as congestion revenue rights ("CRRs"). Edison International Parent and Other does not have any Level 3 assets and liabilities.
Assumptions are made in order to value derivative contracts in which observable inputs are not available. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs, and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts. See Note 6 for a discussion of derivative instruments.
SCE
The following table sets forth assets and liabilities of SCE that were accounted for at fair value by level within the fair value hierarchy:
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2019 |
| (in millions) | Level 1 | | Level 2 | | Level 3 | | Netting and Collateral1 | | Total |
| Assets at fair value | | | | | | | | | |
| Derivative contracts | $ | — |
| | $ | 19 |
| | $ | 83 |
| | $ | (15 | ) | | $ | 87 |
|
| Other | 4 |
| | 14 |
| | — |
| | — |
| | 18 |
|
| Nuclear decommissioning trusts: | | | | | | | | | |
Stocks2 | 1,765 |
| | — |
| | — |
| | — |
| | 1,765 |
|
Fixed Income3 | 738 |
| | 2,024 |
| | — |
| | — |
| | 2,762 |
|
| Short-term investments, primarily cash equivalents | 98 |
| | 48 |
| | — |
| | — |
| | 146 |
|
Subtotal of nuclear decommissioning trusts4 | 2,601 |
| | 2,072 |
| | — |
| | — |
| | 4,673 |
|
| Total assets | 2,605 |
| | 2,105 |
| | 83 |
| | (15 | ) | | 4,778 |
|
| Liabilities at fair value | | | | | | | | | |
| Derivative contracts | — |
| | 11 |
| | 5 |
| | (15 | ) | | 1 |
|
| Total liabilities | — |
| | 11 |
| | 5 |
| | (15 | ) | | 1 |
|
| Net assets | $ | 2,605 |
| | $ | 2,094 |
| | $ | 78 |
| | $ | — |
| | $ | 4,777 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 |
| (in millions) | Level 1 | | Level 2 | | Level 3 | | Netting and Collateral1 | | Total |
| Assets at fair value | | | | | | | | | |
|
| Derivative contracts | $ | — |
| | $ | 32 |
| | $ | 141 |
| | $ | — |
| | $ | 173 |
|
| Other | 9 |
| | 21 |
| | — |
| | — |
| | 30 |
|
| Nuclear decommissioning trusts: | | | | | | | | | |
Stocks2 | 1,382 |
| | — |
| | — |
| | — |
| | 1,382 |
|
Fixed Income3 | 1,001 |
| | 1,665 |
| | — |
| | — |
| | 2,666 |
|
| Short-term investments, primarily cash equivalents | 120 |
| | 95 |
| | — |
| | — |
| | 215 |
|
Subtotal of nuclear decommissioning trusts4 | 2,503 |
| | 1,760 |
| | — |
| | — |
| | 4,263 |
|
| Total assets | 2,512 |
| | 1,813 |
| | 141 |
| | — |
| | 4,466 |
|
| Liabilities at fair value | | | | | | | | | |
| Derivative contracts | — |
| | 13 |
| | — |
| | (7 | ) | | 6 |
|
| Total liabilities | — |
| | 13 |
| | — |
| | (7 | ) | | 6 |
|
| Net assets | $ | 2,512 |
| | $ | 1,800 |
| | $ | 141 |
| | $ | 7 |
| | $ | 4,460 |
|
| |
1 | Represents the netting of assets and liabilities under master netting agreements and cash collateral. |
| |
2 | Approximately 72% and 71% of SCE's equity investments were located in the United States at December 31, 2019 and 2018, respectively. |
| |
3 | Includes corporate bonds, which were diversified and included collateralized mortgage obligations and other asset backed securities of $46 million and $67 million at December 31, 2019 and 2018, respectively. |
| |
4 | Excludes net payables of $111 million and $143 million at December 31, 2019 and 2018, respectively, which consist of interest and dividend receivables as well as receivables and payables related to SCE's pending securities sales and purchases. |
Edison International Parent and Other
Edison International Parent and Other assets measured at fair value consisted of money market funds of $31 million and $115 million at December 31, 2019 and 2018, respectively, classified as Level 1.
SCE Fair Value of Level 3
The following table sets forth a summary of changes in SCE's fair value of Level 3 net derivative assets and liabilities:
|
| | | | | | | | |
| | | December 31, |
| (in millions) | | 2019 | | 2018 |
| Fair value of net assets at beginning of period | | $ | 141 |
| | $ | 101 |
|
| Total realized/unrealized (losses) gains: | | | | |
Included in regulatory assets and liabilities1 | | (63 | ) | | 40 |
|
Fair value of net assets at end of period2 | | 78 |
| | 141 |
|
| Change during the period in unrealized gains and losses related to assets and liabilities held at the end of the period | | $ | 62 |
| | $ | 138 |
|
| |
1 | Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities. |
| |
2 | There were no material transfers into or out of Level 3 during 2019 and 2018. |
The following table sets forth SCE's valuation techniques and significant unobservable inputs used to determine fair value for significant Level 3 assets and liabilities:
|
| | | | | | | | | | | |
| | Fair Value (in millions) | | Significant | Range | Weighted Average |
| | Assets | | Liabilities | Valuation Technique | Unobservable Input |
| Congestion revenue rights | | | | |
| December 31, 2019 | $ | 83 |
| | $ | 5 |
| Auction prices | CAISO CRR auction clearing prices | $(3.59) - $25.32 | $1.97 |
| December 31, 2018 | 141 |
| | — |
| Auction prices | CAISO CRR auction clearing prices | $(7.41) - $41.52 | $1.62 |
Level 3 Fair Value Uncertainty
For CRRs, increases or decreases in CAISO auction price would result in higher or lower fair value, respectively.
Nuclear Decommissioning Trusts
SCE's nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information. There are no securities classified as Level 3 in the nuclear decommissioning trusts.
SCE's investment policies and CPUC requirements place limitations on the types and investment grade ratings of the securities that may be held by the nuclear decommissioning trust funds. These policies restrict the trust funds from holding alternative investments and limit the trust funds' exposures to investments in highly illiquid markets. With respect to equity and fixed income securities, the trustee obtains prices from third-party pricing services which SCE is able to independently corroborate as described below. The trustee monitors prices supplied by pricing services, including reviewing prices against defined parameters' tolerances and performs research and resolves variances beyond the set parameters. SCE corroborates the fair values of securities by comparison to other market-based price sources obtained by SCE's investment managers. Differences outside established thresholds are followed-up with the trustee and resolved. For each reporting period, SCE reviews the trustee determined fair value hierarchy and overrides the trustee level classification when appropriate.
Nonrecurring Fair Value Measurements
Edison International assesses goodwill at the reporting unit level. The fair value of the Edison Energy reporting unit is classified as Level 3 and is estimated using the income approach. During the fourth quarter of 2019 and 2018, Edison International evaluated the recoverability of goodwill and recorded impairment charges of Edison Energy's goodwill totaling $25 million ($18 million after-tax) and $19 million ($13 million after-tax), respectively. See Note 1 for further details.
Fair Value of Debt Recorded at Carrying Value
The carrying value and fair value of Edison International's and SCE's long-term debt (including current portion of long-term debt) are as follows:
|
| | | | | | | | | | | | | | | |
| | December 31, 2019 | | December 31, 2018 |
| (in millions) | Carrying Value1 | | Fair Value2 | | Carrying Value1 | | Fair Value2 |
| Edison International | $ | 18,343 |
| | $ | 20,137 |
| | $ | 14,711 |
| | $ | 14,844 |
|
| SCE | 15,211 |
| | 16,892 |
| | 12,971 |
| | 13,180 |
|
| |
1 | Carrying value is net of debt issuance costs. |
| |
2 | The fair value of Edison International's and SCE's long-term debt is classified as Level 2. |
Note 5. Debt and Credit Agreements
Long-Term Debt
The following table summarizes long-term debt (rates and terms are as of December 31, 2019) of Edison International and SCE:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Edison International Parent and Other: | | | |
| Debentures and notes: | | | |
| 2020 – 2028 (2.125% to 5.750%) | $ | 3,150 |
| | $ | 1,750 |
|
| Current portion of long-term debt | (400 | ) | | — |
|
| Unamortized debt discount/premium and issuance costs, net | (18 | ) | | (10 | ) |
| Total Edison International Parent and Other | 2,732 |
| | 1,740 |
|
| SCE: | | | |
| First and refunding mortgage bonds: | | | |
| 2021 – 2049 (1.845% to 6.05%) | 14,272 |
| | 12,050 |
|
| Pollution-control bonds: | | | |
| 2028 – 2035 (1.875% to 5.00%) | 752 |
| | 752 |
|
| Debentures and notes: | | | |
| 2029 – 2053 (5.06% to 6.65%) | 306 |
| | 306 |
|
| Current portion of long-term debt | (79 | ) | | (79 | ) |
| Unamortized debt discount/premium and issuance costs, net | (119 | ) | | (137 | ) |
| Total SCE | 15,132 |
| | 12,892 |
|
| Total Edison International | $ | 17,864 |
| | $ | 14,632 |
|
Edison International and SCE long-term debt maturities over the next five years are as follows:
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
| 2020 | $ | 479 |
| | $ | 79 |
|
| 2021 | 1,029 |
| | 1,029 |
|
| 2022 | 1,064 |
| | 364 |
|
| 2023 | 1,300 |
| | 900 |
|
| 2024 | 500 |
| | — |
|
Liens and Security Interests
Almost all of SCE's properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage bonds as collateral for borrowed funds obtained from pollution-control bonds issued by government agencies. SCE has a debt covenant that requires a debt to total capitalization ratio to be less than or equal to 0.65 to 1. At December 31, 2019, SCE was in compliance with this debt covenant and all other financial covenants that affect access to capital.
Credit Agreements and Short-Term Debt
The following table summarizes the status of the credit facilities at December 31, 2019:
|
| | | | | | | |
| (in millions) | Edison International Parent | | SCE |
| Commitment | $ | 1,500 |
| | $ | 3,000 |
|
| Outstanding borrowings (excluding discount) | — |
| | (550 | ) |
| Outstanding letters of credit | — |
| | (152 | ) |
| Amount available | $ | 1,500 |
| | $ | 2,298 |
|
In February 2019, SCE borrowed $750 million under a Term Loan Agreement due in February 2020 ("February 2019 SCE Term Loan"), with a variable interest rate based on the London Interbank Offered Rate plus 70 basis points. The proceeds were used to repay SCE's commercial paper borrowings and for general corporate purposes. As noted below, the February 2019 SCE Term Loan was fully repaid in April 2019.
In April 2019, Edison International Parent borrowed $1.0 billion under a Term Loan Agreement due in April 2020 ("April 2019 Edison International Parent Term Loan"), with a variable interest rate based on the London Interbank Offered Rate plus 90 basis points. Of the proceeds, $750 million was contributed to SCE and SCE used this contribution to repay the February 2019 SCE Term Loan as discussed above. The remainder of the proceeds were used for general corporate and working capital purposes. The April 2019 Edison International Parent Term Loan was fully repaid in December 2019.
In June 2019, SCE and Edison International Parent amended the maturity date of their multi-year revolving credit facilities of
$3.0 billion and $1.5 billion, respectively. The facilities now mature in May 2024, with an option to extend for an additional
year, which may be exercised upon agreement between SCE or Edison International Parent and their respective lenders.
SCE's credit facility is generally used to support commercial paper borrowings and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working
capital requirements to support operations and capital expenditures. Edison International Parent's credit facility is used to
support commercial paper borrowings and for general corporate purposes.
At December 31, 2019, SCE's commercial paper, net of discount, was $550 million at a weighted average interest rate of 2.24%. At December 31, 2019, letters of credit issued under SCE's credit facility aggregated $152 million and are scheduled to expire in twelve months or less. At December 31, 2018, the outstanding commercial paper, net of discount, was $720 million at a weighted average interest rate of 3.23%.
At December 31, 2019 and December 31, 2018, Edison International Parent had 0 outstanding commercial paper.
Debt Financing Subsequent to December 31, 2019
In January 2020, SCE issued $100 million of 2.85% first and refunding mortgage bonds due in 2029 and $500 million of 3.65% first and refunding mortgage bonds due in 2050. The proceeds were primarily used to repay SCE's commercial
paper borrowings.
Note 6. Derivative Instruments
Derivative financial instruments are used to manage exposure to commodity price risk. These risks are managed in part by entering into forward commodity transactions, including options, swaps and futures. To mitigate credit risk from counterparties in the event of nonperformance, master netting agreements are used whenever possible and counterparties may be required to pledge collateral depending on the creditworthiness of each counterparty and the risk associated with the transaction.
Commodity Price Risk
Commodity price risk represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's electricity price exposure arises from energy purchased from and sold to wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities and PPAs. SCE's natural gas price exposure arises from natural gas purchased for the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and PPAs in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.
Credit and Default Risk
Credit and default risk represent the potential impact that can be caused if a counterparty were to default on its contractual obligations and SCE would be exposed to spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to the sales of excess power and realized gains on derivative instruments.
Certain power and gas contracts contain master netting agreements or similar agreements, which generally allow counterparties subject to the agreement to offset amounts when certain criteria are met, such as in the event of default. The objective of netting is to reduce credit exposure. Additionally, to reduce SCE's risk exposures counterparties may be required to pledge collateral depending on the creditworthiness of each counterparty and the risk associated with the transaction.
Certain power and gas contracts contain a provision that requires SCE to maintain an investment grade rating from each of the major credit rating agencies, referred to as a credit-risk-related contingent feature. If SCE's credit rating were to fall below investment grade, SCE may be required to post additional collateral to cover derivative liabilities and the related outstanding payables. The net fair value of all derivative liabilities with these credit-risk-related contingent features was $1 million and $4 million as of December 31, 2019 and 2018, respectively, for which SCE has posted 0 collateral and $17 million collateral to its counterparties at the respective dates for its derivative liabilities and related outstanding payables. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2019, SCE would be required to post $2 million of additional collateral of which $1 million is related to outstanding payables.
Fair Value of Derivative Instruments
SCE presents its derivative assets and liabilities on a net basis on its consolidated balance sheets when subject to master netting agreements or similar agreements. Derivative positions are also offset against margin and cash collateral deposits. In addition, SCE has provided collateral in the form of letters of credit. Collateral requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments and other factors. See Note 4 for a discussion of fair value of derivative instruments. The following table summarizes the gross and net fair values of SCE's commodity derivative instruments:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2019 | | |
| | | Derivative Assets | | Derivative Liabilities | | Net Asset |
| (in millions) | | Short-Term | | Long-Term1 | | Subtotal | | Short-Term | | Long-Term | | Subtotal | |
| Commodity derivative contracts | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 94 |
| | $ | 8 |
| | $ | 102 |
| | $ | 14 |
| | $ | 2 |
| | $ | 16 |
| | $ | 86 |
|
| Gross amounts offset in the consolidated balance sheets | | (13 | ) | | (2 | ) | | (15 | ) | | (13 | ) | | (2 | ) | | (15 | ) | | — |
|
Cash collateral posted2 | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net amounts presented in the consolidated balance sheets | | $ | 81 |
| | $ | 6 |
| | $ | 87 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | 86 |
|
| |
1 | Included in "Other long-term assets" in the consolidated balance sheets. |
| |
2 | At December 31, 2019, SCE posted $24 million of cash collateral that is not offset against derivative liabilities and is reflected in "Other current assets" on the consolidated balance sheets. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2018 | | |
| | | Derivative Assets | | Derivative Liabilities | | Net Asset |
| (in millions) | | Short-Term | | Long-Term | | Subtotal | | Short-Term | | Long-Term | | Subtotal | |
| Commodity derivative contracts | | | | | | | | | | | | |
| Gross amounts recognized | | $ | 171 |
| | $ | 2 |
| | $ | 173 |
| | $ | 13 |
| | $ | — |
| | $ | 13 |
| | $ | 160 |
|
| Gross amounts offset in the consolidated balance sheets | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Cash collateral posted | | — |
| | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) | | 7 |
|
| Net amounts presented in the consolidated balance sheets | | $ | 171 |
| | $ | 2 |
| | $ | 173 |
| | $ | 6 |
| | $ | — |
| | $ | 6 |
| | $ | 167 |
|
Income Statement Impact of Derivative Instruments
SCE recognizes realized gains and losses on derivative instruments as purchased power expense and expects that such gains or losses will be part of the purchased power costs recovered from customers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from customers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings. The remaining effects of derivative activities and related regulatory offsets are reported in cash flows from operating activities in the consolidated statements of cash flows.
The following table summarizes the components of SCE's economic hedging activity:
|
| | | | | | | | | | | | |
| | | Years ended December 31, |
| (in millions) | | 2019 | | 2018 | | 2017 |
| Realized (losses) gains | | $ | (7 | ) | | $ | 26 |
| | $ | (14 | ) |
| Unrealized (losses) gains | | (74 | ) | | 82 |
| | 106 |
|
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for SCE economic hedging activities:
|
| | | | |
| | | Economic Hedges |
| | Unit of | December 31, |
| Commodity | Measure | 2019 | | 2018 |
| Electricity options, swaps and forwards | GWh | 3,155 | | 2,786 |
| Natural gas options, swaps and forwards | Bcf | 43 | | 20 |
| Congestion revenue rights | GWh | 48,170 | | 54,453 |
Note 7. Revenue
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 revenues 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.
The following table is a summary of SCE's revenue:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years ended December 31, |
| | 2019 | 2018 | 2017 |
| (in millions) | Earning Activities | Cost- Recovery Activities | Total Consolidated | Earning Activities | Cost- Recovery Activities | Total Consolidated | Earning Activities | Cost-Recovery Activities | Total Consolidated |
Revenues from contracts with customers1,2 | $ | 6,512 |
| $ | 4,655 |
| $ | 11,167 |
| $ | 6,519 |
| $ | 5,611 |
| $ | 12,130 |
| * |
| * |
| * |
|
| Alternative revenue programs and other operating revenue | 166 |
| 973 |
| 1,139 |
| 41 |
| 440 |
| 481 |
| * |
| * |
| * |
|
| Total operating revenue | $ | 6,678 |
| $ | 5,628 |
| $ | 12,306 |
| $ | 6,560 |
| $ | 6,051 |
| $ | 12,611 |
| $ | 6,611 |
| $ | 5,643 |
| $ | 12,254 |
|
* SCE adopted new accounting guidance as of January 1, 2018. Prior period amounts have not been adjusted under the modified retrospective method.
| |
1 | In the absence of a 2018 GRC decision, SCE recorded CPUC revenue in 2018 and the first quarter of 2019 based on the 2017 authorized revenue requirements adjusted for the July 2017 cost of capital decision and Tax Reform. SCE recorded the impact of the 2018 GRC final decision in the second quarter of 2019, including a $265 million reduction in revenue. These revenue adjustments are included in "Revenues from contracts with customers." For further information, see Note 1. |
| |
2 | At December 31, 2019 and 2018, SCE's receivables related to contracts from customers were both $1.1 billion, which included accrued unbilled revenue of $488 million and $482 million, respectively. |
Note 8. Income Taxes
Current and Deferred Taxes
Edison International's sources of income before income taxes are:
|
| | | | | | | | | | | | |
| | | Years ended December 31, |
| (in millions) | | 2018 | | 2017 | | 2016 |
| (Loss) income from continuing operations before income taxes | | $ | (1,089 | ) | | $ | 949 |
| | $ | 1,590 |
|
| Income from discontinued operations before income taxes | | — |
| | — |
| | 1 |
|
| (Loss) income before income tax | | $ | (1,089 | ) | | $ | 949 |
| | $ | 1,591 |
|
The components of income tax (benefit) expense by location of taxing jurisdiction are:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Current: | | | | | | | | | | | |
| Federal | $ | — |
| | $ | (57 | ) | | $ | (221 | ) | | $ | — |
| | $ | (51 | ) | | $ | (253 | ) |
| State | 6 |
| | (155 | ) | | 4 |
| | 14 |
| | (93 | ) | | (81 | ) |
| | 6 |
| | (212 | ) | | (217 | ) | | 14 |
| | (144 | ) | | (334 | ) |
| Deferred: | | | | | | | | | | | |
| Federal | (243 | ) | | (386 | ) | | 570 |
| | (206 | ) | | (354 | ) | | 265 |
|
| State | (41 | ) | | (141 | ) | | (72 | ) | | (37 | ) | | (198 | ) | | 39 |
|
| | (284 | ) | | (527 | ) | | 498 |
| | (243 | ) | | (552 | ) | | 304 |
|
| Total continuing operations | (278 | ) | | (739 | ) | | 281 |
| | (229 | ) | | (696 | ) | | (30 | ) |
Discontinued operations1 | — |
| | (34 | ) | | — |
| | — |
| | — |
| | — |
|
| Total | $ | (278 | ) | | $ | (773 | ) | | $ | 281 |
| | $ | (229 | ) | | $ | (696 | ) | | $ | (30 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Current: | | | | | | | | | | | |
| Federal | $ | (57 | ) | | $ | (221 | ) | | $ | (46 | ) | | $ | (51 | ) | | $ | (253 | ) | | $ | 75 |
|
| State | (155 | ) | | 4 |
| | 33 |
| | (93 | ) | | (81 | ) | | 93 |
|
| | (212 | ) | | (217 | ) | | (13 | ) | | (144 | ) | | (334 | ) | | 168 |
|
| Deferred: | | | | | | | | | | | |
| Federal | (386 | ) | | 570 |
| | 176 |
| | (354 | ) | | 265 |
| | 112 |
|
| State | (141 | ) | | (72 | ) | | 14 |
| | (198 | ) | | 39 |
| | (24 | ) |
| | (527 | ) | | 498 |
| | 190 |
| | (552 | ) | | 304 |
| | 88 |
|
| Total continuing operations | (739 | ) | | 281 |
| | 177 |
| | (696 | ) | | (30 | ) | | 256 |
|
Discontinued operations1 | (34 | ) | | — |
| | (11 | ) | | — |
| | — |
| | — |
|
| Total | $ | (773 | ) | | $ | 281 |
| | $ | 166 |
| | $ | (696 | ) | | $ | (30 | ) | | $ | 256 |
|
| |
1 | In the fourth quarter of 2018, Edison International and SCE recognized tax benefits related to a settlement with the California Franchise Tax Board for tax years 1994 – 2006. See further discussion in Tax Disputes below. |
The components of net accumulated deferred income tax liability are:
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Deferred tax assets: | | | | | | | |
| Property | $ | 478 |
| | $ | 399 |
| | $ | 435 |
| | $ | 388 |
|
Wildfire-related1 | 847 |
| | 709 |
| | 847 |
| | 709 |
|
| Nuclear decommissioning trust assets in excess of nuclear ARO liability | 449 |
| | 323 |
| | 449 |
| | 323 |
|
Loss and credit carryforwards2 | 1,515 |
| | 1,375 |
| | 253 |
| | 154 |
|
| Regulatory asset | 739 |
| | 798 |
| | 739 |
| | 798 |
|
| Pension and postretirement benefits other than pensions, net | 170 |
| | 171 |
| | 40 |
| | 46 |
|
| Other | 408 |
| | 188 |
| | 416 |
| | 184 |
|
| Sub-total | 4,606 |
| | 3,963 |
| | 3,179 |
| | 2,602 |
|
Less: valuation allowance3 | 35 |
| | 36 |
| | — |
| | — |
|
| Total | 4,571 |
| | 3,927 |
| | 3,179 |
| | 2,602 |
|
| Deferred tax liabilities: | | | | | | | |
| Property | 8,244 |
| | 7,685 |
| | 8,234 |
| | 7,685 |
|
| Regulatory liability | 570 |
| | 367 |
| | 570 |
| | 367 |
|
| Nuclear decommissioning trust assets | 449 |
| | 323 |
| | 449 |
| | 323 |
|
| Other | 320 |
| | 57 |
| | 310 |
| | 54 |
|
| Total | 9,583 |
| | 8,432 |
| | 9,563 |
| | 8,429 |
|
Accumulated deferred income tax liability, net4 | $ | 5,012 |
| | $ | 4,505 |
| | $ | 6,384 |
| | $ | 5,827 |
|
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Deferred tax assets: | | | | | | | |
| Property and software related | $ | 399 |
| | $ | 358 |
| | $ | 388 |
| | $ | 357 |
|
Wildfire reserve1 | 709 |
| | — |
| | 709 |
| | — |
|
| Nuclear decommissioning trust assets in excess of nuclear ARO liability | 323 |
| | 404 |
| | 323 |
| | 404 |
|
Loss and credit carryforwards2 | 1,375 |
| | 1,346 |
| | 154 |
| | 150 |
|
Regulatory asset3 | 798 |
| | 812 |
| | 798 |
| | 812 |
|
| Pension and postretirement benefits other than pensions, net | 171 |
| | 178 |
| | 46 |
| | 50 |
|
| Other | 188 |
| | 277 |
| | 184 |
| | 236 |
|
| Sub-total | 3,963 |
| | 3,375 |
| | 2,602 |
| | 2,009 |
|
Less: valuation allowance4 | 36 |
| | 28 |
| | — |
| | — |
|
| Total | 3,927 |
| | 3,347 |
| | 2,602 |
| | 2,009 |
|
| Deferred tax liabilities: | | | | | | | |
| Property-related | 7,497 |
| | 6,970 |
| | 7,497 |
| | 6,962 |
|
| Capitalized software costs | 188 |
| | 160 |
| | 188 |
| | 160 |
|
| Regulatory liability | 367 |
| | 158 |
| | 367 |
| | 158 |
|
| Nuclear decommissioning trust assets | 323 |
| | 404 |
| | 323 |
| | 404 |
|
| Other | 57 |
| | 140 |
| | 54 |
| | 133 |
|
| Total | 8,432 |
| | 7,832 |
| | 8,429 |
| | 7,817 |
|
Accumulated deferred income tax liability, net5 | $ | 4,505 |
| | $ | 4,485 |
| | $ | 5,827 |
| | $ | 5,808 |
|
| |
1 | Relates to a charge recordedaccrued estimated losses for wildfire-related claims, net of expected recoveries from insurance and FERC customers.customers, and contributions to the Wildfire Insurance Fund. For further information, see Note 12.12 and Note 1. |
| |
2 | As of December 31, 2018,2019, deferred tax assets for net operating loss and tax credit carryforwards are reduced by unrecognized tax benefits of $178$212 million and $97$130 million for Edison International and SCE, respectively. |
3 Includes deferred tax asset of $788 million and $809 million, for December 31, 2018 and 2017, respectively, related to certain regulatory liabilities established as part of Tax Reform discussed below.
| |
43
| As of December 31, 20182019, Edison International has recorded a valuation allowance of $32$30 million for non-California state net operating loss carryforwards, and $4$5 million for California capital losslosses generated from sale of SoCore Energy in 2018, which are estimated to expire before being utilized. |
| |
54
| Included in deferred"Deferred income taxes and creditscredits" on the consolidated balance sheets. |
On December 22, 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. At the date of enactment, Edison International and SCE's deferred taxes were re-measured based upon the new tax rate. In December 2017, accumulated deferred income tax liabilities, net, were reduced by $4.5 billion and $5.0 billion at Edison International and SCE, respectively. Edison International recorded income tax expense of $466 million at December 31, 2017, primarily related to the re-measurement of the federal net operating loss carryforwards (see below for more information).
In the absence of regulatory guidance specific to 2017 Tax Reform, SCE used judgment to interpret prior Commission decisions in determining which re-measurement amounts belong to customers and shareholders. Customer amounts were recorded to regulatory assets and liabilities. An income tax expense of $33 million was recorded for the re-measurement of deferred taxes attributable to shareholder-funded activities in 2017. 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 ruling in January of 2019 that determined customers are only entitled to excess
deferred taxes which were included in rate base, all other deferred tax re-measurement belongs to shareholders. As a result, an income tax benefit of approximately $70 million is expected to be recorded in the first quarter of 2019.
In December 2017, SCE recorded estimated deferred taxes related to Tax Reform pertaining to the changes of bonus depreciation rules for property acquired and placed into service after September 27, 2017. In August 2018, the Internal Revenue Service ("IRS") and United States Treasury Department issued proposed regulations which taxpayers may rely on when determining bonus depreciation for such property. The application of the proposed regulations had an immaterial impact on Edison International's and SCE's statements of income and balance sheets.
Net Operating Loss and Tax Credit Carryforwards
The amounts of net operating loss and tax credit carryforwards (after-tax) are as follows:
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, 2019 |
| (in millions) | Loss Carryforwards | | Credit Carryforwards | | Loss Carryforwards | | Credit Carryforwards |
| Expire between 2029 to 2037 | $ | 1,024 |
| | $ | 482 |
| | $ | 229 |
| | $ | 30 |
|
| Expire between 2021 to 2024 | 29 |
|
| — |
|
| 24 |
|
| — |
|
No expiration date1 | 182 |
| | 10 |
| | 100 |
| | — |
|
| Total | $ | 1,235 |
| | $ | 492 |
| | $ | 353 |
| | $ | 30 |
|
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, 2018 |
| (in millions) | Loss Carryforwards | | Credit Carryforwards | | Loss Carryforwards | | Credit Carryforwards |
| Expire between 2021 to 2038 | $ | 1,073 |
| | $ | 469 |
| | $ | 203 |
| | $ | 26 |
|
| No expiration date | — |
| | 11 |
| | — |
| | 22 |
|
| Total | $ | 1,073 |
| | $ | 480 |
| | $ | 203 |
| | $ | 48 |
|
| |
1 | Under the Tax Reform, net operating losses generatedafter December 31, 2017 can carryforward indefinitely. |
Edison International consolidates for federal income tax purposes, but not for financial accounting purposes, a group of wind projects referred to as Capistrano Wind. The amount of net operating loss and tax credit carryforwards recognized as part of deferred income taxes includes $212 million and $199 million related to Capistrano Wind at December 31, 2018for both 2019 and 2017, respectively.2018. Under a tax allocation
agreement, Edison International has recorded a corresponding liability as part of other long-term liabilities related to its obligation to make payments to Capistrano Wind of these tax benefits when realized.
Effective Tax Rate
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision:
| | | | Edison International | | SCE | Edison International | | SCE |
| | Years ended December 31, | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| (Loss) income from continuing operations before income taxes | $ | (1,089 | ) | | $ | 949 |
| | $ | 1,590 |
| | $ | (885 | ) | | $ | 1,106 |
| | $ | 1,755 |
| |
Provision for income tax at federal statutory rate of 21% and 35%, respectively1 | (229 | ) | | 332 |
| | 556 |
| | (186 | ) | | 387 |
| | 614 |
| |
| Income (loss) from continuing operations before income taxes | | $ | 1,127 |
| | $ | (1,089 | ) | | $ | 949 |
| | $ | 1,301 |
| | $ | (885 | ) | | $ | 1,106 |
|
Provision for income tax at federal statutory rate of 21% for 2019 and 2018, and 35% for 20171 | | 237 |
| | (229 | ) | | 332 |
| | 273 |
| | (186 | ) | | 387 |
|
| Increase in income tax from: | |
| | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
| | |
| | |
| Items presented with related state income tax, net: | |
| | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
| | |
| | |
| State tax, net of federal benefit | (168 | ) | | 2 |
| | 29 |
| | (155 | ) | | 8 |
| | 43 |
| (22 | ) | | (168 | ) | | 2 |
| | (13 | ) | | (155 | ) | | 8 |
|
| Property-related | (275 | ) | | (439 | ) | | (362 | ) | | (275 | ) | | (439 | ) | | (362 | ) | (303 | ) | | (275 | ) | | (439 | ) | | (303 | ) | | (275 | ) | | (439 | ) |
Change related to uncertain tax positions2 | (66 | ) | | (18 | ) | | (4 | ) | | (71 | ) | | (13 | ) | | (8 | ) | — |
| | (66 | ) | | (18 | ) | | — |
| | (71 | ) | | (13 | ) |
Revised San Onofre Settlement Agreement3 | — |
| | 25 |
| | — |
| | — |
| | 25 |
| | — |
| — |
| | — |
| | 25 |
| | — |
| | — |
| | 25 |
|
Share-based compensation4 | (2 | ) | | (55 | ) | | (28 | ) | | (1 | ) | | (11 | ) | | (13 | ) | (4 | ) | | (2 | ) | | (55 | ) | | (3 | ) | | (1 | ) | | (11 | ) |
Deferred tax re-measurement5 | — |
| | 466 |
| | — |
| | — |
| | 33 |
| | — |
| (88 | ) | | — |
| | 466 |
| | (88 | ) | | — |
| | 33 |
|
| 2018 GRC Final Decision | | (80 | ) | | — |
| | — |
| | (80 | ) | | — |
| | — |
|
| Other | 1 |
| | (32 | ) | | (14 | ) | | (8 | ) | | (20 | ) | | (18 | ) | (18 | ) | | 1 |
| | (32 | ) | | (15 | ) | | (8 | ) | | (20 | ) |
| Total income tax (benefit) expense from continuing operations | $ | (739 | ) | | $ | 281 |
| | $ | 177 |
| | $ | (696 | ) | | $ | (30 | ) | | $ | 256 |
| $ | (278 | ) | | $ | (739 | ) | | $ | 281 |
| | $ | (229 | ) | | $ | (696 | ) | | $ | (30 | ) |
| Effective tax rate | (67.9 | )% | | 29.6 | % | | 11.1 | % | | (78.6 | )% | | (2.7 | )% | | 14.6 | % | (24.7 | )% | | (67.9 | )% | | 29.6 | % | | (17.6 | )% | | (78.6 | )% | | (2.7 | )% |
1 Tax Reform reduced the federal corporate income tax rate from 35% to 21%, effective January 1, 2018.
2In the fourth quarter of 2018, Edison International and SCE recognized tax benefits related to a settlement with the California Franchise Tax Board for tax years 1994 – 2006. See further discussion in Tax Disputes below.
3Includes the write-off of an unrecovered tax regulatory asset related to the Revised San Onofre Order Instituting Investigation Settlement Agreement. See Note 12 for further information.Agreement among SCE, SDG&E and various intervening parties, dated January 30, 2018 and modified on August 2, 2018 ("Revised San Onofre Settlement Agreement").
| |
4 | Includes state taxes of $(11) million and $(4) million for Edison International and $(2) million and $(1) million for SCE for the yearsyear ended December 31, 2017 and 2016, respectively.2017. |
| |
5 | In 2017, Edison International and SCE recorded a charge to earnings related to the re-measurement of deferred taxes resulting from Tax Reform. See further discussion above.This charge was updated in 2019 to conform to a CPUC resolution which finalized the re-measurement amounts belonging to shareholders and those amounts are charged to earnings. |
The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. Flow-through items reduce current authorized revenue requirements in SCE's rate cases and result in a regulatory asset for recovery of deferred income taxes in future periods. The difference between the authorized amounts as determined in SCE's rate cases, adjusted for balancing and memorandum account activities, and the recorded flow-through items also result in increases or decreases in regulatory assets with a corresponding impact on the effective tax rate to the extent that recorded deferred amounts are expected to be recovered in future rates. For further information, see Note 11.
2017 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. 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, Edison International and SCE's deferred taxes were re-measured based upon the new tax rate.
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 allocated between customers and shareholders. Customer amounts were recorded to regulatory assets and liabilities while shareholder-funded activities were charged to earnings.
In the absence of regulatory guidance at the time, SCE used judgment to interpret prior CPUC decisions when determining which re-measurement amounts belong to customers and shareholders. In February of 2019, the CPUC issued a final resolution holding that customers are only entitled to the re-measurement of deferred taxes that were included when setting rates (i.e. included in rate base) and that all other deferred tax re-measurements belong to shareholders. As a result of the resolution, SCE recorded an income tax benefit of approximately $88 million in the year 2019.
Accounting for Uncertainty in Income Taxes
Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination. The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.
Unrecognized Tax Benefits
The following table provides a reconciliation of unrecognized tax benefits for continuing and discontinued operations:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Balance at January 1, | $ | 338 |
| | $ | 432 |
| | $ | 471 |
| | $ | 249 |
| | $ | 331 |
| | $ | 371 |
|
| Tax positions taken during the current year: | | | | | | | | | | | |
| Increases | 46 |
| | 41 |
| | 51 |
| | 47 |
| | 42 |
| | 51 |
|
| Tax positions taken during a prior year: | | | | | | | | | | | |
| Increases | 6 |
| | — |
| | — |
| | 6 |
| | — |
| | — |
|
Decreases1 | (20 | ) | | (108 | ) | | (7 | ) | | (20 | ) | | (121 | ) | | (13 | ) |
Settlements with taxing authorities2 | — |
| | (27 | ) | | (83 | ) | | — |
| | (3 | ) | | (78 | ) |
| Balance at December 31, | $ | 370 |
| | $ | 338 |
| | $ | 432 |
| | $ | 282 |
| | $ | 249 |
| | $ | 331 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Balance at January 1, | $ | 432 |
| | $ | 471 |
| | $ | 529 |
| | $ | 331 |
| | $ | 371 |
| | $ | 353 |
|
| Tax positions taken during the current year: | | | | | | | | | | | |
| Increases | 41 |
| | 51 |
| | 36 |
| | 42 |
| | 51 |
| | 36 |
|
| Tax positions taken during a prior year: | | | | | | | | | | | |
| Increases | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
|
Decreases1 | (108 | ) | | (7 | ) | | (96 | ) | | (121 | ) | | (13 | ) | | (18 | ) |
Decreases for settlements during the period2 | (27 | ) | | (83 | ) | | — |
| | (3 | ) | | (78 | ) | | — |
|
| Balance at December 31, | $ | 338 |
| | $ | 432 |
| | $ | 471 |
| | $ | 249 |
| | $ | 331 |
| | $ | 371 |
|
| |
1 | Decrease in 2018 was related to re-measurement as a result of a settlement with the California Franchise Tax Board for tax years 1994 – 2006. Decrease in 2016 was related to state tax receivables on various claims. Due to the tax risks associated with these claims, the tax benefits were fully reserved at the time the asset was recorded. During 2016, the Company determined that it will not recognize these assets, so the tax benefit and related tax reserve were written off. |
| |
2 | In 2018, Edison International reached a settlement with the California Franchise Tax Board for tax years 1994 – 2006. In 2017, Edison International settled all open tax positions with the IRS for taxable years 2007 – 2012. See Tax Disputes below for further details. |
As of December 31, 2018, 2017 and 2016,2019, if recognized, $197$192 million $308 million, and $347 million, respectively, of unrecognized tax benefits would impact Edison International's effective tax rate and $95$104 million $167 million, and $243 million, respectively, of the unrecognized tax benefits would impact SCE's effective tax rate.
Tax Disputes
In 2017, Edison International settled all open tax positions with the IRS for tax years 2007 – 2012. Edison International has previously made cash deposits to cover the estimated tax and interest liability from this audit cycle and expects a $7 million refund of this deposited amount.
Tax years that remain open for examination by the IRS and the California Franchise Tax Board are 20152016 – 20172018 and 2010 – 2017,2018, respectively. Edison International has settled all open tax positions with the IRS for taxable years prior to 2013.
In the fourth quarter of 2018, Edison International reachedrecorded the impacts of a settlement reached with the California Franchise Tax Board for tax years 1994 – 2006 and has updated its uncertain tax positions to reflect this settlement. This updatethat resulted in income tax benefits of $103a $65 million and $70 million at Edison International and SCE, respectively. Of the $103 million tax benefits, $34 million was related to Edison Mission Energy ("EME"), a legacy business of Edison International with no ongoing operations. Accordingly, the amounts of the settlement related to EME were recorded to discontinued operations. As a result of the settlement, Edison International expects a refund of tax and interest from the California Franchise Tax Boardinterest. This refund was received in the amountsecond quarter of $65 million.2019. Tax years 2007 – 2009 are currently under protest with the California Franchise Tax Board.
Accrued Interest and Penalties
The total amount of accrued interest and penalties related to income tax liabilities for continuing and discontinued operations are:
| | | | Edison International | | SCE | Edison International | | SCE |
| | Years ended December 31, | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2018 | | 2017 | 2019 | | 2018 | | 2019 | | 2018 |
| Accrued interest and penalties | $ | 37 |
| | $ | 115 |
| | $ | 6 |
| | $ | 41 |
| $ | 56 |
| | $ | 37 |
| | $ | 29 |
| | $ | 6 |
|
The net after-tax interest and penalties recognized in income tax expense (benefit) expense for continuing and discontinued operations are:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Net after-tax interest and penalties tax expense (benefit) | $ | 4 |
| | $ | (62 | ) | | $ | 6 |
| | $ | 3 |
| | $ | (25 | ) | | $ | 4 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Net after-tax interest and penalties tax (benefit) expense | $ | (62 | ) | | $ | 6 |
| | $ | 6 |
| | $ | (25 | ) | | $ | 4 |
| | $ | 2 |
|
Note 9. Compensation and Benefit Plans
Employee Savings Plan
The 401(k) defined contribution savings plan is designed to supplement employees' retirement income. The following employer contributions were made for continuing operations:as follows:
|
| | | | | | | |
| | Edison International | | SCE |
| (in millions) | Years ended December 31, |
| 2019 | $ | 82 |
| | $ | 81 |
|
| 2018 | 74 |
| | 74 |
|
| 2017 | 70 |
| | 69 |
|
|
| | | | | | | |
| | Edison International | | SCE |
| (in millions) | Years ended December 31, |
| 2018 | $ | 74 |
| | $ | 74 |
|
| 2017 | 70 |
| | 69 |
|
| 2016 | 69 |
| | 68 |
|
Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
Noncontributory defined benefit pension plans (some with cash balance features) cover most employees meeting minimum service requirements. SCE recognizes pension expense for its nonexecutive plan as calculated by the actuarial method used for ratemaking. The expected contributions (all by the employer) for Edison International and SCE are approximately $84$54 million and $57$37 million, respectively, for the year ending December 31, 2019.2020. Annual contributions made by SCE to most of SCE's pension plans are anticipated to be recovered through CPUC-approved regulatory mechanisms.
The funded position of Edison International's pension is sensitive to changes in market conditions. Changes in overall interest rate levels significantly affect the company's liabilities, while assets held in the various trusts established to fund Edison International's pension are affected by movements in the equity and bond markets. Due to SCE's regulatory recovery treatment, a regulatory asset has been recorded equal to the unfunded status (Seestatus. See Note 11).11 for further information.
Information on pension plan assets and benefit obligations for continuing and discontinued operations is shown below.
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Change in projected benefit obligation | | | | | | | |
| Projected benefit obligation at beginning of year | $ | 3,880 |
| | $ | 4,179 |
| | $ | 3,431 |
| | $ | 3,702 |
|
| Service cost | 114 |
| | 126 |
| | 110 |
| | 121 |
|
| Interest cost | 155 |
| | 141 |
| | 138 |
| | 124 |
|
Actuarial loss (gain)1 | 240 |
| | (280 | ) | | 199 |
| | (273 | ) |
| Benefits paid | (250 | ) | | (286 | ) | | (216 | ) | | (243 | ) |
| Projected benefit obligation at end of year | $ | 4,139 |
| | $ | 3,880 |
| | $ | 3,662 |
| | $ | 3,431 |
|
| Change in plan assets | | | | | | | |
| Fair value of plan assets at beginning of year | $ | 3,321 |
| | $ | 3,616 |
| | $ | 3,124 |
| | $ | 3,390 |
|
| Actual return on plan assets | 611 |
| | (86 | ) | | 576 |
| | (86 | ) |
| Employer contributions | 73 |
| | 77 |
| | 57 |
| | 52 |
|
| Benefits paid | (250 | ) | | (286 | ) | | (216 | ) | | (232 | ) |
| Fair value of plan assets at end of year | 3,755 |
| | 3,321 |
| | 3,541 |
| | 3,124 |
|
| Funded status at end of year | $ | (384 | ) | | $ | (559 | ) | | $ | (121 | ) | | $ | (307 | ) |
Amounts recognized in the consolidated balance sheets consist of 2: | | | | | | | |
| Long-term assets | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| Current liabilities | (19 | ) | | (29 | ) | | (2 | ) | | (5 | ) |
| Long-term liabilities | (365 | ) | | (532 | ) | | (119 | ) | | (302 | ) |
| | $ | (384 | ) | | $ | (559 | ) | | $ | (121 | ) | | $ | (307 | ) |
| Amounts recognized in accumulated other comprehensive loss consist of: | | | | | | | |
| Prior service cost | $ | (1 | ) | | $ | (1 | ) | | $ | — |
| | $ | — |
|
Net loss2 | 95 |
| | 83 |
| | 17 |
| | 17 |
|
| | 94 |
| | 82 |
| | 17 |
| | 17 |
|
| Amounts recognized as a regulatory asset | 87 |
| | 271 |
| | 87 |
| | 271 |
|
| Total not yet recognized as expense | $ | 181 |
| | $ | 353 |
| | $ | 104 |
| | $ | 288 |
|
| Accumulated benefit obligation at end of year | $ | 3,968 |
| | $ | 3,753 |
| | $ | 3,529 |
| | $ | 3,342 |
|
| Pension plans with an accumulated benefit obligation in excess of plan assets: | | | | | | | |
| Projected benefit obligation | 4,139 |
| | 3,880 |
| | 3,662 |
| | 3,431 |
|
| Accumulated benefit obligation | 3,968 |
| | 3,753 |
| | 3,529 |
| | 3,342 |
|
| Fair value of plan assets | 3,755 |
| | 3,321 |
| | 3,541 |
| | 3,124 |
|
| Weighted average assumptions used to determine obligations at end of year: | | | | | | | |
| Discount rate | 3.11 | % | | 4.19 | % | | 3.11 | % | | 4.19 | % |
| Rate of compensation increase | 4.10 | % | | 4.10 | % | | 4.10 | % | | 4.10 | % |
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Change in projected benefit obligation | | | | | | | |
| Projected benefit obligation at beginning of year | $ | 4,179 |
| | $ | 4,284 |
| | $ | 3,702 |
| | $ | 3,791 |
|
| Service cost | 126 |
| | 137 |
| | 121 |
| | 129 |
|
| Interest cost | 141 |
| | 164 |
| | 124 |
| | 144 |
|
| Actuarial gain | (280 | ) | | (46 | ) | | (273 | ) | | (74 | ) |
| Benefits paid | (286 | ) | | (360 | ) | | (243 | ) | | (288 | ) |
| Projected benefit obligation at end of year | $ | 3,880 |
| | $ | 4,179 |
| | $ | 3,431 |
| | $ | 3,702 |
|
| Change in plan assets | | | | | | | |
| Fair value of plan assets at beginning of year | $ | 3,616 |
| | $ | 3,388 |
| | $ | 3,390 |
| | $ | 3,172 |
|
| Actual return on plan assets | (86 | ) | | 483 |
| | (86 | ) | | 442 |
|
| Employer contributions | 77 |
| | 105 |
| | 52 |
| | 64 |
|
| Benefits paid | (286 | ) | | (360 | ) | | (232 | ) | | (288 | ) |
| Fair value of plan assets at end of year | $ | 3,321 |
| | $ | 3,616 |
| | $ | 3,124 |
| | $ | 3,390 |
|
| Funded status at end of year | $ | (559 | ) | | $ | (563 | ) | | $ | (307 | ) | | $ | (312 | ) |
Amounts recognized in the consolidated balance sheets consist of 1: | | | | | | | |
| Long-term assets | $ | 2 |
| | $ | 7 |
| | $ | — |
| | $ | — |
|
| Current liabilities | (29 | ) | | (17 | ) | | (5 | ) | | (4 | ) |
| Long-term liabilities | (532 | ) | | (553 | ) | | (302 | ) | | (308 | ) |
| | $ | (559 | ) | | $ | (563 | ) | | $ | (307 | ) | | $ | (312 | ) |
| Amounts recognized in accumulated other comprehensive loss consist of: | | | | | | | |
| Prior service cost | $ | (1 | ) | | $ | (1 | ) | | $ | — |
| | $ | — |
|
Net loss1 | 83 |
| | 77 |
| | 17 |
| | 21 |
|
| | $ | 82 |
| | $ | 76 |
| | $ | 17 |
| | $ | 21 |
|
| Amounts recognized as a regulatory asset | 271 |
| | 271 |
| | 271 |
| | 271 |
|
| Total not yet recognized as expense | $ | 353 |
| | $ | 347 |
| | $ | 288 |
| | $ | 292 |
|
| Accumulated benefit obligation at end of year | $ | 3,753 |
| | $ | 4,022 |
| | $ | 3,342 |
| | $ | 3,585 |
|
| Pension plans with an accumulated benefit obligation in excess of plan assets: | | | | | | | |
| Projected benefit obligation | $ | 3,880 |
| | $ | 4,179 |
| | $ | 3,431 |
| | $ | 3,702 |
|
| Accumulated benefit obligation | 3,753 |
| | 4,022 |
| | 3,342 |
| | 3,585 |
|
| Fair value of plan assets | 3,321 |
| | 3,616 |
| | 3,124 |
| | 3,390 |
|
| Weighted-average assumptions used to determine obligations at end of year: | | | | | | | |
| Discount rate | 4.19 | % | | 3.46 | % | | 4.19 | % | | 3.46 | % |
| Rate of compensation increase | 4.10 | % | | 4.10 | % | | 4.10 | % | | 4.10 | % |
| |
1 | For Edison International and SCE, respectively, the 2019 actuarial losses are primarily related to $401 million and $373 million in losses from a decrease in the discount rate (from 4.19% as of December 31, 2018 to 3.11% as of December 31, 2019), partially offset by $157 million and $177 million in gains from other economic assumption changes. The 2018 actuarial gains are primarily related to $277 million and $261 million in gains from an increase in discount rate (from 3.46% as of December 31, 2017 to 4.19% as of December 31, 2018), respectively. |
| |
2 | The SCE liability excludes a long-term payable due to Edison International Parent of $117$133 million and $114$117 million at December 31, 20182019 and 2017,2018, respectively, related to certain SCE postretirement benefit obligations transferred to Edison International Parent. SCE's accumulated other comprehensive loss of $17 million and $21 million at December 31, 20182019 and 2017, respectively,2018, excludes net losslosses of $21$37 million and $19$21 million related to these benefits.benefits, respectively. |
Net periodic pension expense components for continuing operations are:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Service cost | $ | 114 |
| | $ | 126 |
| | $ | 138 |
| | $ | 111 |
| | $ | 123 |
| | $ | 133 |
|
| Non-service cost | | | | | | | | | | | |
| Interest cost | 155 |
| | 140 |
| | 164 |
| | 143 |
| | 128 |
| | 149 |
|
| Expected return on plan assets | (205 | ) | | (228 | ) | | (212 | ) | | (194 | ) | | (214 | ) | | (199 | ) |
| Settlement costs | — |
| | — |
| | 6 |
| | — |
| | — |
| | — |
|
| Amortization of prior service cost | 2 |
| | 3 |
| | 3 |
| | 2 |
| | 3 |
| | 3 |
|
Amortization of net loss1 | 7 |
| | 9 |
| | 21 |
| | 5 |
| | 6 |
| | 17 |
|
| Regulatory adjustment (deferred) | (3 | ) | | 15 |
| | (28 | ) | | (3 | ) | | 15 |
| | (28 | ) |
| Total non-service benefit | (44 | ) |
| (61 | ) |
| (46 | ) |
| (47 | ) |
| (62 | ) |
| (58 | ) |
| Total expense recognized | $ | 70 |
| | $ | 65 |
| | $ | 92 |
| | $ | 64 |
| | $ | 61 |
| | $ | 75 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 3 | | 2016 3 | | 2018 | | 2017 3 | | 2016 3 |
| Service cost | $ | 126 |
| | $ | 138 |
| | $ | 139 |
| | $ | 123 |
| | $ | 133 |
| | $ | 136 |
|
| Non-service cost | | | | | | | | | | | |
| Interest cost | 140 |
| | 164 |
| | 172 |
| | 128 |
| | 149 |
| | 156 |
|
| Expected return on plan assets | (228 | ) | | (212 | ) | | (220 | ) | | (214 | ) | | (199 | ) | | (205 | ) |
Settlement costs1 | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
|
| Amortization of prior service cost | 3 |
| | 3 |
| | 4 |
| | 3 |
| | 3 |
| | 4 |
|
Amortization of net loss2 | 9 |
| | 21 |
| | 27 |
| | 6 |
| | 17 |
| | 23 |
|
| Regulatory adjustment (deferred) | 15 |
| | (28 | ) | | (21 | ) | | 15 |
| | (28 | ) | | (21 | ) |
| Total non-service benefit | $ | (61 | ) |
| $ | (46 | ) |
| $ | (38 | ) |
| $ | (62 | ) |
| $ | (58 | ) |
| $ | (43 | ) |
| Total expense recognized | $ | 65 |
| | $ | 92 |
| | $ | 101 |
| | $ | 61 |
| | $ | 75 |
| | $ | 93 |
|
| |
1 | Under GAAP, a settlement is recorded when lump-sum payments exceed estimated annual service and interest costs. Lump sum payments made in 2017 to Edison International executives retiring in 2016 from the Executive Retirement Plan exceeded the estimated service and interest costs, resulting in a partial settlement of that plan. A settlement loss of approximately $6.4 million ($3.8 million after-tax) was recorded at Edison International for the year ended December 31, 2017. |
| |
2
| Includes the amount of net loss reclassified from accumulated other comprehensive loss. The amount reclassified for Edison International was $9$7 million, $10$9 million and $10 million for the years ended December 31, 2019, 2018 2017 and 2016,2017, respectively. The amount reclassified for SCE was $5 million, $6 million and $6 million for all the years ended December 31, 2019, 2018 2017 and 2016.2017. |
3 During the first quarter of 2018, Edison International and SCE adopted an accounting standard retrospectively related to the presentation of the components of net periodic benefit costs for the defined benefit pension and other postretirement plans. Prior years' consolidated income statements have been updated to reflect the retrospective application of this accounting standard. Service and non-service costs are included in "Operation and maintenance" and "Other income and expenses," respectively, on the consolidated income statement. See Note 1 for further information.
Other changes in pension plan assets and benefit obligations recognized in other comprehensive loss for continuing operations:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Net loss | $ | 19 |
| | $ | 5 |
| | $ | — |
| | $ | 21 |
| | $ | 5 |
| | $ | 3 |
|
| Settlement charges | — |
| | — |
| | (6 | ) | | — |
| | — |
| | — |
|
| Amortization of net loss | (7 | ) | | (9 | ) | | (10 | ) | | (5 | ) | | (6 | ) | | (6 | ) |
| Total recognized in other comprehensive loss | 12 |
| | (4 | ) | | (16 | ) | | 16 |
| | (1 | ) | | (3 | ) |
| Total recognized in expense and other comprehensive loss | $ | 82 |
| | $ | 61 |
| | $ | 76 |
| | $ | 80 |
| | $ | 60 |
| | $ | 72 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Net loss | $ | 5 |
| | $ | — |
| | $ | 6 |
| | $ | 5 |
| | $ | 3 |
| | $ | 4 |
|
| Settlement charges | — |
| | (6 | ) | | — |
| | — |
| | — |
| | — |
|
| Amortization of net loss | (9 | ) | | (10 | ) | | (10 | ) | | (6 | ) | | (6 | ) | | (6 | ) |
| Total recognized in other comprehensive loss | $ | (4 | ) | | $ | (16 | ) | | $ | (4 | ) | | $ | (1 | ) | | $ | (3 | ) | | $ | (2 | ) |
| Total recognized in expense and other comprehensive loss | $ | 61 |
| | $ | 76 |
| | $ | 97 |
| | $ | 60 |
| | $ | 72 |
| | $ | 91 |
|
In accordance with authoritative guidance on rate-regulated enterprises, SCE records regulatory assets and liabilities instead of charges and credits to other comprehensive income (loss) for the portion of SCE's postretirement benefit plans that are recoverable in utility rates.
The estimated pension amounts that will be amortized to expense in 20192020 for continuing operations are as follows:
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
Unrecognized net loss to be amortized1 | $ | 11 |
| | $ | 8 |
|
| Unrecognized prior service cost to be amortized | 2 |
| | 2 |
|
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
Unrecognized net loss to be amortized1 | $ | 8 |
| | $ | 6 |
|
| Unrecognized prior service cost to be amortized | 2 |
| | 2 |
|
| |
1 | The amount of net loss expected to be reclassified from accumulated other comprehensive loss for Edison International and SCE is $8$11 million and $6$8 million, respectively. |
Edison International and SCE used the following weighted-averageweighted average assumptions to determine pension expense for continuing operations:
|
| | | | | | | | |
| | Years ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Discount rate | 4.19 | % | | 3.46 | % | | 3.94 | % |
| Rate of compensation increase | 4.10 | % | | 4.10 | % | | 4.00 | % |
| Expected long-term return on plan assets | 6.50 | % | | 6.50 | % | | 6.50 | % |
|
| | | | | | | | |
| | Years ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Discount rate | 3.46 | % | | 3.94 | % | | 4.18 | % |
| Rate of compensation increase | 4.10 | % | | 4.00 | % | | 4.00 | % |
| Expected long-term return on plan assets | 6.50 | % | | 6.50 | % | | 7.00 | % |
The following benefit payments, which reflect expected future service, are expected to be paid:
|
| | | | | | | |
| | Edison International | | SCE |
| (in millions) | Years ended December 31, |
| 2020 | $ | 336 |
| | $ | 302 |
|
| 2021 | 332 |
| | 295 |
|
| 2022 | 320 |
| | 288 |
|
| 2023 | 309 |
| | 280 |
|
| 2024 | 306 |
| | 272 |
|
2025 – 2029 | 1,383 |
| | 1,224 |
|
|
| | | | | | | |
| | Edison International | | SCE |
| (in millions) | Years ended December 31, |
| 2019 | $ | 342 |
| | $ | 299 |
|
| 2020 | 323 |
| | 289 |
|
| 2021 | 323 |
| | 285 |
|
| 2022 | 313 |
| | 281 |
|
| 2023 | 301 |
| | 274 |
|
2024 – 2028 | 1,446 |
| | 1,280 |
|
Postretirement Benefits Other Than Pensions ("PBOP(s)")
Employees hired prior to December 31, 2017 who are retiring at or after age 55 with at least 10 years of service may be eligible for postretirement medical, dental, and vision benefits. Eligibility for a company contribution toward the cost of these benefits in retirement depends on a number of factors, including the employee's years of service, age, hire date, and retirement date. Under the terms of the Edison International Welfare Benefit Plan ("PBOP Plan"), each participating employer (Edison International or its participating subsidiaries) is responsible for the costs and expenses of all PBOP Plan benefits with respect to its employees and former employees that exceed the participants' share of contributions. A participating employer may terminate the PBOP Plan benefits with respect to its employees and former employees, as may SCE (as PBOP Plan sponsor), and, accordingly, the participants' PBOP Plan benefits are not vested benefits.
The expected contributions (substantially all of which are expected to be made by SCE) for PBOP benefits are $23$11 million for the year ended December 31, 2019.2020. Annual contributions related to SCE employees made to SCE plans are anticipated to be recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the total annual expense for these plans.
SCE has three3 voluntary employees' beneficiary association trusts ("VEBA Trusts") that can only be used to pay for retiree health care benefits of SCE and its subsidiaries. Once funded into the VEBA Trusts, neither SCE nor Edison International can subsequently recover remaining amounts in the VEBA Trusts. Participants of the PBOP Plan do not have a beneficial interest in the VEBA Trusts. The VEBA Trust assets are sensitive to changes in market conditions. Changes in overall interest rate levels significantly affect the company's liabilities, while assets held in the various trusts established to fund Edison International's other postretirement benefits are affected by movements in the equity and bond markets. Due to SCE's regulatory recovery treatment, the unfunded status is offset by a regulatory asset.
Information on PBOP Plan assets and benefit obligations is shown below:
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Change in benefit obligation | | | | | | | |
| Benefit obligation at beginning of year | $ | 1,986 |
| | $ | 2,337 |
| | $ | 1,977 |
| | $ | 2,325 |
|
| Service cost | 30 |
| | 37 |
| | 30 |
| | 37 |
|
| Interest cost | 77 |
| | 80 |
| | 77 |
| | 80 |
|
Actuarial loss (gain)1 | 70 |
| | (382 | ) | | 70 |
| | (379 | ) |
| Plan participants' contributions | 29 |
| | 28 |
| | 29 |
| | 28 |
|
| Benefits paid | (109 | ) | | (114 | ) | | (109 | ) | | (114 | ) |
| Benefit obligation at end of year | $ | 2,083 |
| | $ | 1,986 |
| | $ | 2,074 |
| | $ | 1,977 |
|
| Change in plan assets | | | | | | | |
| Fair value of plan assets at beginning of year | $ | 2,133 |
| | $ | 2,330 |
| | $ | 2,133 |
| | $ | 2,330 |
|
| Actual return on assets | 401 |
| | (123 | ) | | 401 |
| | (123 | ) |
| Employer contributions | 11 |
| | 13 |
| | 10 |
| | 12 |
|
| Plan participants' contributions | 29 |
| | 28 |
| | 29 |
| | 28 |
|
| Benefits paid | (109 | ) | | (115 | ) | | (109 | ) | | (114 | ) |
| Fair value of plan assets at end of year | 2,465 |
| | 2,133 |
| | 2,464 |
| | 2,133 |
|
| Funded status at end of year | $ | 382 |
| | $ | 147 |
| | $ | 390 |
| | $ | 156 |
|
| Amounts recognized in the consolidated balance sheets consist of: | | | | | | | |
| Long-term assets | $ | 393 |
| | $ | 159 |
| | $ | 402 |
| | $ | 168 |
|
| Current liabilities | (11 | ) | | (12 | ) | | (12 | ) | | (12 | ) |
| Long-term liabilities | — |
| | — |
| | — |
| | — |
|
| | $ | 382 |
| | $ | 147 |
| | $ | 390 |
| | $ | 156 |
|
| Amounts recognized in accumulated other comprehensive loss consist of: | | | | | | | |
| Net loss | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| Amounts recognized as a regulatory liability | (416 | ) | | (185 | ) | | (416 | ) | | (185 | ) |
| Total not yet recognized as income | $ | (414 | ) | | $ | (184 | ) | | $ | (416 | ) | | $ | (185 | ) |
| Weighted average assumptions used to determine obligations at end of year: | | | | | | | |
| Discount rate | 3.32 | % | | 4.35 | % | | 3.32 | % | | 4.35 | % |
| Assumed health care cost trend rates: | | | | | | | |
| Rate assumed for following year | 6.50 | % | | 6.75 | % | | 6.50 | % | | 6.75 | % |
| Ultimate rate | 5.00 | % | | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Year ultimate rate reached | 2029 |
| | 2029 |
| | 2029 |
| | 2029 |
|
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Change in benefit obligation | | | | | | | |
| Benefit obligation at beginning of year | $ | 2,337 |
| | $ | 2,276 |
| | $ | 2,325 |
| | $ | 2,266 |
|
| Service cost | 37 |
| | 31 |
| | 37 |
| | 31 |
|
| Interest cost | 80 |
| | 86 |
| | 80 |
| | 85 |
|
| Special termination benefits | — |
| | 1 |
| | — |
| | 1 |
|
Actuarial (gain) loss1 | (382 | ) | | 24 |
| | (379 | ) | | 23 |
|
| Plan participants' contributions | 28 |
| | 24 |
| | 28 |
| | 24 |
|
| Benefits paid | (114 | ) | | (105 | ) | | (114 | ) | | (105 | ) |
| Benefit obligation at end of year | $ | 1,986 |
| | $ | 2,337 |
| | $ | 1,977 |
| | $ | 2,325 |
|
| Change in plan assets | | | | | | | |
| Fair value of plan assets at beginning of year | $ | 2,330 |
| | $ | 2,102 |
| | $ | 2,330 |
| | $ | 2,102 |
|
| Actual return on assets | (123 | ) | | 297 |
| | (123 | ) | | 297 |
|
| Employer contributions | 13 |
| | 12 |
| | 12 |
| | 12 |
|
| Plan participants' contributions | 28 |
| | 24 |
| | 28 |
| | 24 |
|
| Benefits paid | (115 | ) | | (105 | ) | | (114 | ) | | (105 | ) |
| Fair value of plan assets at end of year | $ | 2,133 |
| | $ | 2,330 |
| | $ | 2,133 |
| | $ | 2,330 |
|
| Funded status at end of year | $ | 147 |
| | $ | (7 | ) | | $ | 156 |
| | $ | 5 |
|
| Amounts recognized in the consolidated balance sheets consist of: | | | | | | | |
| Long-term assets | $ | 159 |
| | $ | 6 |
| | $ | 168 |
| | $ | 17 |
|
| Current liabilities | (12 | ) | | (13 | ) | | (12 | ) | | (12 | ) |
| Long-term liabilities | — |
| | — |
| | — |
| | — |
|
| | $ | 147 |
| | $ | (7 | ) | | $ | 156 |
| | $ | 5 |
|
| Amounts recognized in accumulated other comprehensive loss consist of: | | | | | | | |
| Net loss | $ | 1 |
| | $ | 4 |
| | $ | — |
| | $ | — |
|
| Amounts recognized as a regulatory liability | (185 | ) | | (26 | ) | | (185 | ) | | (26 | ) |
| Total not yet recognized as income | $ | (184 | ) | | $ | (22 | ) | | $ | (185 | ) | | $ | (26 | ) |
| Weighted-average assumptions used to determine obligations at end of year: | | | | | | | |
| Discount rate | 4.35 | % | | 3.70 | % | | 4.35 | % | | 3.70 | % |
| Assumed health care cost trend rates: | | | | | | | |
| Rate assumed for following year | 6.75 | % | | 6.75 | % | | 6.75 | % | | 6.75 | % |
| Ultimate rate | 5.00 | % | | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Year ultimate rate reached | 2029 |
| | 2029 |
| | 2029 |
| | 2029 |
|
1 For Edison International and SCE, respectively, the 2018 actuarial gain isgains are primarily related to $195 million and $194 million gainin gains from an increase in the discount rate (from 3.70% as of December 31, 2017 to 4.35% as of December 31, 2018) and $137 million and $135 million in experience gain.gains.
Net periodic PBOP expense components for continuing operations are:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Service cost | $ | 30 |
| | $ | 37 |
| | $ | 31 |
| | $ | 30 |
| | $ | 37 |
| | $ | 31 |
|
| Non-service cost | | | | | | | | | | | |
| Interest cost | 77 |
| | 80 |
| | 86 |
| | 77 |
| | 80 |
| | 85 |
|
| Expected return on plan assets | (111 | ) | | (121 | ) | | (110 | ) | | (111 | ) | | (122 | ) | | (110 | ) |
| Special termination benefits | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Amortization of prior service credit | (1 | ) | | (1 | ) | | (3 | ) | | (1 | ) | | (1 | ) | | (2 | ) |
| Amortization of net loss | (17 | ) | | — |
| | — |
| | (17 | ) | | — |
| | — |
|
| Regulatory adjustment (deferred) | 29 |
| | 24 |
| | — |
| | 29 |
| | 24 |
| | — |
|
| Total non-service benefit | (23 | ) |
| (18 | ) |
| (26 | ) |
| (23 | ) |
| (19 | ) |
| (26 | ) |
| Total expense | $ | 7 |
| | $ | 19 |
| | $ | 5 |
| | $ | 7 |
| | $ | 18 |
| | $ | 5 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 2 | | 2016 2 | | 2018 | | 2017 2 | | 2016 2 |
| Service cost | $ | 37 |
| | $ | 31 |
| | $ | 35 |
| | $ | 37 |
| | $ | 31 |
| | $ | 34 |
|
| Non-service cost | | | | | | | | | | | |
| Interest cost | 80 |
| | 86 |
| | 97 |
| | 80 |
| | 85 |
| | 97 |
|
| Expected return on plan assets | (121 | ) | | (110 | ) | | (112 | ) | | (122 | ) | | (110 | ) | | (112 | ) |
Special termination benefits1 | — |
| | 1 |
| | 2 |
| | — |
| | 1 |
| | 2 |
|
| Amortization of prior service credit | (1 | ) | | (3 | ) | | (2 | ) | | (1 | ) | | (2 | ) | | (2 | ) |
Regulatory adjustment (deferred)
| 24 |
| | — |
| | — |
| | 24 |
| | — |
| | — |
|
| Total non-service benefit | $ | (18 | ) |
| $ | (26 | ) |
| $ | (15 | ) |
| $ | (19 | ) |
| $ | (26 | ) |
| $ | (15 | ) |
| Total expense | $ | 19 |
| | $ | 5 |
| | $ | 20 |
| | $ | 18 |
| | $ | 5 |
| | $ | 19 |
|
| |
1
| Due to the reduction in workforce, SCE has incurred costs for extended retiree health care coverage. |
2 During the first quarter of 2018, Edison International and SCE adopted an accounting standard retrospectively related to the presentation of the components of net periodic benefit costs for the defined benefit pension and other postretirement plans. Prior years' consolidated income statements have been updated to reflect the retrospective application of this accounting standard. Service and non-service costs are included in "Operation and maintenance" and "Other income and expenses," respectively, on the consolidated income statement. See Note 1 for further information.
In accordance with authoritative guidance on rate-regulated enterprises, SCE records regulatory assets and liabilities instead of charges and credits to other comprehensive income (loss) for the portion of SCE's postretirement benefit plans that are recoverable in utility rates. The estimated PBOP amounts that will be amortized to expense in 20192020 for continuing operations are as follows:
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
| Unrecognized net gain to be amortized | $ | (17 | ) | | $ | (17 | ) |
| Unrecognized prior service credit to be amortized | (1 | ) | | (1 | ) |
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
| Unrecognized net gain to be amortized | $ | (3 | ) | | $ | (3 | ) |
| Unrecognized prior service credit to be amortized | (1 | ) | | (1 | ) |
Edison International and SCE used the following weighted-averageweighted average assumptions to determine PBOP expense for continuing operations:
|
| | | | | | | | |
| | Years ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Discount rate | 4.35 | % | | 3.70 | % | | 4.29 | % |
| Expected long-term return on plan assets | 5.30 | % | | 5.30 | % | | 5.30 | % |
| Assumed health care cost trend rates: | | | | | |
| Current year | 6.75 | % | | 6.75 | % | | 7.00 | % |
| Ultimate rate | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Year ultimate rate reached | 2029 |
| | 2029 |
| | 2022 |
|
|
| | | | | | | | |
| | Years ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Discount rate | 3.70 | % | | 4.29 | % | | 4.55 | % |
| Expected long-term return on plan assets | 5.30 | % | | 5.30 | % | | 5.60 | % |
| Assumed health care cost trend rates: | | | | | |
| Current year | 6.75 | % | | 7.00 | % | | 7.50 | % |
| Ultimate rate | 5.00 | % | | 5.00 | % | | 5.00 | % |
| Year ultimate rate reached | 2029 |
| | 2022 |
| | 2022 |
|
A one-percentage-point change in assumed health care cost trend rate would have the following effects on continuing operations:
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| (in millions) | One-Percentage-Point Increase | | One-Percentage-Point Decrease | | One-Percentage-Point Increase | | One-Percentage-Point Decrease |
| Effect on accumulated benefit obligation as of December 31, 2019 | $ | 225 |
| | $ | (184 | ) | | $ | 224 |
| | $ | (183 | ) |
| Effect on annual aggregate service and interest costs | 10 |
| | (8 | ) | | 10 |
| | (8 | ) |
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| (in millions) | One-Percentage-Point Increase | | One-Percentage-Point Decrease | | One-Percentage-Point Increase | | One-Percentage-Point Decrease |
| Effect on accumulated benefit obligation as of December 31, 2018 | $ | 210 |
| | $ | (173 | ) | | $ | 209 |
| | $ | (172 | ) |
| Effect on annual aggregate service and interest costs | 11 |
| | (9 | ) | | 11 |
| | (9 | ) |
The following benefit payments (net of plan participants' contributions) are expected to be paid:
|
| | | | | | | |
| | Edison International | | SCE |
| (in millions) | Years ended December 31, |
| 2020 | $ | 87 |
| | $ | 87 |
|
| 2021 | 90 |
| | 89 |
|
| 2022 | 92 |
| | 92 |
|
| 2023 | 94 |
| | 94 |
|
| 2024 | 97 |
| | 96 |
|
| 2025 – 2029 | 512 |
| | 509 |
|
|
| | | | | | | |
| | Edison International | | SCE |
| (in millions) | Years ended December 31, |
| 2019 | $ | 91 |
| | $ | 91 |
|
| 2020 | 94 |
| | 94 |
|
| 2021 | 97 |
| | 97 |
|
| 2022 | 100 |
| | 99 |
|
| 2023 | 103 |
| | 102 |
|
| 2024 – 2028 | 553 |
| | 550 |
|
Plan Assets
Description of Pension and Postretirement Benefits Other than Pensions Investment Strategies
The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination of asset classes and may have active and passive investment strategies within asset classes. Target allocations for 20182019 pension plan assets were 25%23% for U.S. equities, 17% for non-U.S. equities, 40%48% for fixed income and 12% for opportunistic and/or alternative investments and 6% for other investments. Target allocations for 20182019 PBOP plan assets (except for Represented VEBA which is 85% for fixed income, 5% for opportunistic/private equities and 10% globalfor U.S. and non-U.S. equities) are 58% for globalU.S. and non-U.S. equities, 29% for fixed income and 13% for opportunistic and/or alternative investments. Edison International employs multiple investment management firms. Investment managers within each asset class cover a range of investment styles and approaches. Risk is managed through diversification among multiple asset classes, managers, styles and securities. Plan asset classes and individual manager performances are measured against targets. Edison International also monitors the stability of its investment managers' organizations.
Allowable investment types include:
United States Equities: Commonequities: common and preferred stocks of large, medium, and small companies which are predominantly United States-based.
Non-United States Equities: Equityequities: equity securities issued by companies domiciled outside the United States and in depository receipts which represent ownership of securities of non-United States companies.
Fixed Income: Fixedincome: fixed income securities issued or guaranteed by the United States government, non-United States governments, government agencies and instrumentalities including municipal bonds, mortgage backed securities and corporate debt obligations. A portion of the fixed income positions may be held in debt securities that are below investment grade.
Opportunistic, Alternativealternative and Other Investments:other investments:
Opportunistic: Investmentsinvestments in short to intermediate term market opportunities. Investments may have fixed income and/or equity characteristics and may be either liquid or illiquid.
Alternative: Limitedlimited partnerships that invest in non-publicly traded entities.
Other: Investmentsinvestments diversified among multiple asset classes such as global equity, fixed income currency and commodities markets. Investments are made in liquid instruments within and across markets. The investment returns are expected to approximate the plans' expected investment returns.
Asset class portfolio weights are permitted to range within plus or minus 3%. Where approved by the fiduciary investment committee, futures contracts are used for portfolio rebalancing and to reallocate portfolio cash positions. Where authorized, a few of the plans' investment managers employ limited use of derivatives, including futures contracts, options, options on futures and interest rate swaps in place of direct investment in securities to gain efficient exposure to markets. Derivatives are not used to leverage the plans or any portfolios.
Determination of the Expected Long-Term Rate of Return on Assets
The overall expected long-term rate of return on assets assumption is based on the long-term target asset allocation for plan assets and capital markets return forecasts for asset classes employed. A portion of the PBOP trust asset returns are subject to taxation, so the expected long-term rate of return for these assets is determined on an after-tax basis.
Capital Markets Return Forecasts
SCE's capital markets return forecast methodologies primarily use a combination of historical market data, current market conditions, proprietary forecasting expertise, complex models to develop asset class return forecasts and a building block approach. The forecasts are developed using variables such as real risk-free interest, inflation and asset class specific risk premiums. For equities, the risk premium is based on an assumed average equity risk premium of 5% over cash. The forecasted return on private equity and opportunistic investments are estimated at a 2%4% premium above public equity, reflecting a premium for higher volatility and lower liquidity. For fixed income, the risk premium is based on a comprehensive modeling of credit spreads.
Fair Value of Plan Assets
The PBOP Plan and the Southern California Edison Company Retirement Plan Trust ("Master Trust") assets include investments in equity securities, U.S. treasury securities, other fixed-income securities, common/collective funds, mutual funds, other investment entities, foreign exchange and interest rate contracts, and partnership/joint ventures. Equity securities, U.S. treasury securities, mutual and money market funds are classified as Level 1 as fair value is determined by observable, unadjusted quoted market prices in active or highly liquid and transparent markets. The fair value of the underlying investments in equity mutual funds are based on stock-exchange prices. The fair value of the underlying investments in fixed-income mutual funds and other fixed income securities including municipal bonds are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information. Foreign exchange and interest rate contracts are classified as Level 2 because the values are based on observable prices but are not traded on an exchange. Futures contracts trade on an exchange and therefore are classified as Level 1. No investment is classified as Level 3 as of December 31, 2019 and 2018. Common/collective funds and partnerships are measured at fair value using the net asset value per share ("NAV") and have not been classified in the fair value hierarchy. Other investment entities are valued similarly to common/collective funds and are therefore classified as NAV. The Level 1 registered investment companies are either mutual or money market funds. The remaining funds in this category are readily redeemable and classified as NAV and are discussed further at Note 9 to the pension plan master trust investments table below.
Edison International reviews the process/procedures of both the pricing services and the trustee to gain an understanding of the inputs/assumptions and valuation techniques used to price each asset type/class. The trustee and Edison International's validation procedures for pension and PBOP equity and fixed income securities are the same as the nuclear decommissioning trusts. For further discussion, see Note 4. The values of Level 1 mutual and money market funds are publicly quoted. The trustees obtain the values of common/collective and other investment funds from the fund managers. The values of partnerships are based on partnership valuation statements updated for cash flows. SCE's investment managers corroborate the trustee fair values.
Pension Plan
The following table sets forth the Master Trust investments for Edison International and SCE that were accounted for at fair value as of December 31, 20182019 by asset class and level within the fair value hierarchy: | | | (in millions) | Level 1 | | Level 2 | | Level 3 | | NAV1 | | Total | Level 1 | | Level 2 | | NAV1 | | Total |
U.S. government and agency securities2 | $ | 110 |
| | $ | 937 |
| | $ | — |
| | $ | — |
| | $ | 1,047 |
| $ | 146 |
| | $ | 992 |
| | $ | — |
| | $ | 1,138 |
|
Corporate stocks3 | 473 |
| | 6 |
| | — |
| | — |
| | 479 |
| 547 |
| | 7 |
| | — |
| | 554 |
|
Corporate bonds4 | — |
| | 582 |
| | — |
| | — |
| | 582 |
| — |
| | 572 |
| | — |
| | 572 |
|
Common/collective funds5 | — |
| | — |
| | — |
| | 426 |
| | 426 |
| — |
| | — |
| | 693 |
| | 693 |
|
Partnerships/joint ventures6 | — |
| | — |
| | — |
| | 434 |
| | 434 |
| — |
| | — |
| | 471 |
| | 471 |
|
Other investment entities7 | — |
| | — |
| | — |
| | 236 |
| | 236 |
| — |
| | — |
| | 130 |
| | 130 |
|
Registered investment companies8 | 112 |
| | — |
| | — |
| | 2 |
| | 114 |
| 133 |
| | — |
| | — |
| | 133 |
|
| Interest-bearing cash | 2 |
| | — |
| | — |
| | — |
| | 2 |
| 7 |
| | — |
| | — |
| | 7 |
|
| Other | — |
| | 73 |
| | — |
| | — |
| | 73 |
| — |
| | 79 |
| | — |
| | 79 |
|
| Total | $ | 697 |
| | $ | 1,598 |
| | $ | — |
| | $ | 1,098 |
| | $ | 3,393 |
| $ | 833 |
| | $ | 1,650 |
| | $ | 1,294 |
| | $ | 3,777 |
|
| Receivables and payables, net | |
| | |
| | | | |
| | (72 | ) | |
| | |
| | |
| | (22 | ) |
| Net plan assets available for benefits | |
| | |
| | | | |
| | $ | 3,321 |
| |
| Combined net plan assets available for benefits | | |
| | |
| | |
| | 3,755 |
|
| SCE's share of net plan assets | | | | | | | | | $ | 3,124 |
| | | | | | | $ | 3,541 |
|
The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 20172018 by asset class and level within the fair value hierarchy: | | | (in millions) | Level 1 | | Level 2 | | Level 3 | | NAV1 | | Total | Level 1 | | Level 2 | | NAV1 | | Total |
U.S. government and agency securities2 | $ | 184 |
| | $ | 507 |
| | $ | — |
| | $ | — |
| | $ | 691 |
| $ | 110 |
| | $ | 937 |
| | $ | — |
| | $ | 1,047 |
|
Corporate stocks3 | 718 |
| | 11 |
| | — |
| | — |
| | 729 |
| 473 |
| | 6 |
| | — |
| | 479 |
|
Corporate bonds4 | — |
| | 676 |
| | — |
| | — |
| | 676 |
| — |
| | 582 |
| | — |
| | 582 |
|
Common/collective funds5 | — |
| | — |
| | — |
| | 705 |
| | 705 |
| — |
| | — |
| | 426 |
| | 426 |
|
Partnerships/joint ventures6 | — |
| | — |
| | — |
| | 396 |
| | 396 |
| — |
| | — |
| | 434 |
| | 434 |
|
Other investment entities7 | — |
| | — |
| | — |
| | 262 |
| | 262 |
| — |
| | — |
| | 236 |
| | 236 |
|
Registered investment companies8 | 140 |
| | — |
| | — |
| | — |
| | 140 |
| 112 |
| | — |
| | 2 |
| | 114 |
|
| Interest-bearing cash | 9 |
| | — |
| | — |
| | — |
| | 9 |
| 2 |
| | — |
| | — |
| | 2 |
|
| Other | — |
| | 106 |
| | — |
| | — |
| | 106 |
| — |
| | 73 |
| | — |
| | 73 |
|
| Total | $ | 1,051 |
| | $ | 1,300 |
| | $ | — |
| | $ | 1,363 |
| | $ | 3,714 |
| $ | 697 |
| | $ | 1,598 |
| | $ | 1,098 |
| | $ | 3,393 |
|
| Receivables and payables, net | |
| | |
| | | | |
| | (98 | ) | |
| | |
| | |
| | (72 | ) |
| Net plan assets available for benefits | |
| | |
| | | | |
| | $ | 3,616 |
| |
| Combined net plan assets available for benefits | | |
| | |
| | |
| | 3,321 |
|
| SCE's share of net plan assets | | | | | | | | | $ | 3,390 |
| | | | | | | $ | 3,124 |
|
| |
1 | These investments are measured at fair value using the net asset value per share practical expedient and have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the net plan assets available for benefits. |
| |
2 | Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relates to the Federal National Mortgage Association and the Federal Home Loan Mortgage Corporation. |
| |
3 | Corporate stocks are diversified. At December 31, 20182019 and 2017,2018, respectively, performance for actively managed separate accounts is primarily benchmarked against the Russell Indexes (43%(40%) and (54%(43%) and Morgan Stanley Capital International (MSCI) index (57%(60%) and (46%(57%). |
| |
4 | Corporate bonds are diversified. At December 31, 20182019 and 2017,2018, respectively, this category includes $60$45 million and $65$60 million for collateralized mortgage obligations and other asset backed securities. |
| |
5 | At December 31, 20182019 and 2017,2018, respectively, the common/collective assets were invested in equity index funds that seek to track performance of the Standard and Poor's 500 Index (43%(35% and 41%43%) and Russell 1000 indexes (14%(17% and 15%14%). In addition, at December 31, 2019 and 2018, respectively, 28% and 2017, respectively, 21% and 15% of the assets in this category are in index funds which seek to track performance in the MSCI All Country World Index exUS and 15%12% and 25%15% of this category are in non-index U.S. equity fund, which is actively managed. |
| |
6 | At December 31, 2019 and 2018, respectively, 51% and 2017, respectively, 50% and 55% are invested in private equity funds with investment strategies that include branded consumer products, clean technology and California geographic focus companies, 30%17% and 20%1% are invested in ABS including distressed mortgages and commercial and residential loans, 19% and 16% are invested in publicly traded fixed income securities, and 8% and 30% are invested in a broad range of financial assets in all global markets, and 16% and 23% are invested in publicly traded fixed income securities. markets. |
| |
7 | OtherAt both December 31, 2019 and 2018, other investment entities were primarily invested in (1) emerging market equity securities and (2) domestic mortgage backed securities. In addition, other investment entities were also invested in a hedge fund that invests through liquid instruments in a global diversified portfolio of equity, fixed income, interest rate, foreign currency and commodities markets and (3) domestic mortgage backed securities.at December 31, 2018. |
| |
8 | Level 1 registered investment companies primarily consisted of a global equity mutual fund which seeks to outperform the MSCI World Total Return Index. |
At December 31, 20182019 and 2017,2018, respectively, approximately 61%56% and 67%61% of the publicly traded equity investments, including equities in the common/collective funds, were located in the United States.
Postretirement Benefits Other than Pensions
The following table sets forth the VEBA Trust assets for Edison International and SCE that were accounted for at fair value as of December 31, 20182019 by asset class and level within the fair value hierarchy:
| | | (in millions) | Level 1 | | Level 2 | | Level 3 | | NAV1 | | Total | Level 1 | | Level 2 | | NAV1 | | Total |
U.S. government and agency securities2 | $ | 322 |
| | $ | 49 |
| | $ | — |
| | $ | — |
| | $ | 371 |
| $ | 386 |
| | $ | 63 |
| | $ | — |
| | $ | 449 |
|
Corporate stocks3 | 204 |
| | — |
| | — |
| | — |
| | 204 |
| 242 |
| | 2 |
| | — |
| | 244 |
|
Corporate notes and bonds4 | — |
| | 832 |
| | — |
| | — |
| | 832 |
| — |
| | 885 |
| | — |
| | 885 |
|
Common/collective funds5 | — |
| | — |
| | — |
| | 495 |
| | 495 |
| — |
| | — |
| | 652 |
| | 652 |
|
Partnerships6 | — |
| | — |
| | — |
| | 89 |
| | 89 |
| — |
| | — |
| | 68 |
| | 68 |
|
Registered investment companies7 | 38 |
| | — |
| | — |
| | — |
| | 38 |
| 66 |
| | — |
| | — |
| | 66 |
|
| Interest bearing cash | 22 |
| | — |
| | — |
| | — |
| | 22 |
| — |
| | 17 |
| | — |
| | 17 |
|
Other8 | 5 |
| | 99 |
| | — |
| | — |
| | 104 |
| 2 |
| | 101 |
| | — |
| | 103 |
|
| Total | $ | 591 |
| | $ | 980 |
| | $ | — |
| | $ | 584 |
| | $ | 2,155 |
| $ | 696 |
| | $ | 1,068 |
| | $ | 720 |
| | $ | 2,484 |
|
| Receivables and payables, net | |
| | |
| | | | |
| | (22 | ) | |
| | |
| | |
| | (19 | ) |
| Combined net plan assets available for benefits | |
| | |
| | | | |
| | $ | 2,133 |
| |
| | |
| | |
| | 2,465 |
|
| SCE's share of net plan assets | | | | | | | | $ | 2,464 |
|
The following table sets forth the VEBA Trust assets for Edison International and SCE that were accounted for at fair value as of December 31, 20172018 by asset class and level within the fair value hierarchy: | | | (in millions) | Level 1 | | Level 2 | | Level 3 | | NAV1 | | Total | Level 1 | | Level 2 | | NAV1 | | Total |
U.S. government and agency securities2 | $ | 398 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| | $ | 431 |
| $ | 322 |
| | $ | 49 |
| | $ | — |
| | $ | 371 |
|
Corporate stocks3 | 254 |
| | — |
| | — |
| | — |
| | 254 |
| 204 |
| | — |
| | — |
| | 204 |
|
Corporate notes and bonds4 | — |
| | 845 |
| | — |
| | — |
| | 845 |
| — |
| | 832 |
| | — |
| | 832 |
|
Common/collective funds5 | — |
| | — |
| | — |
| | 569 |
| | 569 |
| — |
| | — |
| | 495 |
| | 495 |
|
Partnerships6 | — |
| | — |
| | — |
| | 82 |
| | 82 |
| — |
| | — |
| | 89 |
| | 89 |
|
Registered investment companies7 | 37 |
| | — |
| | — |
| | — |
| | 37 |
| 38 |
| | — |
| | — |
| | 38 |
|
| Interest bearing cash | 42 |
| | — |
| | — |
| | — |
| | 42 |
| 22 |
| | — |
| | — |
| | 22 |
|
Other8 | 5 |
| | 84 |
| | — |
| | — |
| | 89 |
| 5 |
| | 99 |
| | — |
| | 104 |
|
| Total | $ | 736 |
| | $ | 962 |
| | $ | — |
| | $ | 651 |
| | $ | 2,349 |
| $ | 591 |
| | $ | 980 |
| | $ | 584 |
| | $ | 2,155 |
|
| Receivables and payables, net | |
| | |
| | | | |
| | (19 | ) | |
| | |
| | |
| | (22 | ) |
| Combined net plan assets available for benefits | |
| | |
| | | | |
| | $ | 2,330 |
| |
| | |
| | |
| | $ | 2,133 |
|
| |
1 | These investments are measured at fair value using the net asset value per share practical expedient and have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the net plan assets available for benefits. |
| |
2 | Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relates to the Federal Home Loan Mortgage Corporation and the Federal National Mortgage Association. |
| |
3 | Corporate stock performance for actively managed separate accounts is primarily benchmarked against the Russell Indexes (67%(68%and64%67%) and the MSCI All Country World Index (33%(32% and 36%33%) for 2019 and 2018, and 2017, respectively. |
| |
4 | Corporate notes and bonds are diversified and include approximately $59$49 million and $36$59 million for commercial collateralized mortgage obligations and other asset backed securities at December 31, 20182019 and 2017,2018, respectively. |
| |
5 | At both December 31, 2019 and 2018, and 2017, respectively, 74% and 75% of the common/collective assets are invested in index funds which seek to track performance in the MSCI All Country World Index Investable Market Index and 19% and 17% are invested in a non-index U.S. equity fund which is actively managed. The remaining assets in this category are primarily invested in emerging market fund. |
| |
6 | At December 31, 2019 and 2018, respectively, 55% and 2017, respectively, 48% and 56% of the partnerships are invested in private equity and venture capital funds. Investment strategies for these funds include branded consumer products, clean and information technology and healthcare. 34%28% and 33% are invested in a broad range of financial assets in all global markets. 17% and 9% of the remaining partnerships category are invested in asset backed securities including distressed mortgages, distressed companies and commercial and residential loans and debt and equity of banks. 15% and 34% are invested in a broad range of financial assets in all global markets. |
| |
7 | At both December 31, 20182019 and 2017,2018, registered investment companies were primarily invested in (1) a money market fund, (2) exchange rate trade funds which seek to track performance of MSCI Emerging Market Index, Russell 2000 Index and international small cap equities. |
| |
8 | Other includes $58$66 million and $60$58 million of municipal securities at December 31, 20182019 and 2017,2018, respectively. |
At December 31, 20182019 and 2017,2018, respectively, approximately 64%65% and 61%64% of the publicly traded equity investments, including equities in the common/collective funds, were located in the United States.
Stock-Based Compensation
Edison International maintains a shareholder-approved incentive plan (the 2007"2007 Performance Incentive Plan)Plan") that includes stock-based compensation. The maximum number of shares of Edison International's common stock authorized to be issued or transferred pursuant to awards under the 2007 Performance Incentive Plan, as amended, is 66approximately 71 million shares, plus the number of any shares subject to awards issued under Edison International's prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued.shares. As of December 31, 2018,2019, Edison International had approximately 2826 million shares remaining available for new award grants under its stock-based compensation plans.
The following table summarizes total expense and tax benefits associated with stock basedstock-based compensation:
| | | | Edison International | | SCE | Edison International | | SCE |
| | Years ended December 31, | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
Stock-based compensation expense1: | | | | | | | | | | | | | | | | | | | | | | |
| Stock options | $ | 11 |
| | $ | 14 |
| | $ | 14 |
| | $ | 6 |
| | $ | 8 |
| | $ | 7 |
| $ | 13 |
| | $ | 11 |
| | $ | 14 |
| | $ | 7 |
| | $ | 6 |
| | $ | 8 |
|
| Performance shares | 1 |
| | 2 |
| | 13 |
| | 1 |
| | 2 |
| | 6 |
| 8 |
| | 1 |
| | 2 |
| | 4 |
| | 1 |
| | 2 |
|
| Restricted stock units | 7 |
| | 6 |
| | 6 |
| | 4 |
| | 3 |
| | 3 |
| 6 |
| | 7 |
| | 6 |
| | 3 |
| | 4 |
| | 3 |
|
| Other | 2 |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
| 2 |
| | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Total stock-based compensation expense | $ | 21 |
| | $ | 23 |
| | $ | 34 |
| | $ | 11 |
| | $ | 13 |
| | $ | 16 |
| 29 |
| | 21 |
| | 23 |
| | 14 |
| | 11 |
| | 13 |
|
| Income tax benefits related to stock compensation expense | $ | 6 |
| | $ | 72 |
| | $ | 41 |
| | $ | 3 |
| | $ | 15 |
| | $ | 20 |
| $ | 10 |
| | $ | 6 |
| | $ | 72 |
| | $ | 6 |
| | $ | 3 |
| | $ | 15 |
|
| |
1 | Reflected in "Operation and maintenance" on Edison International's and SCE's consolidated statements of income. |
Stock Options
Under the 2007 Performance Incentive Plan, Edison International has granted stock options at exercise prices equal to the closing price at the grant date. Edison International may grant stock options and other awards related to, or with a value derived from, its common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service with expense recognized evenly over the requisite service period,in equal annual increments, except for awards granted to retirement-eligible participants, as discussed in "Stock-Based Compensation" in Note 1. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.which vest on an accelerated basis.
The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table:
|
| | | | | |
| | Years ended December 31, |
| | 2019 | | 2018 | | 2017 |
| Expected terms (in years) | 5.5 | | 5.7 | | 5.7 |
| Risk-free interest rate | 1.6% - 2.3% | | 2.6% - 3.0% | | 2.1% - 2.3% |
| Expected dividend yield | 3.3% - 4.0% | | 3.6% - 4.3% | | 2.7% - 3.8% |
| Weighted average expected dividend yield | 3.9% | | 3.8% | | 2.7% |
| Expected volatility | 21.7% - 24.1% | | 20.9% - 21.9% | | 17.8% - 20.9% |
| Weighted average volatility | 21.8% | | 20.9% | | 17.9% |
|
| | | | | |
| | Years ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Expected terms (in years) | 5.7 | | 5.7 | | 5.9 |
| Risk-free interest rate | 2.6% - 3.0% | | 2.1% - 2.3% | | 1.2% – 2.2% |
| Expected dividend yield | 3.6% - 4.3% | | 2.7% - 3.8% | | 2.5% – 3.0% |
| Weighted-average expected dividend yield | 3.8% | | 2.7% | | 2.9% |
| Expected volatility | 20.9% - 21.9% | | 17.8% - 20.9% | | 17.2% – 17.5% |
| Weighted-average volatility | 20.9% | | 17.9% | | 17.4% |
The expected term represents the period of time for which the options are expected to be outstanding and is primarily based on historical exercise and post-vesting cancellation experience and stock price history. The risk-free interest rate for periods within the contractual life of the option is based on a zero couponzero-coupon U.S. Treasury STRIPS (separate trading of registered interest and principal of securities) whose maturity equals the option's expected term on the measurement date. Expected volatility is based on the historical volatility of Edison International's common stock for the length of the option's expected term for 2018.2019. The volatility period used was 6866 months, 68 months and 7168 months at December 31, 2019, 2018 2017 and 2016,2017, respectively.
The following is a summary of the status of Edison International's stock options:
|
| | | | | | | | | | | | |
| | | | Weighted Average | | |
| | Stock Options | | Exercise Price | | Remaining Contractual Term (Years) | | Aggregate Intrinsic Value (in millions) |
| Edison International: | | | | | | | |
| Outstanding at December 31, 2018 | 8,833,610 |
| | $ | 59.81 |
| | | | |
|
| Granted | 1,928,314 |
| | 62.79 |
| | | | |
|
| Forfeited or expired | (201,643 | ) | | 67.38 |
| | | | |
|
Exercised1 | (1,281,604 | ) | | 45.26 |
| | | | |
|
| Outstanding at December 31, 2019 | 9,278,677 |
| | 62.27 |
| | 6.28 | | |
|
| Vested and expected to vest at December 31, 2019 | 9,151,143 |
| | 62.27 |
| | 6.25 | | $ | 125 |
|
| Exercisable at December 31, 2019 | 5,378,183 |
| | $ | 60.32 |
| | 4.91 | | $ | 84 |
|
| SCE: | | | | | | | |
| Outstanding at December 31, 2018 | 5,037,185 |
| | $ | 57.84 |
| | | | |
|
| Granted | 1,047,247 |
| | 62.91 |
| | | | |
|
| Forfeited or expired | (182,822 | ) | | 66.83 |
| | | | |
|
Exercised1 | (878,084 | ) | | 44.67 |
| | | | |
|
| Affiliate transfers, net | (88,824 | ) | | 53.14 |
| | | | |
| Outstanding at December 31, 2019 | 4,934,702 |
| | 61.01 |
| | 6.05 | | |
|
| Vested and expected to vest at December 31, 2019 | 4,871,685 |
| | 60.98 |
| | 6.01 | | $ | 73 |
|
| Exercisable at December 31, 2019 | 2,945,726 |
| | $ | 58.28 |
| | 4.62 | | $ | 52 |
|
|
| | | | | | | | | | | | |
| | | | Weighted-Average | | |
| | Stock options | | Exercise Price | | Remaining Contractual Term (Years) | | Aggregate Intrinsic Value (in millions) |
| Edison International: | | | | | | | |
| Outstanding at December 31, 2017 | 7,822,565 |
| | $ | 58.98 |
| | | | |
|
| Granted | 1,785,538 |
| | 60.83 |
| | | | |
|
| Forfeited or expired | (222,392 | ) | | 69.59 |
| | | | |
|
Exercised1 | (552,101 | ) | | 47.33 |
| | | | |
|
| Outstanding at December 31, 2018 | 8,833,610 |
| | 59.81 |
| | 6.13 | | |
|
| Vested and expected to vest at December 31, 2018 | 8,726,445 |
| | 59.76 |
| | 6.10 | | $ | 34 |
|
| Exercisable at December 31, 2018 | 5,145,292 |
| | $ | 54.77 |
| | 4.74 | | $ | 34 |
|
| SCE: | | | | | | | |
| Outstanding at December 31, 2017 | 4,445,702 |
| | $ | 56.46 |
| | | | |
|
| Granted | 960,240 |
| | 60.86 |
| | | | |
|
| Forfeited or expired | (125,260 | ) | | 68.90 |
| | | | |
|
Exercised1 | (288,302 | ) | | 41.57 |
| | | | |
|
| Transfers, net | 44,805 |
| | 55.74 |
| | | | |
| Outstanding at December 31, 2018 | 5,037,185 |
| | 57.84 |
| | 5.79 | | |
|
| Vested and expected to vest at December 31, 2018 | 4,982,445 |
| | 57.77 |
| | 5.75 | | $ | 25 |
|
| Exercisable at December 31, 2018 | 3,089,466 |
| | $ | 52.15 |
| | 4.33 | | $ | 25 |
|
1 Edison International and SCE recognized tax benefits of $3$7 million and $2$5 million, respectively, from stock options exercised in 2018.2019.
At December 31, 2018,2019, total unrecognized compensation cost related to stock options and the weighted-averageweighted average period the cost is expected to be recognized are as follows:
|
| | | | | | | |
| | Edison International | | SCE |
| Unrecognized compensation cost, net of expected forfeitures (in millions) | $ | 18 |
| | $ | 9 |
|
| Weighted average period (in years) | 2.4 |
| | 2.4 |
|
|
| | | | | | | |
| (in millions) | Edison International | | SCE |
| Unrecognized compensation cost, net of expected forfeitures | $ | 15 |
| | $ | 8 |
|
| Weighted-average period (in years) | 2.4 |
| | 2.2 |
|
Supplemental Data on Stock Options
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions, except per award amounts) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Stock options: | | | | | | | | | | | |
| Weighted average grant date fair value per option granted | $ | 8.80 |
| | $ | 8.21 |
| | $ | 10.65 |
| | $ | 8.83 |
| | $ | 8.22 |
| | $ | 10.63 |
|
| Fair value of options vested | 14 |
| | 14 |
| | 11 |
| | 7 |
| | 7 |
| | 5 |
|
| Value of options exercised | 27 |
| | 10 |
| | 126 |
| | 19 |
| | 7 |
| | 29 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions, except per award amounts) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Stock options: | | | | | | | | | | | |
| Weighted average grant date fair value per option granted | $ | 8.21 |
| | $ | 10.65 |
| | $ | 7.38 |
| | $ | 8.22 |
| | $ | 10.63 |
| | $ | 7.50 |
|
| Fair value of options vested | 14 |
| | 11 |
| | 11 |
| | 7 |
| | 5 |
| | 5 |
|
| Value of options exercised | 10 |
| | 126 |
| | 84 |
| | 7 |
| | 29 |
| | 41 |
|
Performance Shares
A target number of contingent performance shares were awarded to executives in March 2019, 2018 2017 and 20162017 and vest at December 31, 2021, 2020 2019 and 2018,2019, respectively. The vesting of the grants is dependent upon market and financial performance and service conditions as defined in the grants for each of the years. The number of performance shares earned
from each year's grants could range from zero to twice the target number (plus additional units credited as dividend equivalents).
equivalents). Performance shares that were granted during 2016 to 2018 are settled solely in cash and are classified as a share-based liability award. Performance shares awarded, beginning in 2019, will be settled in common stock and will be classified as share-based equity awards. The fair value of these shares granted during 2016 to 2018 is re-measured at each reporting period, and the related compensation expense is adjusted. Performance shares expense is recognized ratably over the requisite service period based on the fair values determined (subject to the adjustments discussed above), except for awards granted to retirement-eligible participants.
The fair value of market condition performance shares is determined using a Monte Carlo simulation valuation model for the total shareholder return. The fair value of financial performance condition performance shares is determined (i) at grant as the target number of shares (which Edison International determined to be the probable outcome) valued at the closing price on the grant date of Edison International common stock and (ii) subsequently using Edison International's earnings per share compared to pre-established targets.
The following is a summary of the status of Edison International's nonvested performance shares:
|
| | | | | | | | | | | | | |
| | Equity Awards | | Liability Awards |
| | Shares | | Weighted Average
Fair Value | | Shares | | Weighted Average
Fair Value |
| Edison International: | | | | | | | |
| Nonvested at December 31, 2018 | — |
| | $ | — |
| | 193,438 |
| | $ | 42.81 |
|
| Granted | 124,183 |
| | | | — |
| | |
| Forfeited | (4,340 | ) | | | | (38,439 | ) | | |
Vested1 | — |
| | | | (41,813 | ) | |
|
|
| Nonvested at December 31, 2019 | 119,843 |
| | $ | 66.03 |
| | 113,186 |
| | $ | 67.30 |
|
| SCE: | | | | | | | |
| Nonvested at December 31, 2018 | — |
| | $ | — |
| | 101,858 |
| | $ | 42.96 |
|
| Granted | 67,512 |
| | | | — |
| | |
| Forfeited | (4,340 | ) | | | | (21,641 | ) | | |
Vested1 | — |
| | | | (21,035 | ) | |
|
|
| Affiliate transfers, net | — |
| | | | (783 | ) | | |
| Nonvested at December 31, 2019 | 63,172 |
| | $ | 66.27 |
| | 58,399 |
| | $ | 67.34 |
|
|
| | | | | | |
| | Shares | | Weighted-Average Fair Value |
| Edison International: | | | |
| Nonvested at December 31, 2017 | 179,122 |
| | $ | 63.85 |
|
| Granted | 119,345 |
| | |
|
| Forfeited | (51,281 | ) | | |
Vested1 | (53,748 | ) | | |
|
| Nonvested at December 31, 2018 | 193,438 |
| | 42.81 |
|
| SCE: | | | |
| Nonvested at December 31, 2017 | 88,722 |
| | $ | 64.01 |
|
| Granted | 64,335 |
| | |
|
| Forfeited | (27,331 | ) | | |
Vested1 | (24,574 | ) | | |
|
| Affiliate transfers, net | 706 |
| | |
| Nonvested at December 31, 2018 | 101,858 |
| | 42.96 |
|
| |
1 | Relates to performance shares that will be paid in 20192020 as performance targets were met at December 31, 2018.2019. |
Restricted Stock Units
Restricted stock units were awarded to executives in March 2019, 2018 2017 and 20162017 and vest and become payable on January 3, 2022, January 4, 2021 and January 2, 2020, and January 2, 2019, respectively. Each restricted stock unit awarded includes a dividend equivalent feature and is a contractual right to receive one share of Edison International common stock, if vesting requirements are satisfied. The vesting of Edison International's restricted stock units is dependent upon continuous service through the end of the vesting period, except for awards granted to retirement-eligible participants.participants, which vest on an accelerated basis.
The following is a summary of the status of Edison International's nonvested restricted stock units:
|
| | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Restricted Stock Units | | Weighted Average
Grant Date
Fair Value | | Restricted Stock Units | | Weighted Average
Grant Date
Fair Value |
| Nonvested at December 31, 2018 | 291,786 |
| | $ | 68.11 |
| | 147,826 |
| | $ | 68.08 |
|
| Granted | 135,168 |
| | 62.80 |
| | 73,937 |
| | 62.93 |
|
| Forfeited | (10,456 | ) | | 65.82 |
| | (9,564 | ) | | 65.53 |
|
| Vested | (104,816 | ) | | 67.43 |
| | (52,028 | ) | | 67.15 |
|
| Affiliate transfers, net | — |
| | — |
| | (186 | ) | | — |
|
| Nonvested at December 31, 2019 | 311,682 |
| | $ | 66.11 |
| | 159,985 |
| | $ | 66.16 |
|
|
| | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Restricted Stock Units | | Weighted-Average Grant Date Fair Value | | Restricted Stock Units | | Weighted-Average Grant Date Fair Value |
| Nonvested at December 31, 2017 | 303,051 |
| | $ | 69.52 |
| | 141,418 |
| | $ | 69.96 |
|
| Granted | 120,606 |
| | 60.83 |
| | 64,919 |
| | 60.87 |
|
| Forfeited | (8,225 | ) | | 68.76 |
| | (7,973 | ) | | 68.97 |
|
| Vested | (123,646 | ) | | 64.43 |
| | (51,667 | ) | | 64.07 |
|
| Affiliate transfers, net | — |
| | — |
| | 1,129 |
| | 68.64 |
|
| Nonvested at December 31, 2018 | 291,786 |
| | 68.11 |
| | 147,826 |
| | 68.08 |
|
The fair value for each restricted stock unit awarded is determined as the closing price of Edison International common stock on the grant date.
Note 10. Investments
Nuclear Decommissioning Trusts
Future decommissioning costs related to SCE's nuclear assets are expected to be funded from independent decommissioning trusts.
The following table sets forth amortized cost and fair value of the trust investments (see Note 4 for a discussion of fair value of the trust investments):
|
| | | | | | | | | | | | | | | | | |
| | Longest Maturity Date | | Amortized Cost | | Fair Value |
| | | December 31, |
| (in millions) | | 2019 | | 2018 | | 2019 | | 2018 |
| Stocks | — | | N/A |
| | N/A |
| | $ | 1,765 |
| | $ | 1,381 |
|
| Municipal bonds | 2057 | | 822 |
| | 665 |
| | 970 |
| | 767 |
|
| U.S. government and agency securities | 2067 | | 996 |
| | 1,193 |
| | 1,115 |
| | 1,288 |
|
| Corporate bonds | 2068 | | 597 |
| | 573 |
| | 679 |
| | 611 |
|
Short-term investments and receivables/payables1 | One-year | | 32 |
| | 70 |
| | 33 |
| | 73 |
|
| Total | | | $ | 2,447 |
| | $ | 2,501 |
| | $ | 4,562 |
| | $ | 4,120 |
|
|
| | | | | | | | | | | | | | | | | |
| | Longest Maturity Date | | Amortized Cost | | Fair Value |
| | | December 31, |
| (in millions) | | 2018 | | 2017 | | 2018 | | 2017 |
| Stocks | — | | * |
| | $ | 236 |
| | $ | 1,381 |
| | $ | 1,596 |
|
| Municipal bonds | 2057 | | 665 |
| | 643 |
| | 767 |
| | 768 |
|
| U.S. government and agency securities | 2067 | | 1,193 |
| | 1,235 |
| | 1,288 |
| | 1,319 |
|
| Corporate bonds | 2050 | | 573 |
| | 579 |
| | 611 |
| | 643 |
|
Short-term investments and receivables/payables1 | One-year | | 70 |
| | 110 |
| | 73 |
| | 114 |
|
| Total | | | $ | 2,501 |
| | $ | 2,803 |
| | $ | 4,120 |
| | $ | 4,440 |
|
* Effective January 1, 2018, SCE adopted an accounting standards update related to the classification and measurement of financial instruments in which equity investments are measured at fair value. See Note 1 for further information.
| |
1 | Short-term investments include $71$41 million and $29$71 million of repurchase agreements payable by financial institutions which earn interest, are fully secured by U.S. Treasury securities and mature by January 2, 20192020 and January 2, 20182019 as of December 31, 2019 and 2018, and 2017, respectively. |
Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Unrealized holding gains, net of losses, were $1.4$1.8 billion and $1.6$1.4 billion at December 31, 20182019 and 2017,2018, respectively, and other-than-temporary impairments of $170were $160 million and $143$170 million at the respective periods.
Trust assets are used to pay income taxes. Deferred tax liabilities related to net unrealized gains at December 31, 20182019 were $323$449 million. Accordingly, the fair value of trust assets available to pay future decommissioning costs, net of deferred income taxes, totaled $3.8$4.1 billion at December 31, 2018.2019.
The following table summarizes the gains and (losses)losses for the trust investments:
|
| | | | | | | | | |
| | December 31, |
| (in millions) | 2019 | 2018 | 2017 |
| Gross realized gains | $ | 87 |
| $ | 134 |
| $ | 244 |
|
| Gross realized losses | (2 | ) | (27 | ) | (23 | ) |
| Net unrealized gains (losses) for equity securities | 343 |
| (233 | ) | 142 |
|
|
| | | | | | | | | |
| | December 31, |
| (in millions) | 2018 | 2017 | 2016 |
| Gross realized gains | $ | 134 |
| $ | 244 |
| $ | 92 |
|
| Gross realized losses | (27 | ) | (23 | ) | (19 | ) |
| Net unrealized (losses) gains for equity securities | (233 | ) | 142 |
| 75 |
|
Due to regulatory mechanisms, changes in assets of the trusts from income or loss items have no impact on operating revenue or earnings.
Note 11. Regulatory Assets and Liabilities
Included in SCE's regulatory assets and liabilities are regulatory balancing accounts. CPUC authorizedCPUC-authorized balancing account mechanisms require SCE to refund or recover any differences between forecasted and actual costs. The CPUC has authorized balancing accounts for specified costs or programs such as fuel, purchased-power,purchased power, demand-side management programs, nuclear decommissioning and public purpose programs. Certain of these balancing accounts include a return on rate base of 7.61% in both 2019 and 7.90% in 2018, and 2017, respectively. The CPUC authorizes the use of a balancing account to recover from or refund to customers differences in revenue resulting from actual and forecasted electricity sales.
Amounts included in regulatory assets and liabilities are generally recorded with corresponding offsets to the applicable income statement accounts.
Regulatory Assets
SCE's regulatory assets included on the consolidated balance sheets are:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Current: | | | |
| Regulatory balancing and memorandum accounts | $ | 798 |
| | $ | 814 |
|
Power contracts1 | 189 |
| | 305 |
|
| Other | 22 |
| | 14 |
|
| Total current | 1,009 |
| | 1,133 |
|
| Long-term: | | | |
| Deferred income taxes, net of liabilities | 4,026 |
| | 3,589 |
|
| Pension and other postretirement benefits | 87 |
| | 271 |
|
Power contracts1 | 434 |
| | 700 |
|
Unamortized investments, net of accumulated amortization2 | 119 |
| | 118 |
|
| Unamortized loss on reacquired debt | 142 |
| | 153 |
|
| Regulatory balancing and memorandum accounts | 981 |
| | 360 |
|
| Environmental remediation | 237 |
| | 134 |
|
| Other | 62 |
| | 55 |
|
| Total long-term | 6,088 |
| | 5,380 |
|
| Total regulatory assets | $ | 7,097 |
|
| $ | 6,513 |
|
|
| | | | | | | |
| | December 31, |
| (in millions) | 2018 | | 2017 |
| Current: | | | |
| Regulatory balancing accounts | $ | 814 |
| | $ | 484 |
|
Power contracts1 | 305 |
| | 203 |
|
| Other | 14 |
| | 16 |
|
| Total current | 1,133 |
| | 703 |
|
| Long-term: | | | |
| Deferred income taxes, net of liabilities | 3,589 |
| | 3,143 |
|
| Pensions and other postretirement benefits | 271 |
| | 271 |
|
Power contracts1 | 700 |
| | 799 |
|
Unamortized investments, net of accumulated amortization2 | 118 |
| | 123 |
|
San Onofre3 | — |
| | 72 |
|
| Unamortized loss on reacquired debt | 153 |
| | 168 |
|
| Regulatory balancing accounts | 360 |
| | 143 |
|
| Environmental remediation | 134 |
| | 144 |
|
| Other | 55 |
| | 51 |
|
| Total long-term | 5,380 |
| | 4,914 |
|
| Total regulatory assets | $ | 6,513 |
|
| $ | 5,617 |
|
| |
1 | In 2018, SCE amended the termination date of two2 power purchase agreements. As a result of this amendment, SCE is required to make early termination payments of $100totaling $206 million in 2019, $77 million in 2020 andby 2021. The unpaid portion of $29 million in 2021, whichand $206 million were reflected as a regulatory asset in the consolidated balance sheets as of December 31, 2018.2019 and 2018, respectively. |
| |
2 | Relates to a regulatory asset that earns a rate of return. See below for further information. |
| |
3In accordance with the accounting standards applicable to rate-regulated enterprises, SCE defers costs as regulatory assets that are probable of future recovery from customers and has recorded regulatory assets for these incremental costs at December 31, 2019. While SCE believes such costs are probable of future recovery, there is no assurance that SCE will collect all amounts currently deferred as regulatory assets. | In accordance with the Revised San Onofre Settlement Agreement, SCE wrote down the San Onofre regulatory asset in 2017 and applied $72 million of the U.S. Department of Energy ("DOE") proceeds, previously reflected as a regulatory liability in the DOE litigation memorandum account, against the remaining San Onofre regulatory asset during the third quarter of 2018. See Note 12 for further information. |
SCE's regulatory assets related to power contracts primarily represent derivative contracts that were designated as normal purchasepurchases and normal salesales contracts. The liabilities for these power contracts are amortized over the remaining contract terms, approximately 2 to 5 years. For further information, see Note 1.
SCE's regulatory assets related to deferred income taxes represent tax benefits passed through to customers. The CPUC requires SCE to flow through certain deferred income tax benefits to customers by reducing electricity rates, thereby deferring recovery of such amounts to future periods. Based on current regulatory ratemaking and income tax laws, SCE expects to recover its regulatory assets related to deferred income taxes over the life of the assets that give rise to the accumulated deferred income taxes, approximately from 1 to 60 years. As a result of Tax Reform, SCE re-measured its deferred tax assets and liabilities as of December 31, 2017. For further information, see Note 8.
SCE's regulatory assets related to pensionspension and other post-retirement plans represent the unfunded net loss and prior service costs of the plans (seeplans. This amount is being recovered through rates charged to customers. See "Pension Plans and Postretirement Benefits Other than Pensions" discussion in Note 9). This amount is being recovered through rates charged to customers.9.
SCE has long-term unamortized investments which include nuclear assets related to Palo Verde and the beyond the meter program. Nuclear assets related to Palo Verde and the beyond the meter program are expected to be recovered by 20472044 and 2027, respectively, and both earned returns of 7.61% in 20182019 and 7.90% in 2017.2018.
SCE's net regulatory asset related to its unamortized loss on reacquired debt will be recovered over the original amortization period of the reacquired debt over periods ranging from 10 to 3540 years or the life of the new issueissuance if the debt is refunded or refinanced.
SCE's regulatory assets related to environmental remediation representsrepresent a portion of the costs incurred at certain sites that SCE is allowed to recover through customer rates. See "Environmental Remediation" discussed in Note 12.
Regulatory Liabilities
SCE's regulatory liabilities included on the consolidated balance sheets are:
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Current: | | | |
| Regulatory balancing and memorandum accounts | $ | 883 |
| | $ | 1,080 |
|
| Energy derivatives | 80 |
| | 158 |
|
2018 GRC1 | — |
| | 274 |
|
| Other | 9 |
| | 20 |
|
| Total current | 972 |
| | 1,532 |
|
| Long-term: | | | |
| Costs of removal | 2,674 |
| | 2,769 |
|
| Re-measurement of deferred taxes | 2,424 |
| | 2,776 |
|
| Recoveries in excess of ARO liabilities | 1,569 |
| | 1,130 |
|
Regulatory balancing and memorandum accounts | 1,261 |
| | 1,344 |
|
| Other postretirement benefits | 416 |
| | 185 |
|
Other1 | 41 |
| | 125 |
|
| Total long-term | 8,385 |
| | 8,329 |
|
| Total regulatory liabilities | $ | 9,357 |
| | $ | 9,861 |
|
|
| | | | | | | |
| | December 31, |
| (in millions) | 2018 | | 2017 |
| Current: | | | |
| Regulatory balancing accounts | $ | 1,080 |
| | $ | 1,009 |
|
| Energy derivatives | 158 |
| | 74 |
|
Other1 | 294 |
| | 38 |
|
| Total current | 1,532 |
| | 1,121 |
|
| Long-term: | | | |
| Costs of removal | 2,769 |
| | 2,741 |
|
| Re-measurement of deferred taxes | 2,776 |
| | 2,892 |
|
| Recoveries in excess of ARO liabilities | 1,130 |
| | 1,575 |
|
| Regulatory balancing accounts | 1,344 |
| | 1,316 |
|
| Other postretirement benefits | 185 |
| | 26 |
|
Other1 | 125 |
| | 64 |
|
| Total long-term | 8,329 |
| | 8,614 |
|
| Total regulatory liabilities | $ | 9,861 |
| | $ | 9,735 |
|
| |
1 | During 2018, SCE recorded CPUC revenue based on the 2017 authorized revenue requirement adjusted for the July 2017 cost of capital decision and Tax Reform pending the outcome of the 2018 GRC. SCE recorded regulatory liabilities primarily associated with these adjustments. The CPUC has authorizedIn May 2019, these regulatory liabilities were reversed due to the establishmentadoption of a2018 GRC memorandum account, which will make the 2018 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2018.final decision. For further information, see Note 1. |
SCE's regulatory liabilities related to energy derivatives are primarily an offset to unrealized gains on derivatives.
SCE's regulatory liabilities related to costs of removal represent differences between asset removal costs recorded and amounts collected in rates for those costs.
As a result of Tax Reform, SCE's deferred tax assets and liabilities were re-measured at December 31, 2017, resulting in an increase in regulatory liabilities which is subjectliabilities. In February 2019, the CPUC issued a final resolution holding that customers are only entitled to change based on the outcomere-measurement of deferred taxes that were included when setting rates (i.e. included in rate base), and that all other deferred tax re-measurements belong to shareholders. As a result of the regulatory process. The regulatory liabilities are generally expected to be refunded to customers overresolution, SCE recorded an income tax benefit of approximately $88 million in the lives of the assets and liabilities that gave rise to the deferred taxes.year 2019. For further information, see Note 8.
SCE's regulatory liabilities related to recoveries in excess of ARO liabilities represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the SCE's nuclear generation facilities. Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust
investments. See Note 10 for further discussion.
Net Regulatory Balancing and Memorandum Accounts
Balancing accounts track amounts that the CPUC or FERC have authorized for recovery. Balancing account over and under collections represent differences between cash collected in current rates for specified forecasted costs and such costs that are actually incurred. Undercollections are recorded as regulatory balancing account assets. Overcollections are recorded as regulatory balancing account liabilities. 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. Memorandum accounts are authorized to track costs for potential future recovery.
Regulatory balancing and memorandum accounts that SCE does not expect to collect or refund in the next 12 months are reflected in the long-term section of the consolidated balance sheets. Regulatory balancing and memorandum accounts that do not have the right of offset are presented gross in the consolidated balance sheets. Under and over collections in balancing accounts and amounts recorded in memorandum accounts typically accrue interest based on a three-month commercial paper rate published by the Federal Reserve.
The following table summarizes the significant components of regulatory balancing and memorandum accounts included in the above tables of regulatory assets and liabilities: |
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Asset (liability) | | | |
Energy resource recovery account1 | $ | (23 | ) | | $ | 815 |
|
Portfolio allocation balancing account1 | 537 |
| | — |
|
New system generation balancing account1 | 85 |
| | (74 | ) |
| Public purpose programs and energy efficiency programs | (1,235 | ) | | (1,200 | ) |
| Base revenue requirement balancing account | (328 | ) | | (628 | ) |
| Tax accounting memorandum account and pole loading balancing account | 17 |
| | 28 |
|
| DOE litigation memorandum account | (35 | ) | | (69 | ) |
| Greenhouse gas auction revenue and low carbon fuel standard revenue | (196 | ) | | (81 | ) |
| FERC balancing accounts | (127 | ) | | (180 | ) |
Wildfire-related memorandum accounts2 | 868 |
| | 272 |
|
| Other | 72 |
| | (133 | ) |
| Liability | $ | (365 | ) | | $ | (1,250 | ) |
|
| | | | | | | |
| | December 31, |
| (in millions) | 2018 | | 2017 |
| Asset (liability) | | | |
Energy resource recovery account1 | $ | 815 |
| | $ | 464 |
|
| New system generation balancing account | (74 | ) | | (197 | ) |
| Public purpose programs and energy efficiency programs | (1,200 | ) | | (1,145 | ) |
Base revenue requirement balancing account2 | (628 | ) | | (200 | ) |
Tax accounting memorandum account and pole loading balancing account2 | 28 |
| | (259 | ) |
| DOE litigation memorandum account | (69 | ) | | (156 | ) |
| Greenhouse gas auction revenue and low carbon fuel standard revenue | (81 | ) | | (46 | ) |
| FERC balancing accounts | (180 | ) | | (205 | ) |
| Catastrophic event memorandum account | 144 |
| | 102 |
|
Wildfire expense memorandum account3 | 128 |
| | — |
|
| Other | (133 | ) | | (56 | ) |
| Liability | $ | (1,250 | ) | | $ | (1,698 | ) |
| |
1 | SCE's cost-recovery mechanism for its fuel and purchased power-related costs is facilitated in three main balancing accounts, the Energy resource recovery accountResource Recovery Account ("ERRA"), the Portfolio Allocation Balancing Account ("PABA") and the New System Generation Balancing Account ("NSGBA"). In May 2019, the CPUC approved a PABA to determine and pro-ratably recover from responsible bundled service and departing load customers the "above-market" costs of all generation resources that are eligible for cost recovery. The ERRA and PABA balancing account isaccounts are subject to a trigger mechanism that allows SCE to request an expeditious rate change if the sum of the ERRA balancing account overcollection or undercollectionbalance and the bundled service customers' pro-rata share of the PABA balance either exceeds 5% of SCE's prior year generation rate revenue or exceeds 4% of SCE's prior year generation rate revenue and SCE does not expect the overcollection or undercollection to fall below 4% within 120 days. For 2019,2020, the 4% and 5% trigger amounts are approximately $213$200 million and $266$250 million, respectively. SCE anticipates to recoverwill begin recovering the combined ERRA, PABA and NSGBA undercollection from customercustomers in rates beginning in April 2019. For further information of ERRA trigger mechanism, see "Business—SCE—Overview of Ratemaking Process."2020, which will be fully recovered in April 2021. |
| |
2 | During 2018, $263 millionThe wildfire-related memorandum accounts regulatory assets represent wildfire-related costs that are probable of 2017 incremental tax benefits were reclassifiedfuture recovery from the tax accounting memorandum accountcustomers, subject to the base revenue requirement balancing account (to be refundeda reasonableness review. The Fire Hazard Prevention Memorandum Account ("FHPMA") is used to customerstrack costs related to fire safety and to implement fire prevention corrective action measures in 2019). |
| |
3
| extreme and very high fire threat areas. The Catastrophic Event Memorandum Account ("CEMA") is used to track costs related to restoring service and damage repair, upon declaration of disasters by state or federal authorities. During 2018, the CPUC established a wildfire expense memorandum accountapproved the establishment of the Wildfire Expense Memorandum Account ("WEMA") to track incremental wildfire insurance costs and uninsured wildfire-related financing, legal and claims costs. In March 2019, the CPUC approved a fire risk mitigation memorandum account to track costs including insurance premiumsrelated to the reduction of fire risk that are incremental to the amount in excess of amountsSCE's any other revenue requirement. In June 2019, the CPUC approved a wildfire mitigation plan memorandum account to track costs incurred to implement SCE's Wildfire Mitigation Plan that ultimately will be approvedare not currently reflected in the 2018 GRC decision. See Note 12 for further information.SCE's revenue requirements. |
In February 2019, the CPUC approved recovery of $107 million of premiums related to a 12-month $300 million wildfire liability insurance policy purchased in December 2017. As a result of this decision, SCE expects to recover these costs in 2019. For further information, see Note 12.
Note 12. Commitments and Contingencies
Power Purchase Agreements
SCE entered into various agreements to purchase power, electric capacity and other energy products. At December 31, 2018,2019, the undiscounted future expected minimum payments for the SCE PPAs (primarily related to renewable energy contracts), which were approved by the CPUC and met other critical contract provisions (including completion of major milestones for construction), were as follows:
|
| | | |
| (in millions) | Total |
| 2020 | $ | 2,796 |
|
2021 1 | 2,777 |
|
| 2022 | 2,729 |
|
| 2023 | 2,457 |
|
| 2024 | 2,160 |
|
| Thereafter | 23,102 |
|
Total future commitments2 | $ | 36,021 |
|
|
| | | |
| (in millions) | Total |
| 2019 | $ | 2,562 |
|
| 2020 | 2,602 |
|
| 2021 | 2,570 |
|
| 2022 | 2,415 |
|
| 2023 | 2,185 |
|
| Thereafter | 23,855 |
|
| Total future commitments | $ | 36,189 |
|
| |
1 | Includes $242 million related to certain lease contracts to be recorded as short-term lease expense in 2021. |
| |
2 | Certain power purchase agreements are treated as operating or finance leases. For further discussion, see Note 13. Includes a lease contract that has not yet commenced with future lease payments of $135 million. The lease is expected to commence during the third quarter of 2020. |
Additionally, as of December 31, 2019, SCE has executed contracts (including capacity reduction contracts) that have not met the critical contract provisions that would increase contractual obligations by $66 million in 2019, $176$25 million in 2020, $189$106 million in 2021, $184$102 million in 2022, $183$102 million in 2023, $69 million in 2024 and $2.2 billion$897 million thereafter, if all critical contract provisions are completed.
Costs incurred for PPAs were $3.7 billion in 2019, $3.8 billion in 2018 and $3.6 billion in 2017, and $3.3 billion in 2016, which include costs associated with contracts with terms of less than one year.
Certain PPAs that SCE entered into may be accounted for as leases. The following table shows the future minimum lease payments due under the contracts that are treated as operating and capital leases (these amounts are also included in the table above). Due to the inherent uncertainty associated with the reliability of the fuel source, expected purchases from most renewable energy contracts do not meet the definition of a minimum lease payment and have been excluded from the operating and capital lease table below but remain in the table above. The future minimum lease payments for capital leases are discounted to their present value in the table below using SCE's incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the amount representing interest.
|
| | | | | | | |
| (in millions) | Operating Leases | | Capital Leases |
| 2019 | $ | 148 |
| | $ | 5 |
|
| 2020 | 124 |
| | 6 |
|
| 2021 | 103 |
| | 6 |
|
| 2022 | 79 |
| | 6 |
|
| 2023 | 47 |
| | 5 |
|
| Thereafter | 536 |
| | 66 |
|
| Total future commitments | $ | 1,037 |
| | $ | 94 |
|
| Amount representing executory costs | |
| | (25 | ) |
| Amount representing interest | |
| | (33 | ) |
Net commitments1 | |
| | $ | 36 |
|
1 Includes two contracts with net commitments of $26 million that will commence in 2019.
In 2018, SCE amended the termination date of two power purchase agreements, which are classified as operating leases. As a result of this amendment, future minimum payments for these operating leases, totaling $986 million, were removed from the table above. SCE is required to make early termination payments of $100 million in 2019, $77 million in 2020 and $29 million in 2021, which were included in the consolidated balance sheets as of December 31, 2018.
Operating lease expense for PPAs was $2.3 billion in 2018, and $2.3 billion in 2017 and $1.9 billion in 2016 (including contingent rents of $2.1 billion in 2018, $1.8 billion in 2017 and $1.4 billion in 2016). Contingent rents for capital leases were $104 million in 2018, $99 million in 2017 and $109 million in 2016. The timing of SCE's recognition of the lease expense conforms to ratemaking treatment for SCE's recovery of the cost of electricity and is included in purchased power.
Other Lease Commitments
The following summarizes the estimated minimum future commitments for Edison International's non-cancelable other operating leases (primarily related to vehicles, office space and other equipment related to SCE):
|
| | | |
| (in millions) | Total |
| 2019 | $ | 42 |
|
| 2020 | 31 |
|
| 2021 | 27 |
|
| 2022 | 22 |
|
| 2023 | 17 |
|
| Thereafter | 101 |
|
| Total future commitments | $ | 240 |
|
Operating lease expense for other leases were $57 million in 2018, $59 million in 2017 and $68 million in 2016. Certain leases on office facilities contain escalation clauses requiring annual increases in rent. The rentals payable under these leases may increase by a fixed amount each year, a percentage over base year, or the consumer price index.
Other Commitments
The following summarizes the estimated minimum future commitments for SCE's other commitments:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total |
| Other contractual obligations | $ | 77 |
| | $ | 48 |
| | $ | 47 |
| | $ | 46 |
| | $ | 45 |
| | $ | 189 |
| | $ | 452 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in millions) | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
| Other contractual obligations | $ | 79 |
| | $ | 67 |
| | $ | 46 |
| | $ | 44 |
| | $ | 35 |
| | $ | 209 |
| | $ | 480 |
|
Costs incurred for other commitments were $124$110 million in 2019, $124 million in 2018 and $75 million in 2017 and $141 million in 2016. SCE has2017. Other commitments include fuel supply contracts for Palo Verde which require payment only if the fuel is made available for purchase. SCE also hasAlso included are commitments related to maintaining reliability and expanding SCE's transmission and distribution system.
The table above does not include asset retirement obligations, which are discussed in Note 1.
Indemnities
Edison International and SCE have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business.
Edison International and SCE have agreed to provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and indemnities for specified environmental liabilities and income taxes with respect to assets sold.sold or other contractual arrangements. Edison International's and SCE's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison International and SCE may have recourse against third parties. Edison International and SCE have not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.
SCE has agreed to indemnify the City of Redlands, California in connection with the Mountainview power plant's California Energy Commission permit for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. As of December 31, 2018, there has been no groundwater contamination identified. Thus, SCE has not recorded a liability related to this indemnity.
Contingencies
In addition to the matters disclosed in these Notes, Edison International and SCE are involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International and SCE believe the outcome of these other proceedings will not, individually or in the aggregate, materially affect its financial position, results of operations and cash flows.
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,wildfire activity, and 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. SCE has determined that approximately 27% of its service territory is in areas identified as high fire risk.
In December 2017 and November 2018,Over the past several years, wind-driven wildfires impacted portions of SCE's service territory, with wildfires in December 2017 and November 2018 causing loss of life, substantial damage to both residential and business properties, and service outages for SCE customers. The investigating government agencies, the Ventura County Fire Department ("VCFD") and California Department of Forestry and Fire Protection ("CAL FIRE"), have determined that the largest of the 2017 fires knownoriginated on December 4, 2017, in the Anlauf Canyon area of Ventura County (the investigating agencies refer to this fire as the Thomas Fire,"Thomas Fire"), followed shortly thereafter by a second fire that originated near Koenigstein Road in Ventura County andthe City of Santa Paula (the "Koenigstein Fire"). While the progression of these two fires remains under review, the December 4, 2017 fires eventually burned substantial acreage located in both Ventura and Santa Barbara Counties. According to CAL FIRE, the Thomas and Koenigstein Fires, collectively, burned over 280,000 acres, destroyed or damaged an estimated 1,343 structures and resulted in 2 confirmed fatalities. The largest of the November 2018 fires, known as the Woolsey Fire,"Woolsey Fire", originated in Ventura County and burned acreage in both Ventura and Los Angeles Counties. According to California Department of Forestry and Fire Protection ("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, whileFIRE, the Woolsey Fire burned almost 100,000 acres, destroyed an estimated 1,643 structures, damaged an estimated 364 structures and resulted in three3 confirmed fatalities. As of December 31, 2018, SCE had incurred approximately $89 million of capital expenditures related to restoration of service resulting from the Thomas Fire and the Montecito Mudslides (as defined below) and $82 million resulting fromNaN additional fatalities have been associated with the Woolsey Fire.
As described below, multiple lawsuits related to the Thomas Fireand Koenigstein Fires and the Woolsey Fire have been initiated against SCE and Edison International. Some of the Thomas Fire-relatedand Koenigstein Fires lawsuits claim that SCE and Edison International have responsibility for the damages caused by mudslides and flooding in Montecito and surrounding areas in January 2018 (the "Montecito Mudslides") based on a theory alleging that SCE has responsibility for the Thomas Fireand/or Koenigstein Fires and that the Thomas Fireand/or Koenigstein Fires 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 confirmed fatalities, with two2 additional fatalities presumed.
In 2019, several wind-driven wildfires, including the "Saddle Ridge Fire," originated in Southern California (the "2019 Fires"). Based on currently available information and without considering insurance recoveries, it is reasonably possible that SCE will incur a material loss in connection with the Saddle Ridge Fire, but the range of possible losses that could be incurred cannot be estimated at this time. Edison International and SCE expect that any losses incurred will be covered by insurance, subject to a self-insured retention and co-insurance, and that the amount of any such loss after insurance recoveries will not be material. After expected insurance recoveries, SCE does not expect any of the 2019 Fires to have a material adverse effect on its financial condition, results of operations or cash flows. At December 31, 2019, SCE recorded self-insured retention expenses totaling $23 million ($17 million after-tax) primarily associated with the 2019 Fires. SCE has not recorded a charge for potential liabilities relating to the Saddle Ridge Fire because, based on currently available information, it has not determined that a loss is probable.
Liability Overview
The extent of liability for wildfire-related damages in actions against utilities depends on a number of factors, including whether SCEthe utility substantially caused or contributed to the damages and whether parties seeking recovery of damages will be required to show negligence in addition to causation. California courts have previously found utilities to be strictly liable for property damage along with associated interest and attorneys' fees, regardless of fault, by applying the theory of inverse condemnation when a utility's facilities were determined to be a substantial cause of a wildfire that caused the property damage. If inverse condemnation is held to be inapplicable to SCE in connection with a wildfire, SCE still could be held liable for property damages and associated interest if the property damages were found to have been proximately caused by SCE's negligence. If SCE were to be found negligent, SCE could also be held liable for, among other things, fire suppression costs, business interruption losses, evacuation costs, clean-up costs, medical expenses, and personal injury/wrongful death claims.
Additionally, SCE could potentially be subject to fines for alleged violations of CPUC rules and state laws in connection with the ignition of a wildfire.
Investigations intoFinal determinations of liability for the causes ofThomas Fire, the ThomasKoenigstein Fire, the Montecito Mudslides and the Woolsey Fire (collectively,(each a "2017/2018 Wildfire/Mudslide Event," and, collectively, the "2017/2018 Wildfire/Mudslide Events") are ongoing and final determinations of liability,, including determinations of whether SCE was negligent, would only be made during lengthy and complex litigation processes. Even when investigations are still pending or liability is disputed, an assessment of likely outcomes, including through future settlement of disputed claims, may require a chargeliability 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 Eventsinformation available to SCE and consideration of the risks associated with litigation, Edison International and SCE expect to incur a material loss in connection with the 2017/2018 Wildfire/Mudslide Events and have accrued a charge, before recoveries and taxes,Events.
As of $4.7 billion in the fourth quarter of 2018.December 31, 2019, Edison International and SCE also recordedhave estimated liabilities of $4.5 billion, remaining expected recoveries from insurance of $2.0$1.7 billion and expected recoveries through FERC electric rates of $135 million.$149 million on their consolidated balance sheets related to the 2017/2018 Wildfire/Mudslide Events. The net charge to earnings recorded was $1.8 billion after-tax. This chargeaccrued liability 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 with recoveries from insurance policies in place at the time of the events and, to the extent actual losses exceed insurance, through electric rates. The CPUC and FERC may not allow SCE to recover uninsured losses through electric rates if it is determined that such losses were not reasonably or prudently incurred. See "—Loss"Loss Estimates for Third Party Claims and Potential Recoveries from Insurance and through Electric Rates" below for additional information.
External Investigations and Internal Review
Determining wildfire originThe VCFD and cause is often a complex and time-consuming process and several investigations intoCAL FIRE have jointly issued reports concerning their findings regarding the facts and circumstancescauses of the Thomas and Woolsey Fires are believed to be ongoing. SCE has been advised that the origins and
causes of these fires are being investigated by CAL FIREFire and the Ventura County Fire Department. In connection with its investigation of the Thomas and Woolsey Fires, CAL FIRE has removed and retained certain of SCE's equipment that was located in the general vicinity of suspected areas of origin of each of the fires. SCE expects that the Ventura County Fire Department and/or CAL FIRE will ultimately issueKoenigstein Fire. The reports concerning the departments’ findings of origin and cause for each of these fires but cannot predict when these reports will be released. It is SCE's understanding that these reports willdid not address the causes of the Montecito Mudslides. SCE has also received a non-final redacted draft of a report from the VCFD regarding Woolsey Fire (the "Redacted Woolsey Report"). SCE received the Redacted Woolsey Report subject to a protective order in the litigation related to the Woolsey fire and, other than the information disclosed in this Form 10-K, is not authorized to release the report or its contents to the public at this time. Based on a filing made by Ventura County in the Woolsey Fire litigation, SCE anticipates that the VCFD will release the final non-redacted report from the VCFD regarding the Woolsey Fire on or about April 1, 2020. The CPUC's Safety Enforcement Division ("SED")VCFD and CAL FIRE findings do not determine legal causation of or assign legal liability for the Thomas, Koenigstein or Woolsey Fires; final determinations of legal causation and liability would only be made during lengthy and complex litigation.
The SED is also conducting investigations to assess SCE's compliance with applicable rules and regulations in areas impacted by the fires.Thomas, Koenigstein and Woolsey Fires. SCE cannot predict when the SED's investigations of CAL FIRE, the Ventura County Fire Department or the SED will be completed.
Internal Review
Edison International and SCE understand that the California Attorney General's Office has completed its investigation of the Thomas Fire without pursuing criminal charges. Edison International and SCE are aware of an ongoing investigation by the California Attorney General's Office of the Woolsey Fire for the purpose of determining whether any criminal violations have occurred. SCE could be subject to material fines, penalties, or restitution if it is determined that it failed to comply with applicable laws and regulations. SCE is not aware of any basis for felony liability with regards to the Thomas Fire, the Koenigstein Fire or the Woolsey Fire.
SCE's internal review into the facts and circumstances of each of the Thomas Fire2017/2018 Wildfire/Mudslide Events is complex and examines various matters including possible ignition points, the location of those ignition points, fire progression and the attribution of damages to fires with separate ignition points.time consuming. SCE expects to obtain and review additional information and materials in the possession of CAL FIRE and othersthird parties during the course of its internal reviewreviews and the litigation processes.
Thomas Fire litigation process, including SCE equipment that has been retained by
On March 13, 2019, the VCFD and CAL FIRE.
Based on currently available information, SCE believesFIRE jointly issued a report concluding, after ruling out other possible causes, that the Thomas Fire had at least two separate ignition points, one near Koenigstein Roadwas started by SCE power lines coming into contact during high winds, resulting in the City of Santa Paula and the other in the Anlauf Canyon area of Ventura County. With respectmolten metal falling to the Koenigstein Road ignition point, witnesses have reportedground. However, the report does not state that a fire ignited intheir investigation found molten metal on the vicinity of an SCE power pole and SCE later learned of a downed electrical wire at this location. SCE believes that its equipment was associated with this ignition. CAL FIRE has removed SCE equipment that was located in the Koenigstein Road area and SCE has not been able to inspect it. SCE is continuing to assess the progression of the fire from the Koenigstein Road ignition point and the extent of damages that may be attributable to that ignition.ground. At this time, based on available information, SCE has not determined whether its equipment caused the ignitionThomas Fire. Based on publicly available radar data showing a smoke plume in the Anlauf Canyon area involvedemerging in advance of the report's indicated start time, SCE equipment.believes that the Thomas Fire started at least 12 minutes prior to any issue involving SCE's system and at least 15 minutes prior to the start time indicated in the report. SCE is continuing to assess the progression of the Thomas Fire and the extent of damages that may be attributable to that fire.
Koenigstein Fire
On March 20, 2019, the VCFD and CAL FIRE has removedjointly issued a report finding that the Koenigstein Fire was caused when an energized SCE electrical wire separated and fell to the ground along with molten metal particles and ignited the dry vegetation below. As previously disclosed, SCE believes that its equipment was associated with the ignition of the Koenigstein Fire. SCE is continuing to assess the progression of the Koenigstein Fire and the extent of damages that was located in the Anlauf Canyon area and SCE has not been ablemay be attributable to inspect it.that fire.
Montecito Mudslides
SCE's internal review also includes inquiry into whether the Thomas Fireand/or Koenigstein Fires proximately caused or contributed to the Montecito Mudslides, the source of ignition of the portion ofwhether, and to what extent, the Thomas Fire that burned throughand/or Koenigstein Fires were responsible for the damages in the Montecito area and other factors that potentially contributed to the losses that resulted from the Montecito Mudslides. Many other factors, including, but not limited to, weather conditions and insufficiently or improperly designed and maintained debris basins, roads, bridges and other channel crossings, could have proximately caused, contributed to or exacerbated the losses that resulted from the Montecito Mudslides.
At this time, based on available information, SCE has not been able to determine the source of ignition of the portion ofwhether the Thomas Fire that burned withinor the Koenigstein Fire, or both, were responsible for the damages in the Montecito area. In the event that SCE is determined to have caused the fire that spread to the Montecito area, SCE cannot predict whether, if fully litigated, the courts would conclude that the Montecito Mudslides were caused or contributed to by the Thomas Fireand/or Koenigstein Fires or that SCE would be liable for some or all of the damages caused by the Montecito Mudslides.
Woolsey Fire
SCE's internal review into the facts and circumstances of the Woolsey Fire is ongoing. SCE has reported to the CPUC that there was an outageon SCE’sSCE's electric system in the vicinity of where the Woolsey Fire reportedly began on November 8, 2018. SCE is aware of witnesses who saw fire in the vicinity of SCE's equipment at the time the fire was first reported. While SCE did not find evidence of downed electrical wires on the ground in the suspected area of origin, it observed a pole support wire in proximity to an electrical wire that was energized prior to the outage. Whether
The Redacted Woolsey Report states that the November 8, 2018 outageVCFD investigation team determined that electrical equipment owned and operated by SCE was related to contact being made between the support wire andcause of the electrical wire has not been determined.Woolsey Fire. Absent additional evidence, SCE believes that it is likely that its equipment could be found to have beenwas associated with the ignition of the Woolsey Fire. SCE expects to obtain and review additional information and materials in the possession of CAL FIRE and others during the course of its internal review and the Woolsey Fire litigation process, including SCE equipment that has been retained by CAL FIRE.
Wildfire-related Litigation
Multiple lawsuits related to the 2017/2018 Wildfire/Mudslide Events naming SCE as a defendant have been filed.filed by three categories of plaintiffs: individual plaintiffs, subrogation plaintiffs and public entity plaintiffs. A number of the lawsuits also name Edison International as a defendant and some of the lawsuits were filed as purported class actions. The lawsuits, which have been filed in the superior courts of Ventura, Santa Barbara and Los Angeles Counties in the case of the Thomas Fireand Koenigstein Fires and the Montecito Mudslides, and in Ventura and Los Angeles Counties in the case of the Woolsey Fire, allege, among other things, negligence, inverse condemnation, trespass, private nuisance, personal injury, wrongful death, and violations of the California Public Utilities and Health and Safety Codes. SCE expects to be the subject of additional lawsuits
related to the 2017/2018 Wildfire/Mudslide Events. The litigation could take a number of years to be resolved because of the complexity of the matters and number of plaintiffs.
The Thomas Fireand Koenigstein Fires and Montecito Mudslides lawsuits are being coordinated in the Los Angeles Superior Court. The Woolsey Fire lawsuits have also been recommended for coordinationcoordinated in the Los Angeles Superior Court. On October 4, 2018, the Superior Court denied Edison International's and SCE's challenge to the application of inverse condemnation to SCE with respect to the Thomas Fireand Koenigstein Fires and, on February 26, 2019, the California Supreme Court denied SCE's petition to review the Superior Court’sCourt's decision. In January 2019, SCE filed a cross-complaint against certain governmentallocal public entities alleging that failures by these entities, such as failure to adequately plan for flood hazards and build and maintain adequate debris basins, roads, bridges and other channel crossings, among other things, caused, contributed to or exacerbated the losses that resulted from the Montecito Mudslides. These cross-claims in the Montecito Mudslides litigation were not released as part of the Local Public Entity Settlements.
Additionally, in July 2018 and September 2018, two separatea derivative lawsuitslawsuit for breach of fiduciary duties and unjust enrichment werewas filed in the Los Angeles Superior Court against certain current and former members of the Boards of Directors of Edison International and SCE. Edison International and SCE are identified as nominal defendants in those actions.the action. The derivative lawsuitslawsuit generally allegealleges that the individual defendants violated their fiduciary duties by causing or allowing SCE to operate in an unsafe manner in
violation of relevant regulations, resulting in substantial liability and damage from the Thomas Fireand Koenigstein Fires and the Montecito Mudslides. The lawsuit is currently stayed.
In November 2018, a purported class action lawsuit alleging securities fraud and related claims was filed in the federal court against Edison International, SCE and certain current and former officers of Edison International and SCE. The plaintiff alleges that Edison International and SCE made false and/or misleading statements in filings with the Securities and Exchange Commission by failing to disclose that SCE had allegedly failed to maintain its electric transmission and distribution networks in compliance with safety regulations, and that those alleged safety violations led to fires that occurred in 2017 and 2018, including the Thomas Fire and the Woolsey Fire.
In January 2019, two2 separate derivative lawsuits alleging breach of fiduciary duties, securities fraud, misleading proxy statements, unjust enrichment, and related claims were filed in federal court against allcertain current and certain former members of the boardBoards of directorsDirectors and certain current and former officers of Edison International and SCE. Edison International and SCE are named as nominal defendants in those actions. The derivative lawsuits generally allege that the individual defendants breached their fiduciary duties and made misleading statements or allowed misleading statements to be made (i) between March 21, 2014 and August 10, 2015, with respect to certain ex parte communications between SCE and CPUC decision-makers concerning the settlement of the San Onofre Order Instituting Investigation proceeding (the "San Onofre OII") and (ii) from February 23, 2016 to the present, concerning compliance with applicable laws and regulations concerning electric system maintenance and operations related to wildfire risks. The lawsuits generally allege that these breaches of duty and misstatements led to substantial liability and damage resulting from the disclosure of SCE’sSCE's ex parte communications in connection with the San Onofre OII settlement, and from the 2017/2018 Wildfire/Mudslide Events. For more information regarding the San Onofre OII, see "—Permanent Retirement of San Onofre" below.
Loss Estimates for Third Party Claims and Potential Recoveries from Insurance and through Electric Rates
At December 31, 2019 and December 31, 2018, Edison International's and SCE's balance sheets include accrued liabilities (established at the lower end of the reasonably estimated range of expected losses) of $4.5 billion and $4.7 billion, respectively, for the 2017/2018 Wildfire/Mudslide Events.
The following table presents changes in estimated losses (estimated at the lower end of the reasonably estimated range of expected losses) for the 2017/2018 Wildfire/Mudslide Events since December 31, 2018:
|
| | | |
| (in millions) | |
| Balance at December 31, 2018 | $ | 4,669 |
|
| Accrued losses | 232 |
|
| Payments | (360 | ) |
| Balance at December 31, 2019 | $ | 4,541 |
|
In total, SCE has accrued estimated losses of $4.9 billion and paid $360 million in settlements and recovered $290 million from its insurance carriers through December 31, 2019 in relation to the 2017/2018 Wildfire/Mudslide Events.
For the years-ended December 31, 2019 and 2018, the income statements include charges for the estimated losses (established at the lower end of the reasonably estimated range of expected losses), net of expected recoveries from insurance and FERC customers, related to the 2017/2018 Wildfire/Mudslide Events as follows:
|
| | | | | | | |
| | Year ended December 31, |
| (in millions) | 2019 | | 2018 |
| Charge for wildfire-related claims | $ | 232 |
| | $ | 4,669 |
|
| Expected insurance recoveries | — |
| | (2,000 | ) |
| Expected revenue from FERC customers | (14 | ) | | (135 | ) |
| Total pre-tax charge | 218 |
| | 2,534 |
|
| Income tax benefit | (61 | ) | | (709 | ) |
| Total after-tax charge | $ | 157 |
| | $ | 1,825 |
|
In the fourth quarter of 2018, SCE recorded a liability for estimated losses of $4.7 billion related to the 2017/2018 Wildfire/Mudslide Events. In the fourth quarter of 2019, SCE paid $360 million to a number of local public entities to resolve those parties' collective claims arising from the 2017/2018 Wildfire/Mudslide Events (the “Local Public Entity Settlements”). After
the Local Public Entity Settlements, the liability accrued for estimated losses as of December 31, 2019 was reduced by the $360 million paid in the Local Public Entity Settlements.
Each reporting period, management reviews its loss estimates for remaining alleged and potential claims related to the 2017/2018 Wildfire/Mudslide Events. The process for estimating losses associated with wildfire litigation claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including, but not limited toto: estimates of known and expected claims by third parties based on currently available information, and assessments, opinions of counsel regarding litigation risk, the status of and developments in the course of litigation, and prior experience with litigating and settling wildfire litigation claims. While the low end of the reasonably estimated range of expected losses for the 2017/2018 Wildfire/Mudslide Events is estimated on an aggregate basis, some of the factors evaluated by management in connection with its fourth quarter 2019 review contributed to a significant increase in certain loss estimates, while others contributed to a significant decrease in certain other wildfire cases.loss estimates. The net result of management's fourth quarter 2019 review was an increase in estimated losses of $232 million for total estimated losses of $4.5 billion as of December 31, 2019 for unpaid claims related to the 2017/2018 Wildfire Mudslide Events. As additional information becomes available, managementmanagement's estimates and assumptions regarding the causes and financial impact of the 2017/2018 Wildfire/Mudslide Events may change.change further. Such additional information is expected to become available from multiple external sources during the course of litigation and settlement discussions and from SCE's ongoing internal review, including, among other things, information regarding the extent of damages that may be attributable to any ignitionfire determined to have been substantially caused by SCE's equipment, information that may be obtained from the equipment in CAL FIRE's possession, and information pertaining to fire progression, suppression activities, damages alleged damagesby plaintiffs and insurance claims.claims made by third parties.
As described above, the $1.8 billion after-tax chargeaccrued liability as of December 31, 2019 corresponds to the lower end of the reasonably estimated range of expected losses that may be incurred in connection with the 2017/2018 Wildfire/Mudslide Events and is subject to change as additional information becomes available. Edison International and SCE currently believe that it is reasonably possible that the amount of the actual loss will be greater than the amount accrued. However, Edison International and SCE are currently unable to reasonably estimate an upper end of the range of expected losses given the uncertainty as to the legal and factual determinations to be made during litigation, including uncertainty as to the contributing causes of the 2017/2018 Wildfire/Mudslide Events, the complexities associated with multiple ignition points, the potential for separate damages to be attributable to fires ignited at separate ignition points,that merge, whether inverse condemnation will be held applicable to SCE with respect to damages caused by the Montecito Mudslides, and the preliminary nature of the litigation processes.
For events that occurred in 2017 and early 2018, principally the Thomas Fireand Koenigstein Fires and Montecito Mudslides, SCE has $1had $1.0 billion of wildfire-specific insurance coverage, subject to a self-insured retention of $10 million per occurrence. SCE also had other general liability insurance coverage of approximately $450 million, but it is uncertain whether these other policies would apply to liabilities alleged to be related to the Montecito Mudslides. For the Woolsey Fire, SCE hashad an additional $1$1.0 billion of wildfire-specific insurance coverage, subject to a self-insured retention of $10 million per occurrence. Edison International and SCE record a receivable for insurance recoveries when recovery of a recorded loss is determined to be probable. At December 31, 2018, Edison International and SCE had recorded $2.0 billion forThe following table presents changes in expected insurance recoveries associated with the recorded lossestimated losses for the 2017/2018 Wildfire/Mudslide Events. The amount of the receivable is subject to change based on additional information.Events since December 31, 2018:
|
| | | |
| (in millions) | |
| Balance at December 31, 2018 | $ | 2,000 |
|
Insurance recoveries1 | (290 | ) |
| Balance at December 31, 2019 | $ | 1,710 |
|
| |
1 | Additional insurance recoveries of $55 million were received in February 2020. |
SCE will seek to recover uninsured costs resulting from the 2017/2018 Wildfire/Mudslide Events through electric rates. The amount of the receivable is subject to change based on additional information. Recovery of these costs is subject to approval by regulators. Under accounting standards for rate-regulated enterprises, SCE defers costs as regulatory assets when it concludes that such costs are probable of future recovery in electric rates. SCE utilizes objectively determinable evidence to form its view on probability of future recovery. The only directly comparable precedent in which a California investor-owned utility has sought recovery for uninsured wildfire-related costs is SDG&E’s&E's requests for cost recovery related to 2007 wildfire activity, where FERC allowed recovery of all FERC-jurisdictional wildfire-related costs while the CPUC rejected recovery of all CPUC-jurisdictional wildfire-related costs based on a determination that SDG&E did not meet the CPUC’sCPUC's prudency standard. As a result, while SCE does not agree with the CPUC’sCPUC's decision, it believes that the CPUC’sCPUC's interpretation and application of the prudency standard to SDG&E creates substantial uncertainty regarding how that standard will be applied to an investor-owned utility in future wildfire cost-recovery proceedings.proceedings for fires ignited prior to July 12, 2019. SCE will continue to evaluate the probability of recovery based on available evidence, including guidance that may be issued by the commission on Catastrophic Wildfire Cost and Recovery, and new judicial, legislative and regulatory decisions, including any CPUC decisions illustrating the interpretation and/or application of the prudency standard when
making determinations regarding recovery of uninsured wildfire-related costs. 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. SCE would record a regulatory asset at the time it obtains sufficient information to support a conclusion that recovery is probable. SCE will seek recovery of the CPUC portion of any uninsured wildfire-related costs through its WEMA.WEMA or its CEMA. In July 2019, SCE filed a CEMA application with the CPUC to seek recovery of, among other things, approximately $6 million in costs incurred to restore service to customers and to repair, replace and restore buildings and SCE's facilities damaged or destroyed as a result of the Thomas and Koenigstein Fires. SCE continues to incur costs for reconstructing its system and restoring service to structures that were damaged or destroyed by these two fires and plans to file additional applications with the CPUC to recover such costs. See "—Recovery"Recovery of Wildfire-Related Costs" below.
Through the operation of its FERC Formula Rate, and based upon the precedent established in SDG&E's recovery of FERC-jurisdictional wildfire-related costs, SCE believes it is probable it will recover its FERC-jurisdictional wildfire and mudslide related costs and has recorded a regulatory assetassets of $135$149 million within the FERC balancing account, the FERC portion of the $4.7 billion charge accrued.
At December 31, 2018, the balance sheets include estimated losses (established at the lower end of the reasonably estimated range of expected losses) of $4.7 billion for the 2017/2018 Wildfire/Mudslide Events. For the year-ended December 31, 2018, the income statements include the estimated losses (established at the lower end of the reasonably estimated range of expected losses), net of expected recoveries from insurance and FERC customers, related to the 2017/2018 Wildfire/Mudslide Events as follows:accrued.
|
| | | |
| (in millions) | Year ended December 31, 2018 |
| Charge for wildfire-related claims | $ | 4,669 |
|
| Expected insurance recoveries | (2,000 | ) |
| Expected revenue from FERC customers | (135 | ) |
| Total pre-tax charge | 2,534 |
|
| Income tax benefit | (709 | ) |
| Total after-tax charge | $ | 1,825 |
|
Waiver of CPUC Equity Ratio Requirement
Under SCE's interpretation of the CPUC’s capital structure decisions, SCE is required to maintain a 48% equity ratio on average over a 37-month period and to file an application for a waiver to the capital structure condition 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.
Current Wildfire Insurance Coverage
SCE has approximately $1$1.2 billion of wildfire-specific insurance coverage, subject to a self-insured retention of $10 million per occurrence, for events (including the Woolsey fire) during the period June 30, 2018 through May 31, 2019. If the $1 billion of insurance coverage is exhausted as a result of liabilities related to the Woolsey Fire, SCE has approximately $700 million of wildfire-specific insurance coverage for wildfire events during the period February 1, 2019 through May 31, 2019, subject to a self-insured retention of $10 million per occurrence and up to $15 million of co-insurance. SCE has also obtained $750 million of wildfire-specific insurance coverage for events that may occur during the period June 1, 2019 through June 30, 2020, subject to a self-insured retention of $10 million per occurrence and up to $115 million of co-insurance. SCE may obtain additional wildfire-specific insurance for this time periodco-insurance and $50 million of self-insured retention, which results in the future.net coverage of approximately $1.0 billion. Various coverage limitations within the policies that make up SCE's wildfire insurance coverage could result in additional material self-insured costs in the event of multiple wildfire occurrences during a policy period or with a single wildfire with damages in excess of the policy limits.
SCE's cost of obtaining wildfire insurance coverage has increased significantly as a result of, among other things, the number of recent and significant wildfire events throughout California and the application of inverse condemnation to investor-owned utilities. As such, SCE may not be able to obtain sufficient wildfire insurance, at a reasonable cost.cost, in the future.
SCE’sSCE's wildfire insurance expense in 2019, prior to any regulatory deferrals, totaled approximately $237$400 million. In February 2019, the CPUC approved recovery of $107 million during 2018. Based on policies currently in effect,of the costs incurred by SCE anticipates that itsto obtain a 12-month, $300 million wildfire insurance expense, prior to any regulatory deferrals, will total approximately $321 millionpolicy in December 2017. As a result of this decision, SCE recovered these insurance premiums during 2019. Wildfire insurance expense will increase in 2019 if SCE obtains additional wildfire-specific insurance. As of December 31, 2018,2019, SCE had a regulatory assetassets of $128approximately $341 million related to wildfire insurance costs and believes that such amounts are probable of recovery. While SCE believes that amounts deferred are probable of recovery, there is no assurance that SCE will be allowed to recover costs that have been incurred, or costs incurred in the future for additional wildfire insurance, in electric rates.
SCE tracks insurance premium costs related to wildfire liability insurance policies as well as other wildfire-related costs in its WEMA. In FebruaryJuly 2019, SCE filed a WEMA application with the CPUC approvedto seek recovery of $107$478 million in wildfire insurance premium costs incurred in excess of premiums approved in the 2018 GRC. The application also seeks recovery of the costs incurred by SCE to obtain a 12-month, $300 million wildfire insurance policy in December 2017. As a result of this decision, SCE will recover these insurance premiums during 2019.corresponding financing costs.
Recovery of Wildfire-Related Costs
Pre-AB 1054 Cost Recovery
California courts have previously found investor-owned utilities to be strictly liable for property damage, regardless of fault, by applying the theory of inverse condemnation when a utility's facilities were determined to be a substantial cause of a wildfire that caused the property damage. The rationale stated by these courts for applying this theory to investor-owned utilities is that property damages resulting from a public improvement, such as the distribution of electricity, can be spread across the larger community that benefited from such improvement through recovery of uninsured wildfire-related costs in electric rates. However, in November 2017, the CPUC issued a decision denying SDG&E's request to include in its rates uninsured wildfire-related costs arising from several 2007 fires,wildfires, finding that SDG&E did not meet the prudency standard because it did not prudently manage and operate its facilities prior to or at the outset of the 2007 wildfires. In July 2018, the CPUC denied both SDG&E's application for rehearing on its cost recovery request and a joint application for rehearing filed by SCE and PG&E limited to the applicability of inverse condemnation principles in the same proceeding. The California Court of Appeal, the California Supreme Court and the United States Supreme Court have denied SDG&E’s petition&E's petitions for review of the CPUC's denial of SDG&E's application and the California Supreme Court denied SDG&E’s petition to review the Court of Appeal’s denial of SDG&E's petition to review.
In September 2018, California Senate Bill 901 ("SB 901") was signed by the Governor of California. Although SB 901 does not address the strict liability standard imposed by courts in inverse condemnation actions, the bill as enacted introduces a number of considerations the CPUC can apply to determine whether costs are recoverable in electric rates for wildfires occurring on or after January 1, 2019, including, among other things, the utility's actions, circumstances beyond the utility's control and the impact of extreme climate conditions. SB 901 requires investor-owned utilities to prepare annually, for CPUC approval, wildfire risk mitigation plans, and, compliance with an approved plan is one factor the CPUC can consider in addressing cost recovery. On February 6, 2019, in compliance with SB 901, SCE filed its wildfire mitigation plan for 2019. While SCE takes the position, in its wildfire mitigation plan, that substantial compliance with the plan, once approved, will demonstrate that SCE prudently operated its system and met the CPUC’s prudent manager standard regarding wildfire risk mitigation, the CPUC may not agree with SCE's position. Pursuant to the requirements of SB 901, a Commission on Catastrophic Wildfire Cost and Recovery was formed in January 2019 to examine, among other things, the socialization of catastrophic wildfire costs in an equitable manner. SB901 also provides an opportunity for utilities to securitize costs that are deemed just and reasonable by the CPUC for wildfires that occur after January 1, 2019 and, to the extent costs exceed the maximum amount the utility can pay without harming ratepayers or materially impacting the utility’s ability to provide adequate and safe services, for wildfires that occurred in 2017. Based on events and information available to date, SCE
believes it is unlikely that it will seek to use this mechanism to securitize costs incurred in connection with the 2017/2018 Wildfire/Mudslide Events.application.
Edison International and SCE continue to pursue legislative, regulatory and legal strategies, and anticipate pursuing legislative strategies in the longer term, to address the application of a strict liability standard to wildfire-related property damages without the guaranteed ability to recover resulting costs in electric rates. However,
2019 Wildfire Legislation
In July 2019, AB 1054 was signed by the Governor of California and became effective immediately. The summary of the wildfire legislation below is based on SCE's interpretation of AB 1054. A lawsuit challenging the validity of AB 1054 was filed in federal court on July 19, 2019. Edison International and SCE cannotare unable to predict whetherthe outcome of this lawsuit.
Wildfire Insurance Fund
AB 1054 provided for the Wildfire Insurance Fund to reimburse utilities for payment of third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1.0 billion or the utility's insurance coverage. The Wildfire Insurance Fund was established in September 2019 when there will be a comprehensive solution mitigating the significant risk faced by California investor-owned utilities related to wildfires.
Permanent Retirement of San Onofre
The San Onofre 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 a Revised San Onofre Settlement Agreement. On January 30, 2018, 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, ORA, TURN, and Women's Energy Matters (the "OII Parties") entered into a Revised San Onofre Settlement Agreement in the San Onofre OII proceeding (the "Revised San Onofre Settlement Agreement"). Under the Revised San Onofre Settlement Agreement,both SCE and SDG&E (the "Utilities")made their initial contributions to the fund. The Wildfire Insurance Fund is available for claims related to wildfires ignited after July 12, 2019 that are determined to have been caused by a utility by the responsible government investigatory agency.
SCE and SDG&E have collectively made their initial contributions totaling approximately $2.7 billion to the Wildfire Insurance Fund. While PG&E has committed to make an initial contribution of approximately $4.8 billion to the Wildfire Insurance Fund upon emergence from bankruptcy, its participation in, and contributions to, the fund are subject to it resolving its bankruptcy proceeding and meeting certain other conditions prior to June 30, 2020. SCE, SDG&E and PG&E are also collectively expected to make aggregate contributions of $3.0 billion to the Wildfire Insurance Fund through annual contributions to the fund over a 10-year period, of which SCE and SDG&E have made their initial annual contributions totaling approximately $107 million. If PG&E is unable to participate in the Wildfire Insurance Fund, then SCE and SDG&E are collectively expected to make aggregate contributions of approximately $1.0 billion to the fund, through annual contributions over the 10-year period. In addition to PG&E's, SCE's and SDG&E's contributions to the Wildfire Insurance Fund, $13.5 billion is expected to be collected over a 15-year period from their ratepayers through a dedicated rate component. The amount collected from ratepayers may be directly contributed to the Wildfire Insurance Fund or used to support the issuance of up to $10.5 billion in bonds by the California Department of Water Resources, the proceeds of which would be contributed to the fund. In addition to funding contributions to the Wildfire Insurance Fund, the amount collected from utility ratepayers will ceasepay for, among other things, any interest and financing costs related to any bonds that are issued by the California Department of Water Resources to support the contributions to the Wildfire Insurance Fund. Based on a decision adopted by the CPUC in October 2019 in the Order Instituting Rulemaking to Consider Authorization of a Non-Bypassable Charge to Support the Wildfire Insurance Fund, PG&E's ratepayers will not be required to contribute to the fund if PG&E does not participate in the Wildfire Insurance Fund. In that case, $7.5 billion will be collected from SCE's and SDG&E's ratepayers through the dedicated rate component to support a contribution to the Wildfire Insurance Fund.
SCE made an initial contribution of approximately $2.4 billion to the Wildfire Insurance Fund in September 2019 and has committed to make ten annual contributions of approximately $95 million per year to the fund, by no later than January 1 of each year. SCE made its first annual contribution to the Wildfire Insurance Fund in December 2019. Edison International supported SCE's initial contribution to the Wildfire Insurance Fund by raising $1.2 billion from the issuance of Edison International equity. SCE raised the remaining $1.2 billion from the issuance of long-term debt. SCE's contributions to the Wildfire Insurance Fund will not be recoverable through electric rates and will be excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. SCE will also not be entitled to cost recovery for any borrowing costs incurred in connection with its contributions to the Wildfire Insurance Fund. See Note 1 for information on the accounting impact of San Onofre costs asSCE's contributions to the Wildfire Insurance Fund.
Participating investor-owned utilities will be reimbursed from the Wildfire Insurance Fund for eligible claims, subject to the fund administrator's review, and will be required to reimburse the fund for withdrawn amounts that the CPUC disallows, subject, in some instances, to the AB 1054 Liability Cap (as defined below). If the utility has maintained a valid safety certification and its actions or inactions that resulted in the wildfire are not found to constitute conscious or willful disregard of the date their combined remaining San Onofre regulatory assets equal $775 million (the "Cessation Date"rights and safety of others, the aggregate requirement to reimburse the fund over a trailing three calendar year period is capped at 20% of the equity portion of the utility's transmission and distribution rate base in the year of the prudency determination ("AB 1054 Liability Cap"). Based on SCE’s 2020 rate base and assuming the equity portion of SCE's capital structure is 52% (SCE's CPUC authorized capital structure), SCE's requirement to reimburse the Wildfire Insurance Fund for eligible claims disallowed in 2020 would be capped at approximately $3.0 billion.
SCE will not be allowed to recover borrowing costs incurred to reimburse the fund for amounts that the CPUC disallows. The CPUC granted SCE's request to reduceWildfire Insurance Fund, and consequently the San Onofre regulatory asset by applying approximately $72 million of proceeds received from litigation withAB 1054 Liability Cap, will terminate when the DOE related to DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. administrator determines that the fund has been exhausted.
AB 1054 Prudency Standard
As a result of the combined San Onofre regulatory asset balanceestablishment of the Wildfire Insurance Fund, AB 1054 created a new standard that the CPUC must apply when assessing the prudency of a utility in connection with a request for the Utilities reached $775 million on December 19, 2017 and SCE ceased recovery of San Onofrewildfire costs in rates beginning on December 20, 2017. SCE has refundedfor wildfires ignited after July 12, 2019. Under AB 1054, the CPUC is required to customers approximately $155 million of San Onofre-related amounts recovered in rates on and after December 20, 2017. SCE will retain amounts collected under the Prior San Onofre Settlement Agreement before the Cessation Date. SCE will also retain $47 million of proceeds received in 2017 from arbitration with Mitsubishi Heavy Industries ("MHI") over MHI's delivery of faulty steam generators. In the Revised San Onofre Settlement Agreement, SCE retained the right to sell its stock of nuclear fuel and not share such proceeds with customers, as was provided in the Prior San Onofre Settlement Agreement. SCE intends to sell its nuclear fuel inventory as market conditions warrant. Sales of nuclear fuel may be significant.
The Revised San Onofre Settlement Agreement provides certain exclusions from the determination of SCE's ratemaking capital structure. Notwithstanding that SCE will no longer recover its San Onofre regulatory asset, the debt borrowed to finance the regulatory asset will continuefind a utility to be excluded from SCE's ratemaking capital structure. Additionally, SCE may excludeprudent if the after-tax charge resulting from the implementation of the Revised San Onofre Settlement Agreement from its ratemaking capital structure. In connection with the Revised San Onofre Settlement Agreement, and in exchange for the release of certain San Onofre-related claims, the Utilities entered into an agreement ("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 implementation of the Revised San Onofre Settlement Agreement. The following table summarizes the financial impact in 2017 of the Revised San Onofre Settlement Agreement and the Utility Shareholder Agreement:
|
| | | |
| (in millions) |
|
| San Onofre base regulatory asset | $ | 696 |
|
| DOE litigation regulatory liability | (72 | ) |
| MHI Arbitration regulatory liability | (47 | ) |
| GHG Reduction Program | (10 | ) |
| Other | 6 |
|
| Present value of Utility Shareholder Agreement | 143 |
|
| Total pre-tax charge | $ | 716 |
|
| Total after-tax charge | $ | 448 |
|
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 benefitutility's conduct related to the Modification duringignition was consistent with actions that a reasonable utility would have undertaken under similar circumstances, at the third quarterrelevant point in time, and based on the information available at that time. Prudent conduct under the AB 1054 standard is not limited to the optimum practice, method, or act to the exclusion of 2018.others, but rather encompasses a spectrum of possible practices, methods, or acts consistent with utility system needs, the interest of the ratepayers, and the requirements of governmental agencies. AB 1054 also provides that the CPUC may determine that wildfire costs may be recoverable, in whole or in part, by taking into account factors within and outside the utility's control, including humidity, temperature, and winds. Further, utilities with a valid safety certification will be presumed to have acted prudently related to a wildfire ignition unless a party in the cost recovery proceeding creates serious doubt as to the reasonableness of the utility's conduct, at which time, the burden shifts back to the utility to prove its conduct was reasonable. If a utility does not have a valid safety certification, it will have the burden to prove, based on a preponderance of evidence, that its conduct was prudent. The new prudency standard will survive the termination of the Wildfire Insurance Fund.
Utilities participating in the Wildfire Insurance Fund that are found to be prudent are not required to reimburse the fund for amounts withdrawn from the fund and can recover wildfire costs through electric rates if the fund has been exhausted.
109Capital Expenditure Requirement
Under AB 1054, approximately $1.6 billion spent by SCE on wildfire risk mitigation capital expenditures made after August 1, 2019, cannot be included in the equity portion of SCE's rate base. SCE can apply for an irrevocable order from the CPUC to finance these capital expenditures, including through the issuance of securitized bonds, and can recover any prudently incurred financing costs. SCE expects to finance this capital requirement by issuing securitized bonds.
Wildfire Mitigation Plan and Safety Certification
Under AB 1054, SCE is required to submit a wildfire mitigation plan to the CPUC annually for review and approval. Beginning in 2020, each such plan is required to cover at least a three-year period. SCE filed its 2020 Wildfire Mitigation Plan in February 2020.
Under AB 1054, SCE can obtain an annual safety certification upon the submission of certain required safety information, including an approved wildfire mitigation plan. On July 25, 2019, SCE obtained its initial safety certification that will be valid for twelve months.
Environmental Remediation
SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operation and maintenance, monitoring and site closure. Unless there is a single probable amount, SCE records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
At December 31, 2018,2019, SCE's recorded estimated minimum liability to remediate its 2122 identified material sites (sites with a liability balance as of December 31, 2018,2019, in which the upper end of the range of the costs is at least $1 million) was $135$238 million, including $90$177 million related to San Onofre. In addition to these sites, SCE also has 15 immaterial sites with a liability balance at December 31, 20182019 for which the total minimum recorded liability was $4 million. Of the $139$242 million total environmental remediation liability for SCE, $134$237 million has been recorded as a regulatory asset. SCE expects to recover $42$41 million through an incentive mechanism that allows SCE to recover 90% of its environmental remediation costs at certain sites (SCE may request to include additional sites)sites in this mechanism), and $92$196 million through a mechanismproceedings that allowsallow SCE to recover up to 100% of the costs incurred at certain sites through customer rates. SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified
sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs at the identified material sites and immaterial sites could exceed its recorded liability by up to $139$91 million and $7 million, respectively. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.
SCE expects to clean up and mitigate its identified sites over a period of up to 30 years. Remediation costs for each of the next 5 years are expected to range from $6$5 million to $20$15 million. Costs incurred for years ended December 31, 2019, 2018 and 2017 and 2016 were $9 million, $8 million $9 million and $4$9 million, respectively.
Based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, SCE believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to estimates.
Nuclear Insurance
Federal law limits public offsite liability claims for bodily injury and property damage from a nuclear incident to the amount of available financial protection, which is currently approximately $14.1$13.9 billion for Palo Verde and $560 million for San Onofre. As of January 1, 2018,2019, SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($450 million) through a Facility Form issued by American Nuclear Insurers ("ANI"). In the case of San Onofre, the balance is covered by a US Government indemnity. In the case of Palo Verde, the balance is covered by a loss sharing program among nuclear reactor licensees. If a nuclear incident at any licensed reactor in the United States, which is participating in the loss sharing program, results in claims and/or costs which exceed the primary insurance at that plant site, all participating nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.
The ANI Facility Form coverage includes broad liability protection for bodily injury or offsite property damage caused by the nuclear energy hazard at San Onofre or Palo Verde, or while radioactive material is in transit to or from San Onofre or Palo Verde. The Facility Form, however, includes several exclusions. First, it excludes onsite property damage to the nuclear facility itself and onsite cleanup costs, but as discussed below SCE maintains separate Nuclear Electric Insurance Limited ("NEIL") property damage coverage for such events. Second, tort claims of onsite workers are excluded, but SCE also maintains an ANI Master Worker Form policy that provides coverage for non-licensee workers. This program provides a shared industry aggregate limit of $450 million. Industry losses covered by this program could reduce limits available to SCE. Third, offsite environmental costs arising out of government orders or directives, including those issued under the
Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA, are excluded, with minor exceptions from clearly identifiable accidents.
SCE withdrew from participation in the secondary insurance pool for San Onofre for offsite liability insurance effective January 5, 2018. Based on its ownership interests in Palo Verde, SCE could be required to pay a maximum of approximately $65 million per nuclear incident for future incidents. However, it would have to pay no more than approximately $9.7$10 million per future incident in any one year. SCE could be required to pay a maximum of approximately $255 million per nuclear incident and a maximum of $38 million per year per incident for liabilities arising from events prior to January 5, 2018, although SCE is not aware of any such events. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.
SCE is a member of NEIL, a mutual insurance company owned by entities with nuclear facilities. NEIL provides insurance for nuclear property damage, including damages caused by acts of terrorism up to specified limits, and for accidental outages for active facilities. The amount of nuclear property damage insurance purchased for San Onofre and Palo Verde exceeds the minimum federal requirement of $50 million and $1.06$1.1 billion, respectively. These policies include coverage for decontamination liability. Additional outage insurance covers part of replacement power expenses during an accident-related nuclear unit outage. The accidental outage insurance at San Onofre has been canceled as a result of the permanent retirement, but that insurance continues to be in effect at Palo Verde.
If NEIL losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $52 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the DOE is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE has not met its contractual obligation to accept spent nuclear fuel. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for their current license period.
In June 2010, the United States Court of Federal Claims issued a decision granting SCE and the San Onofre co-owners damages of approximately $142 million (SCE share $112 million) to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. SCE received payment from the federal government in the amount of the damage award. In April 2016, SCE, as operating agent, settled a lawsuit on behalf of the San Onofre owners against the DOE for $162 million (SCE share $124 million, which included reimbursement for approximately $2 million in legal and other costs), to compensate for damages caused by the DOE's failure to meet its obligation to begin accepting spent nuclear fuel for the period from January 1, 2006 to December 31, 2013. In August 2018, the CPUC approved SCE's proposal to return the SCE share of the award to customers based on the amount that customers actually contributed for fuel storage costs,costs; resulting in approximately $105.6$106 million of the SCE share being returned to customers and the remaining $16.6$17 million being returned to shareholders. Of the $105.6$106 million, $71.6$72 million was applied against the remaining San Onofre Regulatory Asset in accordance with the Revised San Onofre Settlement Agreement. See Note 11 for further information.
The April 2016 settlement also provided for a claim submission/audit process for expenses incurred from 2014 – 2016, where SCE may submit a claim for damages caused by the DOE failure to accept spent nuclear fuel each year, followed by a government audit and payment of the claim. This process made additional legal action to recover damages incurred in 2014 – 2016 unnecessary. The first such claim covering damages for 2014 – 2015 was filed on September 30, 2016 for approximately $56 million. In February 2017, the DOE reviewed the 2014 – 2015 claim submission and reduced the original request to approximately $43 million (SCE share was approximately $34 million). SCE accepted the DOE's determination, and the government paid the 2014 – 2015 claim under the terms of the settlement. In October 2017, SCE filed a claim covering damages for 2016 for approximately $58 million. In May 2018, the DOE approved reimbursement of approximately $45 million (SCE share was approximately $35 million) of SCE's 2016 damages, disallowing recovery of approximately $13 million. SCE accepted the DOE's determination, and the government paid the 2016 claim under the terms of the settlement. The damages awards are subject to CPUC review as to how the amounts will be refunded among customers, shareholders, or to offset other costs.
In November 2019, SCE filed a new complaint against the DOE to recover damages incurred from January 1, 2017 through July 31, 2018.
Tehachapi Transmission Project
The Tehachapi Transmission Project consists of new and upgraded electric transmission lines and substations between eastern Kern County and San Bernardino County and was undertaken to bring renewable resources in Kern County to energy consumers in the Los Angeles basin and the California energy grid. The project consists of eleven segments. Segments 1-3 were placed in service beginning in 2009 through 2013. Segments 4-11 were placed in service in December 2016.
In December 2019, the CPUC filed a protest alleging that $419 million of costs associated with the Tehachapi Transmission Project are imprudent and should be disallowed from SCE's FERC rate base because these costs exceeded the maximum reasonable cost identified by the CPUC when it granted the project's certificate of public convenience and necessity. The CPUC requested that FERC set this issue for hearings.
Note 13. Leases
Leases as Lessee
SCE enters into various agreements to purchase power, electric capacity and other energy products that may be accounted for as leases when SCE has dispatch rights that determine when and how a plant runs. Prior to January 1, 2019, a power purchase agreement contained a lease when SCE purchased substantially all of the output from a specific plant and did not otherwise meet a fixed price unit of output exception. SCE also leases property and equipment primarily related to vehicles, office space and other equipment. The terms of the contracts included in the table below are primarily 10 to 20 years for PPA leases, 5 to 72 years for office leases, and 5 to 12 years for the remaining other operating leases.
The following table summarizes SCE's lease payments for operating and finance leases as of December 31, 2019:
|
| | | | | | | | | | | |
| (in millions) | PPA Operating Leases1,2 | | Other Operating Leases3 | | PPA Finance Leases1 |
| 2020 | $ | 70 |
| | $ | 37 |
| | $ | 1 |
|
| 2021 | 48 |
| | 30 |
| | 1 |
|
| 2022 | 48 |
| | 24 |
| | 1 |
|
| 2023 | 47 |
| | 19 |
| | 2 |
|
| 2024 | 47 |
| | 14 |
| | 2 |
|
| Thereafter | 489 |
| | 95 |
| | 8 |
|
| Total lease payments | 749 |
| | 219 |
| | 15 |
|
Amount representing interest4 | 220 |
| | 59 |
| | 6 |
|
| Lease liabilities | $ | 529 |
| | $ | 160 |
| | $ | 9 |
|
At December 31, 2018, SCE's future minimum lease payments under non-cancellable leases were as follows:
|
| | | | | | | | | | | |
| (in millions) | PPA Operating Leases1 | | Other Operating Leases3 | | PPA Capital Leases1 |
| 2019 | $ | 148 |
| | $ | 42 |
| | $ | 5 |
|
| 2020 | 124 |
| | 31 |
| | 6 |
|
| 2021 | 103 |
| | 27 |
| | 6 |
|
| 2022 | 79 |
| | 22 |
| | 6 |
|
| 2023 | 47 |
| | 17 |
| | 5 |
|
| Thereafter | 536 |
| | 101 |
| | 66 |
|
| Total lease payments | $ | 1,037 |
| | $ | 240 |
| | $ | 94 |
|
| Amount representing executory costs | | | | | 25 |
|
| Amount representing interest | | | | | 33 |
|
| Net commitments | | | | | $ | 36 |
|
| |
1 | Excludes expected purchases from most renewable energy contracts, which do not meet the definition of a lease payment since renewable power generation is contingent on external factors. |
| |
2 | During the second quarter of 2019, SCE amended 3 power contracts that resulted in a $161 million reduction in ROU assets and lease liabilities as these contracts no longer qualify as leases. |
| |
3 | Excludes escalation clauses based on consumer price or other indices and residual value guarantees that are not considered probable at the commencement date of the lease. |
| |
4 | Lease payments are discounted to their present value using SCE's incremental borrowing rates. |
Supplemental balance sheet information related to SCE's leases was as follows:
|
| | | |
| (in millions) | December 31, 2019 |
| Operating leases: | |
| Operating lease ROU assets | $ | 689 |
|
| Current portion of operating lease liabilities | 79 |
|
| Operating lease liabilities | 610 |
|
| Total operating lease liabilities | $ | 689 |
|
| | |
| Finance leases included in: | |
| Utility property, plant and equipment, gross | $ | 14 |
|
| Accumulated depreciation | (5 | ) |
| Utility property, plant and equipment, net | 9 |
|
| Other current liabilities | 1 |
|
| Other long-term liabilities | 8 |
|
| Total finance lease liabilities | $ | 9 |
|
The timing of SCE's recognition of the lease expense conforms to ratemaking treatment for SCE's recovery of the cost of electricity and is included in purchased power for operating leases and interest and amortization expense for finance leases. The following table summarizes the components of SCE's lease expense:
|
| | | |
| (in millions) | Year ended December 31, 2019 |
| PPA leases: | |
| Operating lease cost | $ | 118 |
|
| Finance lease cost | 1 |
|
Variable lease cost1 | 2,087 |
|
| Total PPA lease cost | 2,206 |
|
| Other operating leases cost | 46 |
|
| Total lease cost | $ | 2,252 |
|
| |
1 | Includes lease costs from renewable energy contracts where payments are based on contingent external factors such as wind, hydro and solar power generation. |
For the year ended 2018 and 2017, operating lease expense for PPAs was $2.3 billion and $2.3 billion, respectively (including contingent rents of $2.1 billion and 1.8 billion, respectively), contingent rents for capital leases were $104 million and $99 million, respectively, and operating lease expense for other leases was $57 million and $59 million, respectively.
Other information related to leases was as follows:
|
| | | |
| (in millions, except lease term and discount rate) | Year ended December 31, 2019 |
| Cash paid for amounts included in the measurement of lease liabilities: | |
| Operating cash flows from operating leases | |
| PPA leases | $ | 118 |
|
| Other leases | 44 |
|
| Financing cash flows from PPA finance leases | 1 |
|
| | |
| ROU assets obtained in exchange for lease obligations: | |
| Other operating leases | 34 |
|
| | |
| Weighted average remaining lease term (in years): | |
| Operating leases | |
| PPA leases | 16.05 |
|
| Other leases | 12.73 |
|
| PPA Finance leases | 11.51 |
|
| | |
| Weighted average discount rate: | |
| Operating leases | |
| PPA leases | 4.46 | % |
| Other leases | 3.88 | % |
| PPA Finance leases | 8.76 | % |
Leases as Lessor
SCE also enters into operating leases to rent certain land and facilities as a lessor. These leases primarily have terms that range from 15 to 65 years. During the year ended December 31, 2019, SCE recognized $18 million in lease income, which is included in operating revenue on the consolidated statements of income. At December 31, 2019, the undiscounted cash flow expected to be received from lease payments for the remaining years is as follows:
|
| | | |
| (in millions) | |
| 2020 | $ | 11 |
|
| 2021 | 10 |
|
| 2022 | 10 |
|
| 2023 | 9 |
|
| 2024 | 8 |
|
| Thereafter | 148 |
|
| Total | $ | 196 |
|
Note 14. Equity
Common Stock Issuances
In May 2019, Edison International filed a prospectus supplement and executed several distribution agreements with certain sales agents to establish an ATM program under which it may sell shares of its common stock having an aggregate sales price of up to $1.5 billion. In the fourth quarter of 2019, Edison International issued 2.8 million shares through the ATM program and received proceeds of $198 million, net of fees and offering expenses of $2 million. The proceeds from the sales were used for equity contributions to SCE and for general corporate and working capital purposes. As of December 31, 2019, shares of common stock having an aggregate offering price of $1.3 billion remained available to be sold under the ATM program. Edison International has no obligation to sell the remaining available shares.
In July 2019, Edison International issued 32.2 million shares of common stock and received proceeds of approximately $2.2 billion, net of fees and offering expenses of $52 million in an underwritten offering. The proceeds were contributed to SCE in a series of equity investments in August and September shown below and for general corporate purposes.
Beginning in July 2019, Edison International settled the ongoing common stock requirements of various internal programs through issuance of new common stock. In the year ended December 31, 2019, 0.6 million shares of new common stock were purchased by employees through the 401(k) defined contribution savings plan for net cash receipts of $41 million, 0.4 million shares of common stock were issued as stock compensation awards for net cash receipts of $22 million and 0.1 million shares of new common stock were issued in lieu of distributing $8 million to shareholders opting to receive dividend payments in the form of additional common stock.
Equity Contributions
In 2019, Edison International Parent made the following equity contributions to SCE:
|
| | | |
| Date of contribution | Amounts (in millions) |
| April 26, 2019 | $ | 750 |
|
| June 21, 2019 | 450 |
|
| August 2, 2019 | 1,200 |
|
| August 30, 2019 | 200 |
|
| September 9, 2019 | 450 |
|
| December 12, 2019 | 200 |
|
| Total | $ | 3,250 |
|
The proceeds from the Edison International Parent equity contribution in 2019 were used to support the initial contribution to the Wildfire Insurance Fund of $2.4 billion, to support SCE's capital program, to increase SCE's equity level, to repay commercial paper borrowings and for general corporate purposes, including the repayment of the February 2019 SCE Term Loan discussed in Note 5.
Preferred and Preference Stock of Utility
SCE's authorized shares are: $100 cumulative preferred – 12 million shares, $25 cumulative preferred – 24 million shares and preference with no par value – 50 million shares. SCE's outstanding shares are not subject to mandatory redemption. There are no dividends in arrears for the preferred or preference shares. Shares of SCE's preferred stock have liquidation and dividend preferences over shares of SCE's common stock and preference stock. See Note 1 for further information on dividend restrictions. All cumulative preferred shares are redeemable. When preferred shares are redeemed, the premiums paid, if any, are charged to common equity. NoNaN preferred shares were issued or redeemed in the years ended December 31, 2019, 2018 2017 and 2016.2017. There is no sinking fund requirement for redemptions or repurchases of preferred shares.
Shares of SCE's preference stock rank junior to all of the preferred stock and senior to all common stock. Shares of SCE's preference stock are not convertible into shares of any other class or series of SCE's capital stock or any other security. There is no sinking fund requirement for redemptions or repurchases of preference shares.
Preferred stock and preference stock is:are: |
| | | | | | | | | | | | | | | | | | |
| | Shares
Outstanding | | Redemption
Price | | Dividends Declared per Share | | December 31, |
| (in millions, except shares and per share amounts) | | | | 2019 | | 2018 |
| Cumulative preferred stock | | | | | | | | | |
| $25 par value: | | | | | | | | | |
| 4.08% Series | 650,000 |
| | $ | 25.50 |
| | $ | 1.020 |
| | $ | 16 |
| | $ | 16 |
|
| 4.24% Series | 1,200,000 |
| | 25.80 |
| | 1.060 |
| | 30 |
| | 30 |
|
| 4.32% Series | 1,653,429 |
| | 28.75 |
| | 1.080 |
| | 41 |
| | 41 |
|
| 4.78% Series | 1,296,769 |
| | 25.80 |
| | 1.195 |
| | 33 |
| | 33 |
|
| Preference stock | | | | | | | | | |
| No par value: | | | | | | | | | |
| 6.25% Series E (cumulative) | 350,000 |
| | 1,000.00 |
| | 62.500 |
| | 350 |
| | 350 |
|
| 5.10% Series G (cumulative) | 160,004 |
| | 2,500.00 |
| | 127.500 |
| | 400 |
| | 400 |
|
| 5.75% Series H (cumulative) | 110,004 |
| | 2,500.00 |
| | 143.750 |
| | 275 |
| | 275 |
|
| 5.375% Series J (cumulative) | 130,004 |
| | 2,500.00 |
| | 134.375 |
| | 325 |
| | 325 |
|
| 5.45% Series K (cumulative) | 120,004 |
| | 2,500.00 |
| | 136.250 |
| | 300 |
| | 300 |
|
| 5.00% Series L (cumulative) | 190,004 |
| | 2,500.00 |
| | 125.000 |
| | 475 |
| | 475 |
|
| SCE's preferred and preference stock | | | | | | | 2,245 |
| | 2,245 |
|
| Less issuance costs | | | | | | | (52 | ) | | (52 | ) |
| Edison International's preferred and preference stock of utility | |
| | |
| | | | $ | 2,193 |
| | $ | 2,193 |
|
|
| | | | | | | | | | | | | | | | | | |
| | Shares
Outstanding | | Redemption
Price | | Dividends Declared per Share | | December 31, |
| (in millions, except shares and per-share amounts) | | | | 2018 | | 2017 |
| Cumulative preferred stock | | | | | | | | | |
| $25 par value: | | | | | | | | | |
| 4.08% Series | 650,000 |
| | $ | 25.50 |
| | $ | 1.020 |
| | $ | 16 |
| | $ | 16 |
|
| 4.24% Series | 1,200,000 |
| | 25.80 |
| | 1.060 |
| | 30 |
| | 30 |
|
| 4.32% Series | 1,653,429 |
| | 28.75 |
| | 1.080 |
| | 41 |
| | 41 |
|
| 4.78% Series | 1,296,769 |
| | 25.80 |
| | 1.195 |
| | 33 |
| | 33 |
|
| Preference stock | | | | | | | | | |
| No par value: | | | | | | | | | |
| 6.25% Series E (cumulative) | 350,000 |
| | 1,000.00 |
| | 62.500 |
| | 350 |
| | 350 |
|
| 5.10% Series G (cumulative) | 160,004 |
| | 2,500.00 |
| | 127.500 |
| | 400 |
| | 400 |
|
| 5.75% Series H (cumulative) | 110,004 |
| | 2,500.00 |
| | 143.750 |
| | 275 |
| | 275 |
|
| 5.375% Series J (cumulative) | 130,004 |
| | 2,500.00 |
| | 134.375 |
| | 325 |
| | 325 |
|
| 5.45% Series K (cumulative) | 120,004 |
| | 2,500.00 |
| | 136.250 |
| | 300 |
| | 300 |
|
| 5.00% Series L (cumulative) | 190,004 |
| | 2,500.00 |
| | 125.000 |
| | 475 |
| | 475 |
|
| SCE's preferred and preference stock | | | | | | | 2,245 |
| | 2,245 |
|
| Less issuance costs | | | | | | | (52 | ) | | (52 | ) |
| Edison International's preferred and preference stock of utility | |
| | |
| | | | $ | 2,193 |
| | $ | 2,193 |
|
Shares of Series E preference stock issued in 2012 may be redeemed at par, in whole or in part, on or after February 1, 2022. Shares of Series G, H, J, K and L preference stock, issued in 2013, 2014, 2015, 2016 and 2017, respectively, may be redeemed at par, in whole, but not in part, at any time prior to March 15, 2018, March 15, 2024, September 15, 2025, March 15, 2026 and June 26, 2022, respectively, if certain changes in tax or investment company law or interpretation (or applicable rating agency equity credit criteria for Series L only) occur and certain other conditions are satisfied. On or after March 15, 2018, March 15, 2024, September 15, 2025, March 15, 2026 and June 26, 2022, SCE may redeem the Series G, H, J, K and L shares, respectively, at par, in whole or in part. For shares of Series H, J and K preference stock, distributions will accrue and be payable at a floating rate from and including March 15, 2024, September 15, 2025 and March 15, 2026, respectively. Shares of Series G, H, J, K and L preference stock were issued to SCE Trust II, SCE Trust III, SCE Trust IV, SCE Trust V and SCE Trust VI, respectively, special purpose entities formed to issue trust securities as discussed in Note 3.
Note 14.15. Accumulated Other Comprehensive Loss
The changes in accumulated other comprehensive loss, net of tax, consist of:
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2019 | | 2018 |
| Beginning balance | $ | (50 | ) | | $ | (43 | ) | | $ | (23 | ) | | $ | (19 | ) |
| Pension and PBOP – net loss: | | | | | | | |
| Other comprehensive loss before reclassifications | (14 | ) | | (9 | ) | | (14 | ) | | (3 | ) |
Reclassified from accumulated other comprehensive loss1 | 5 |
| | 6 |
| | 3 |
| | 4 |
|
Other2 | (10 | ) | | (4 | ) | | (5 | ) | | (5 | ) |
| Change | (19 | ) |
| (7 | ) | | (16 | ) | | (4 | ) |
| Ending balance | $ | (69 | ) | | $ | (50 | ) | | $ | (39 | ) | | $ | (23 | ) |
|
| | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Beginning balance | $ | (43 | ) | | $ | (53 | ) | | $ | (19 | ) | | $ | (20 | ) |
| Pension and PBOP – net gain (loss): | | | | | | | |
| Other comprehensive (loss) income before reclassifications | (9 | ) | | 3 |
| | (3 | ) | | (2 | ) |
Reclassified from accumulated other comprehensive loss1 | 6 |
| | 7 |
| | 4 |
| | 3 |
|
Other2 | (4 | ) | | — |
| | (5 | ) | | — |
|
| Change | (7 | ) |
| 10 |
| | (4 | ) | | 1 |
|
| Ending balance | $ | (50 | ) | | $ | (43 | ) | | $ | (23 | ) | | $ | (19 | ) |
| |
1 | These items are included in the computation of net periodic pension and PBOP expenses. See Note 9 for additional information. |
| |
2 | Edison International and SCE recognized cumulative effect adjustments to the opening balance of retained earnings and accumulated other comprehensive loss on January 1, 2019 and 2018 related to the adoption of the accounting standards update on the reclassification of stranded tax effects resulting from Tax Reform in 2019 and the measurement of financial instruments.instruments in 2018. See Note 1 for further information.information on the reclassification of stranded tax effects. |
Note 15.16. Other Income and Expenses
Other income andnet of expenses areis as follows:
|
| | | | | | | | | | | | |
| | | Years ended December 31, |
| (in millions) | | 2019 | | 2018 | | 2017 |
| SCE other income and (expenses): | | | | | | |
| Equity allowance for funds used during construction | | $ | 101 |
| | $ | 104 |
| | $ | 87 |
|
| Increase in cash surrender value of life insurance policies and life insurance benefits | | 39 |
| | 36 |
| | 42 |
|
| Interest income | | 37 |
| | 24 |
| | 7 |
|
| Net periodic benefit income – non-service components | | 70 |
| | 81 |
| | 51 |
|
| Civic, political and related activities and donations | | (46 | ) | | (44 | ) | | (34 | ) |
| Other | | (6 | ) | | (7 | ) | | (5 | ) |
| Total SCE other income | | 195 |
| | 194 |
| | 148 |
|
| Other income of Edison International Parent and Other: | | | | | | |
| Net periodic benefit costs – non-service components | | (3 | ) | | (2 | ) | | (14 | ) |
| Other | | 1 |
| | 5 |
| | (2 | ) |
| Total Edison International other income | | $ | 193 |
| | $ | 197 |
| | $ | 132 |
|
|
| | | | | | | | | | | | |
| | | Years ended December 31, |
| (in millions) | | 2018 | | 2017 | | 2016 |
| SCE other income and (expenses): | | | | | | |
| Equity allowance for funds used during construction | | $ | 104 |
| | $ | 87 |
| | $ | 74 |
|
| Increase in cash surrender value of life insurance policies and life insurance benefits | | 36 |
| | 42 |
| | 39 |
|
| Interest income | | 24 |
| | 7 |
| | 3 |
|
| Net periodic benefit income – non-service components | | 81 |
| | 51 |
| | 35 |
|
| Civic, political and related activities and donations | | (44 | ) | | (34 | ) | | (32 | ) |
| Other | | (7 | ) | | (5 | ) | | (5 | ) |
| Total SCE other income and (expenses) | | 194 |
| | 148 |
| | 114 |
|
| Other (expenses) and income of Edison International Parent and Other: | | | | | | |
| Net periodic benefit costs – non-service components | | (2 | ) | | (14 | ) | | (5 | ) |
| Other | | 5 |
| | (2 | ) | | — |
|
| Total Edison International other income and (expenses) | | $ | 197 |
| | $ | 132 |
| | $ | 109 |
|
Note 16.17. Supplemental Cash Flows Information
Supplemental cash flows information for continuing operations is: |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Cash payments (receipts): | | | | | | | | | | | |
| Interest, net of amounts capitalized | $ | 705 |
| | $ | 595 |
| | $ | 548 |
| | $ | 615 |
| | $ | 552 |
| | $ | 509 |
|
| Income taxes, net | (85 | ) | | (135 | ) | | 1 |
| | (164 | ) | | (57 | ) | | 2 |
|
| Non-cash financing and investing activities: | | | | | | | | | | | |
| Dividends declared but not paid: | | | | | | | | | | | |
| Common stock | 231 |
| | 200 |
| | 197 |
| | 200 |
| | — |
| | 212 |
|
| Preferred and preference stock | 12 |
| | 12 |
| | 12 |
| | 12 |
| | 12 |
| | 12 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Edison International | | SCE |
| | Years ended December 31, |
| (in millions) | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Cash payments (receipts) for interest and taxes: | | | | | | | | | | | |
| Interest, net of amounts capitalized | $ | 595 |
| | $ | 548 |
| | $ | 504 |
| | $ | 552 |
| | $ | 509 |
| | $ | 475 |
|
| Tax (refunds) payments, net | (135 | ) | | 1 |
| | 18 |
| | (57 | ) | | 2 |
| | 78 |
|
| Non-cash financing and investing activities: | | | | | | | | | | | |
| Dividends declared but not paid: | | | | | | | | | | | |
| Common stock | $ | 200 |
| | $ | 197 |
| | $ | 177 |
| | $ | — |
| | $ | 212 |
| | $ | — |
|
| Preferred and preference stock | 12 |
| | 12 |
| | 12 |
| | 12 |
| | 12 |
| | 12 |
|
SCE's accrued capital expenditures at December 31, 2019, 2018 and 2017 were $643 million, $594 millionand 2016 were $594 million, $652 million, and $540 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.
Note 17.18. Related-Party Transactions
Edison International and SCE provide and receive various services to and from its subsidiaries and affiliates. Services provided to Edison International by SCE are priced at fully loaded cost (i.e., direct cost of good or service and allocation of overhead cost). Specified administrative services such as payroll, employee benefit programs, all performed by Edison International or SCE employees, such as payroll and employee benefit programs, are shared among all affiliates of Edison International. Costs are allocated based on one of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenue, operating expenses, total assets and number of employees). Edison International allocates various corporate administrative and general costs to SCE and other subsidiaries using established allocation factors.
For the years ended December 31, 2019, 2018 and 2017, SCE purchased wildfire liability insurance for premiums of $260 million, $22 million and $144 million respectively, from Edison Insurance Services, Inc. ("EIS"), a wholly-owned subsidiary of Edison International. EIS fully reinsured the exposure for these policies through the commercial reinsurance market, with reinsurance limits and premiums equal to those of the insurance purchased by SCE. The related-party transactions included in SCE's consolidated balance sheets for wildfire-related insurance purchased from EIS were as follows:
| | | | | December 31, | | December 31, |
(in millions)
| | 2018 | | 2017 | | 2019 | | 2018 |
| Long-term insurance receivable due from affiliate | | $ | 1,000 |
| | $ | — |
| |
| Long-term insurance receivables due from affiliate | | | $ | 803 |
| | $ | 1,000 |
|
Prepaid insurance1 | | 13 |
| | 131 |
| | 10 |
| | 13 |
|
Current payables due to affiliate2 | | 4 |
| | 3 |
| | — |
| | 4 |
|
1Reflected in "Prepaid expenses" on SCE's consolidated balance sheets.
2Reflected in "Accounts payable" on SCE's consolidated balance sheets.
The amortization expense for prepaidwildfire-related insurance premiums paid to EIS were $173 million, $140 million and $13 million for the years ended December 31, 2019, 2018 and 2017 respectively.
2Reflected in "Accounts payable" on SCE's consolidated balance sheets.
Note 18.19. Quarterly Financial Data (Unaudited)
Edison International's quarterly financial data is as follows:
|
| | | | | | | | | | | | | | | | |
| | 2019 |
| (in millions, except per share amounts) | | Fourth | | Third | | Second | | First |
| Operating revenue | | $ | 2,970 |
| | $ | 3,741 |
| | $ | 2,812 |
| | $ | 2,824 |
|
| Operating income | | 287 |
| | 636 |
| | 500 |
| | 352 |
|
| Income from continuing operations | | 173 |
| | 502 |
| | 422 |
| | 308 |
|
| Income from discontinued operations, net | | — |
| | — |
| | — |
| | — |
|
| Net income attributable to common shareholders | | 143 |
| | 471 |
| | 392 |
| | 278 |
|
| Basic earnings per share: | | | | | | | | |
| Continuing operations | | $ | 0.40 |
| | $ | 1.36 |
| | $ | 1.20 |
| | $ | 0.85 |
|
| Discontinued operations | | — |
| | — |
| | — |
| | — |
|
| Total | | $ | 0.40 |
| | $ | 1.36 |
| | $ | 1.20 |
| | $ | 0.85 |
|
| Diluted earnings per share: | | | | | | | | |
| Continuing operations | | $ | 0.40 |
| | $ | 1.35 |
| | $ | 1.20 |
| | $ | 0.85 |
|
| Discontinued operations | | — |
| | — |
| | — |
| | — |
|
| Total | | $ | 0.40 |
| | $ | 1.35 |
| | $ | 1.20 |
| | $ | 0.85 |
|
| Dividends declared per share | | 0.6375 |
| | 0.6125 |
| | 0.6125 |
| | 0.6125 |
|
|
| | | | | | | | | | | | | | | | |
| | 2018 |
| (in millions, except per share amounts) | | Fourth | | Third | | Second | | First |
| Operating revenue | | $ | 3,009 |
| | $ | 4,269 |
| | $ | 2,815 |
| | $ | 2,564 |
|
Operating (loss) income1 | | (2,041 | ) | | 739 |
| | 420 |
| | 330 |
|
| (Loss) income from continuing operations | | (1,434 | ) | | 544 |
| | 298 |
| | 242 |
|
| Income from discontinued operations, net | | 34 |
| | — |
| | — |
| | — |
|
| Net (loss) income attributable to common shareholders | | (1,430 | ) | | 513 |
| | 276 |
| | 218 |
|
| Basic (loss) earnings per share: | | | | | | | | |
| Continuing operations | | $ | (4.49 | ) | | $ | 1.57 |
| | $ | 0.85 |
| | $ | 0.67 |
|
| Discontinued operations | | 0.10 |
| | — |
| | — |
| | — |
|
| Total | | $ | (4.39 | ) | | $ | 1.57 |
| | $ | 0.85 |
| | $ | 0.67 |
|
| Diluted (loss) earnings per share: | | | | | | | | |
| Continuing operations | | $ | (4.49 | ) | | $ | 1.57 |
| | $ | 0.84 |
| | $ | 0.67 |
|
| Discontinued operations | | 0.10 |
| | — |
| | — |
| | — |
|
| Total | | $ | (4.39 | ) | | $ | 1.57 |
| | $ | 0.84 |
| | $ | 0.67 |
|
| Dividends declared per share | | 0.6125 |
| | 0.6050 |
| | 0.6050 |
| | 0.6050 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 |
| (in millions, except per-share amounts) | Total | | Fourth | | Third | | Second | | First |
| Operating revenue | $ | 12,657 |
| | $ | 3,009 |
| | $ | 4,269 |
| | $ | 2,815 |
| | $ | 2,564 |
|
Operating (loss) income1 | (552 | ) | | (2,041 | ) | | 739 |
| | 420 |
| | 330 |
|
| (Loss) income from continuing operations | (350 | ) | | (1,434 | ) | | 544 |
| | 298 |
| | 242 |
|
| Income from discontinued operations, net | 34 |
| | 34 |
| | — |
| | — |
| | — |
|
| Net (loss) income attributable to common shareholders | (423 | ) | | (1,430 | ) | | 513 |
| | 276 |
| | 218 |
|
| Basic (loss) earnings per share: | | | | | | | | | |
| Continuing operations | $ | (1.40 | ) | | $ | (4.49 | ) | | $ | 1.57 |
| | $ | 0.85 |
| | $ | 0.67 |
|
| Discontinued operations | 0.10 |
| | 0.10 |
| | — |
| | — |
| | — |
|
| Total | $ | (1.30 | ) | | $ | (4.39 | ) | | $ | 1.57 |
| | $ | 0.85 |
| | $ | 0.67 |
|
| Diluted (loss) earnings per share: | | | | | | | | | |
| Continuing operations | $ | (1.40 | ) | | $ | (4.49 | ) | | $ | 1.57 |
| | $ | 0.84 |
| | $ | 0.67 |
|
| Discontinued operations | 0.10 |
| | 0.10 |
| | — |
| | — |
| | — |
|
| Total | $ | (1.30 | ) | | $ | (4.39 | ) | | $ | 1.57 |
| | $ | 0.84 |
| | $ | 0.67 |
|
| Dividends declared per share | 2.4275 |
| | 0.6125 |
| | 0.6050 |
| | 0.6050 |
| | 0.6050 |
|
| |
1
| In the fourth quarter of 2018, SCE recorded a charge of $2.5 billion for wildfire-related claims, net of expected recoveries from insurance and FERC customers. |
1 In the fourth quarter of 2018, SCE recorded a charge of $2.5 billion for wildfire-related claims, net of expected recoveries from insurance and FERC customers. |
| | | | | | | | | | | | | | | | | | | |
| | 2017 |
| (in millions, except per-share amounts) | Total | | Fourth | | Third | | Second | | First |
| Operating revenue | $ | 12,320 |
| | $ | 3,220 |
| | $ | 3,672 |
| | $ | 2,965 |
| | $ | 2,463 |
|
Operating income (loss)1 | 1,456 |
| | (38 | ) | | 553 |
| | 470 |
| | 471 |
|
Income (loss) from continuing operations2,3 | 668 |
| | (534 | ) | | 501 |
| | 309 |
| | 392 |
|
| Income (loss) from discontinued operations, net | — |
| | — |
| | — |
| | — |
| | — |
|
| Net income (loss) attributable to common shareholders | 565 |
| | (545 | ) | | 470 |
| | 278 |
| | 362 |
|
| Basic earnings (loss) per share: | | | | | | | | | |
| Continuing operations | $ | 1.73 |
| | $ | (1.67 | ) | | $ | 1.44 |
| | $ | 0.85 |
| | $ | 1.11 |
|
| Discontinued operations | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | $ | 1.73 |
| | $ | (1.67 | ) | | $ | 1.44 |
| | $ | 0.85 |
| | $ | 1.11 |
|
| Diluted earnings (loss) per share: | | | | | | | | | |
| Continuing operations | $ | 1.72 |
| | $ | (1.66 | ) | | $ | 1.43 |
| | $ | 0.85 |
| | $ | 1.10 |
|
| Discontinued operations | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | $ | 1.72 |
| | $ | (1.66 | ) | | $ | 1.43 |
| | $ | 0.85 |
| | $ | 1.10 |
|
| Dividends declared per share | 2.2325 |
| | 0.6050 |
| | 0.5425 |
| | 0.5425 |
| | 0.5425 |
|
| |
1
| Expenses 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.See Note 1 for further information.
|
| |
2
| In the fourth quarter of 2017, Edison International Parent and Other recorded a charge of $433 million related to the re-measurement of deferred taxes as a result of Tax Reform. |
| |
3
| In the fourth quarter of 2017, SCE recorded an impairment charge of $716 million ($448 million after-tax) related to the Revised San Onofre Settlement Agreement. |
SCE's quarterly financial data is as follows:
|
| | | | | | | | | | | | | | | | |
| | 2019 |
| (in millions) | | Fourth | | Third | | Second | | First |
| Operating revenue | | $ | 2,958 |
| | $ | 3,732 |
| | $ | 2,800 |
| | $ | 2,816 |
|
| Operating income | | 325 |
| | 649 |
| | 513 |
| | 358 |
|
| Net income | | 224 |
| | 534 |
| | 449 |
| | 323 |
|
| Net income available for common stock | | 194 |
| | 503 |
| | 419 |
| | 293 |
|
| Common dividends declared | | 200 |
| | 200 |
| | — |
| | 200 |
|
| | | | 2018 | 2018 |
| (in millions) | Total | | Fourth | | Third | | Second | | First | | Fourth | | Third | | Second | | First |
| Operating revenue | $ | 12,611 |
| | $ | 2,994 |
| | $ | 4,260 |
| | $ | 2,803 |
| | $ | 2,554 |
| | $ | 2,994 |
| | $ | 4,260 |
| | $ | 2,803 |
| | $ | 2,554 |
|
Operating (loss) income1 | (406 | ) | | (2,013 | ) | | 754 |
| | 439 |
| | 414 |
| | (2,013 | ) | | 754 |
| | 439 |
| | 414 |
|
| Net (loss) income | (189 | ) | | (1,399 | ) | | 567 |
| | 327 |
| | 316 |
| | (1,399 | ) | | 567 |
| | 327 |
| | 316 |
|
| Net (loss) income available for common stock | (310 | ) | | (1,429 | ) | | 536 |
| | 297 |
| | 286 |
| | (1,429 | ) | | 536 |
| | 297 |
| | 286 |
|
| Common dividends declared | 576 |
| | — |
| | 264 |
| | 100 |
| | 212 |
| | — |
| | 264 |
| | 100 |
| | 212 |
|
| |
1
| In the fourth quarter of 2018, SCE recorded a charge of $2.5 billion for wildfire-related claims, net of expected recoveries from insurance and FERC customers. |
|
| | | | | | | | | | | | | | | | | | | |
| | 2017 |
| (in millions) | Total | | Fourth | | Third | | Second | | First |
| Operating revenue | $ | 12,254 |
| | $ | 3,193 |
| | $ | 3,652 |
| | $ | 2,953 |
| | $ | 2,456 |
|
Operating income (loss)1 | 1,547 |
| | (28 | ) | | 569 |
| | 508 |
| | 498 |
|
Net income (loss)2 | 1,136 |
| | (79 | ) | | 497 |
| | 338 |
| | 380 |
|
| Net income (loss) available for common stock | 1,012 |
| | (109 | ) | | 465 |
| | 307 |
| | 349 |
|
| Common dividends declared | 785 |
| | 212 |
| | 191 |
| | 191 |
| | 191 |
|
| |
1
| Expenses 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. See Note 1 for further information. |
| |
2
| In the fourth quarter of 2017, SCE recorded an impairment charge of $716 million ($448 million after-tax) related to the Revised San Onofre Settlement Agreement. |
Due to the seasonal nature of Edison International and SCE's business, a significant amount of revenue and earnings are recorded in the third quarter of each year. As a result of rounding, the total of the four quarters does not always equal the amount for the year.
SELECTED FINANCIAL DATA
Selected Financial Data: 20142015 – 20182019
| | | (in millions, except per-share amounts) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 | |
| (in millions, except per share amounts) | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| Edison International | | | | | | | | | | | | | | | | | | |
Operating revenue1 | $ | 12,657 |
| | $ | 12,320 |
| | $ | 11,869 |
| | $ | 11,524 |
| | $ | 13,413 |
| $ | 12,347 |
| | $ | 12,657 |
| | $ | 12,320 |
| | $ | 11,869 |
| | $ | 11,524 |
|
Operating expenses2 | 13,209 |
| | 10,864 |
| | 9,807 |
| | 9,542 |
| | 10,939 |
| 10,572 |
| | 13,209 |
| | 10,864 |
| | 9,807 |
| | 9,542 |
|
| (Loss) income from continuing operations | (350 | ) | | 668 |
| | 1,413 |
| | 1,082 |
| | 1,536 |
| |
| Income (loss) from continuing operations | | 1,405 |
| | (350 | ) | | 668 |
| | 1,413 |
| | 1,082 |
|
| Income from discontinued operations, net of tax | 34 |
| | — |
| | 12 |
| | 35 |
| | 185 |
| — |
| | 34 |
| | — |
| | 12 |
| | 35 |
|
| Net (loss) income | (316 | ) | | 668 |
| | 1,425 |
| | 1,117 |
| | 1,721 |
| |
| Net (loss) income attributable to common shareholders | (423 | ) | | 565 |
| | 1,311 |
| | 1,020 |
| | 1,612 |
| |
| Weighted-average shares of common stock outstanding | 326 |
| | 326 |
| | 326 |
| | 326 |
| | 326 |
| |
| Basic (loss) earnings per share: | | | | | | | | | | |
| Net income (loss) | | 1,405 |
| | (316 | ) | | 668 |
| | 1,425 |
| | 1,117 |
|
| Net income (loss) attributable to common shareholders | | 1,284 |
| | (423 | ) | | 565 |
| | 1,311 |
| | 1,020 |
|
| Weighted average shares of common stock outstanding | | 340 |
| | 326 |
| | 326 |
| | 326 |
| | 326 |
|
| Basic earnings (loss) per share: | | | | | | | | | | |
| Continuing operations | $ | (1.40 | ) | | $ | 1.73 |
| | $ | 3.99 |
| | $ | 3.02 |
| | $ | 4.38 |
| $ | 3.78 |
| | $ | (1.40 | ) | | $ | 1.73 |
| | $ | 3.99 |
| | $ | 3.02 |
|
| Discontinued operations | 0.10 |
| | — |
| | 0.03 |
| | 0.11 |
| | 0.57 |
| — |
| | 0.10 |
| | — |
| | 0.03 |
| | 0.11 |
|
| Total | $ | (1.30 | ) | | $ | 1.73 |
| | $ | 4.02 |
| | $ | 3.13 |
| | $ | 4.95 |
| $ | 3.78 |
| | $ | (1.30 | ) | | $ | 1.73 |
| | $ | 4.02 |
| | $ | 3.13 |
|
| Diluted (loss) earnings per share: | | | | | | | | | | |
| Diluted earnings (loss) per share: | | | | | | | | | | |
| Continuing operations | (1.40 | ) | | $ | 1.72 |
| | $ | 3.94 |
| | $ | 2.99 |
| | $ | 4.33 |
| 3.77 |
| | $ | (1.40 | ) | | $ | 1.72 |
| | $ | 3.94 |
| | $ | 2.99 |
|
| Discontinued operations | 0.10 |
| | — |
| | 0.03 |
| | 0.11 |
| | 0.56 |
| — |
| | 0.10 |
| | — |
| | 0.03 |
| | 0.11 |
|
| Total | $ | (1.30 | ) | | $ | 1.72 |
| | $ | 3.97 |
| | $ | 3.10 |
| | $ | 4.89 |
| $ | 3.77 |
| | $ | (1.30 | ) | | $ | 1.72 |
| | $ | 3.97 |
| | $ | 3.10 |
|
| Dividends declared per share | 2.4275 |
| | 2.2325 |
| | 1.9825 |
| | 1.7325 |
| | 1.4825 |
| 2.4750 |
| | 2.4275 |
| | 2.2325 |
| | 1.9825 |
| | 1.7325 |
|
Total assets3, 4 | $ | 56,715 |
| | $ | 52,580 |
| | $ | 51,319 |
| | $ | 50,229 |
| | $ | 49,734 |
| $ | 64,382 |
| | $ | 56,715 |
| | $ | 52,580 |
| | $ | 51,319 |
| | $ | 50,229 |
|
| Long-term debt excluding current portion | 14,632 |
| | 11,642 |
| | 10,175 |
| | 10,883 |
| | 10,234 |
| 17,864 |
| | 14,632 |
| | 11,642 |
| | 10,175 |
| | 10,883 |
|
| Capital lease obligations excluding current portion | 9 |
| | 10 |
| | 6 |
| | 7 |
| | 196 |
| |
| Preferred and preference stock of utility | 2,193 |
| | 2,193 |
| | 2,191 |
| | 2,020 |
| | 2,022 |
| 2,193 |
| | 2,193 |
| | 2,193 |
| | 2,191 |
| | 2,020 |
|
| Common shareholders' equity | 10,459 |
| | 11,671 |
| | 11,996 |
| | 11,368 |
| | 10,960 |
| 13,303 |
| | 10,459 |
| | 11,671 |
| | 11,996 |
| | 11,368 |
|
| Southern California Edison Company | | | | | | | | | | | | | | | | | | |
Operating revenue1 | $ | 12,611 |
| | $ | 12,254 |
| | $ | 11,830 |
| | $ | 11,485 |
| | $ | 13,380 |
| $ | 12,306 |
| | $ | 12,611 |
| | $ | 12,254 |
| | $ | 11,830 |
| | $ | 11,485 |
|
Operating expenses2 | 13,017 |
| | 10,707 |
| | 9,648 |
| | 9,436 |
| | 10,854 |
| 10,461 |
| | 13,017 |
| | 10,707 |
| | 9,648 |
| | 9,436 |
|
| Net (loss) income | (189 | ) | | 1,136 |
| | 1,499 |
| | 1,111 |
| | 1,565 |
| |
| Net (loss) income available for common stock | (310 | ) | | 1,012 |
| | 1,376 |
| | 998 |
| | 1,453 |
| |
| Net income (loss) | | 1,530 |
| | (189 | ) | | 1,136 |
| | 1,499 |
| | 1,111 |
|
| Net income (loss) available for common stock | | 1,409 |
| | (310 | ) | | 1,012 |
| | 1,376 |
| | 998 |
|
Total assets4 | $ | 56,574 |
| | $ | 51,515 |
| | $ | 50,891 |
| | $ | 49,795 |
| | $ | 49,456 |
| $ | 64,273 |
| | $ | 56,574 |
| | $ | 51,515 |
| | $ | 50,891 |
| | $ | 49,795 |
|
| Long-term debt excluding current portion | 12,892 |
| | 10,428 |
| | 9,754 |
| | 10,460 |
| | 9,624 |
| 15,132 |
| | 12,892 |
| | 10,428 |
| | 9,754 |
| | 10,460 |
|
| Capital lease obligations excluding current portion | 9 |
| | 10 |
| | 6 |
| | 7 |
| | 196 |
| |
| Preferred and preference stock | 2,245 |
| | 2,245 |
| | 2,245 |
| | 2,070 |
| | 2,070 |
| 2,245 |
| | 2,245 |
| | 2,245 |
| | 2,245 |
| | 2,070 |
|
| Common shareholder's equity | 11,540 |
| | 12,427 |
| | 12,238 |
| | 11,602 |
| | 11,212 |
| 15,582 |
| | 11,540 |
| | 12,427 |
| | 12,238 |
| | 11,602 |
|
Capital structure5: | | | | | |
| | |
| | |
| | | | | |
| | |
| | |
|
| Common shareholder's equity | 43.3 | % | | 49.5 | % | | 50.5 | % | | 48.1 | % | | 49.0 | % | 47.3 | % | | 43.3 | % | | 49.5 | % | | 50.5 | % | | 48.1 | % |
| Preferred and preference stock | 8.4 | % | | 9.0 | % | | 9.3 | % | | 8.6 | % | | 9.0 | % | 6.8 | % | | 8.4 | % | | 9.0 | % | | 9.3 | % | | 8.6 | % |
| Long-term debt | 48.3 | % | | 41.5 | % | | 40.2 | % | | 43.3 | % | | 42.0 | % | 45.9 | % | | 48.3 | % | | 41.5 | % | | 40.2 | % | | 43.3 | % |
| |
1 | Effective January 1, 2018, Edison International and SCE adopted an accounting standards update on revenue recognition, using the modified retrospective method. As a result, prior period amounts were not adjusted to reflect the adoption of this standard. For further information, see Note 1 in the "Notes to Consolidated Financial Statements." |
| |
2 | Expenses for the years ended December 31, 2017, 2016 2015 and 20142015 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." |
3 IncludeIncludes assets from continuing and discontinued operations.
| |
4 | Effective December 31, 2015, Edison International and SCE adopted an accounting standard, retrospectively, that requires all deferred income tax assets and liabilities be presented as noncurrent in the consolidated balance sheet. |
5 This capital structure is based on the financial statements as reported under generally accepted accounting principles and does not factor in the adjustments required to calculate CPUC ratemaking capital structure.
| |
5 | This capital structure is based on the financial statements as reported under generally accepted accounting principles and does not factor in the adjustments required to calculate CPUC ratemaking capital structure. |
The selected financial data was derived from Edison International's and SCE's audited financial statements and is qualified in its entirety by the more detailed information and financial statements, including notes to thesethose financial statements, included in this annual report. References to Edison International refer to the consolidated group of Edison International and its subsidiaries.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Based on an evaluation of Edison International's and SCE's disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as of December 31, 2018,2019, Edison International's and SCE's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by Edison International and SCE in reports that the companies file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, Edison International's and SCE's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by Edison International and SCE in the reports that Edison International and SCE file or submit under the Exchange Act is accumulated and communicated to Edison International's and SCE's management, including Edison International's and SCE's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Management's Report on Internal Control Over Financial Reporting
Edison International's and SCE's respective management are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f), for Edison International and its subsidiaries and SCE, respectively. Under the supervision and with the participation of their respective principal executive officer and principal financial officer, Edison International's and SCE's management conducted an evaluation of the effectiveness of their respective internal controls over financial reporting based on the framework set forth in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on their evaluations under the COSO framework, Edison International's and SCE's respective management concluded that Edison International's and SCE's respective internal controls over financial reporting were effective as of December 31, 2018.2019. Edison International's internal control over financial reporting as of December 31, 20182019 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report on the financial statements included in this report, which is incorporated herein by this reference. This annual report does not include an attestation report of SCE's independent registered public accounting firm regarding internal control over financial reporting. Management's report for SCE is not subject to attestation by the independent registered public accounting firm.
Changes in Internal Control Over Financial Reporting
There were no changes in Edison International's or SCE's internal control over financial reporting during the fourth quarter of 20182019 that have materially affected, or are reasonably likely to materially affect, Edison International's or SCE's internal control over financial reporting.
Jointly Owned Utility Plant
Edison International's and SCE's respective scope of evaluation of internal control over financial reporting includes their Jointly Owned Utility Projects.
OTHER INFORMATION
None.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
BUSINESS
CORPORATE STRUCTURE, INDUSTRY AND OTHER INFORMATION
Edison International was incorporated in 1987 as the parent holding company of SCE, a California public utility.utility incorporated in 1909. Edison International also owns Edison Energy which is engaged in the competitive business of providing energy services to commercial and industrial customers.
The principal executive offices of Edison International and SCE are located at 2244 Walnut Grove Avenue, P.O. Box 976, Rosemead, California 91770, and the telephone numbers are (626) 302-2222 for Edison International and (626) 302-1212 for SCE.
This is a combined Annual Report on Form 10-K for Edison International and SCE. Edison International and SCE make available at www.edisoninvestor.com: Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statements and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, as soon as reasonably practicable after Edison International and SCE electronically file such material with, or furnishes it to, the SEC. Such reports are also available on the SEC's internet website at www.sec.gov. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.
Subsidiaries of Edison International
SCE – Public Utility
SCE is an investor-owned public utility primarily engaged in the business of supplying and delivering electricity through SCE's electrical infrastructure to an approximately 50,000 square-mile area of southern California. SCE serves approximately 5 million customers in its service area. SCE's total number of customers by class were as follows:
| | | (in thousands) | | 2018 | | 2017 | | 2016 | | 2019 | | 2018 | | 2017 |
| Residential | | 4,478 | | 4,448 | | 4,417
| | 4,499 |
| | 4,478 |
| | 4,448 |
|
| Commercial | | 572 | | 569
| | 565
| | 575 |
| | 572 |
| | 569 |
|
| Industrial | | 10 | | 10
| | 10
| | 10 |
| | 10 |
| | 10 |
|
| Public authorities | | 46 | | 46 | | 46
| | 46 |
| | 46 |
| | 46 |
|
| Agricultural and other | | 21 | | 22 | | 23 | | 21 |
| | 21 |
| | 22 |
|
| Total | | 5,127 | | 5,095 | | 5,061 | | 5,151 |
| | 5,127 |
| | 5,095 |
|
In 2018,2019, SCE's total operating revenue of $12.6$12.3 billion was derived as follows: 42.8%43.1% commercial customers, 39.3%38.8% residential customers, 4.3% industrial customers, 4.5%4.4% public authorities, 2.4% agricultural and other, and 6.7%7.0% other operating revenue.
CPUC and FERC rates decouple authorized revenue from the volume of electricity sales and the price of energy procured so that SCE has the opportunity to receive revenue equal to amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity sold to customers does not have a direct impact on SCE's financial results. See "SCE—Overview of Ratemaking Process—CPUC" and "—FERC" for further information.
Edison Energy Group – Energy Service Provider
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 to help them improve managing their energy costs.
During the third quarter of 2017, Edison International completed a strategic review of Edison Energy Group's competitive businesses. At that time, Edison International decided to evaluate strategic options, including the potential sale of SoCore Energy,costs and began to consolidate management across Edison Energy Group.reaching their sustainability goals. In April 2018, Edison Energy Group sold its subsidiary SoCore Energy, which was engaged in providing distributed solar solutions. For more information on the accounting status of SoCore Energy, see "Results of Operations—Edison International Parent and Other" in the MD&A.
Edison Energy will continue to pursue a proof of concept of its existing energy services and managed portfolio solutions practice for large energy users in the United States. Under the proof of concept, Edison Energy will seek to achieve a breakeven earnings run rate and 5% target customer penetration by the end of 2019.
To date, investments in Edison Energy Group are below 1% of the total consolidated assets and operating revenue, and therefore are not material to be reported as a business segment.
Regulation of Edison International as a Holding Company
As a public utility holding company, Edison International is subject to the Public Utility Holding Company Act. The Public Utility Holding Company Act primarily obligates Edison International and its utility subsidiaries to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.
Edison International is not a public utility and its capital structure is not regulated by the CPUC. The 1988 CPUC decision authorizing SCE to reorganize into a holding company structure, however, imposed certain obligations on Edison International and its affiliates. These obligations include a requirement that SCE's dividend policy continue to be established by SCE's Board of Directors as though 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 Edison International and SCE. The CPUC has also promulgated Affiliate Transaction Rules, which, among other requirements, prohibit holding companies from (1) being used as a conduit to provide non-public information to a utility's affiliates and (2) causing or abetting a utility's violation of the rules, including providing preferential treatment to its affiliates.
Employees and Labor Relations
At December 31, 2018,2019, Edison International and its consolidated subsidiaries had an aggregate of 12,57412,937 full-time employees, 12,21912,720 of which were full-time employees at SCE.SCE or its subsidiaries.
Approximately 3,9004,000 of SCE's full-time employees are covered by collective bargaining agreements with the International Brotherhood of Electrical Workers ("IBEW"). The IBEW collective bargaining agreements expire on December 31, 2019.2022.
Insurance
Edison International maintains a property and casualty insurance program for itself and its subsidiaries and excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations. These policies are subject to specific retentions, sub-limits and deductibles, which are comparable to those carried by other utility companies of similar size. SCE also has separate insurance programs for nuclear property and liability, workers compensation solar rooftop construction and wildfires. For further information on nuclear and wildfire insurance, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies."
SCE
Regulation
CPUC
The CPUC has the authority to regulate, among other things, retail rates, utility distribution-level equipment and assets, energy purchases on behalf of retail customers, SCE capital structure, rate of return, issuance of securities, disposition of utility assets and facilities, oversight of nuclear decommissioning funding and costs, and aspects of the transmission system planning, site identification and construction, including safety and environmental mitigation.
FERC
The FERC has the authority to regulate wholesale rates as well as other matters, including unbundled transmission service pricing, rate of return, accounting practices, and licensing of hydroelectric projects. The FERC also has jurisdiction over a portion of the retail rates and associated rate design.
CAISO
Major transmission projects required for reliability and accessing renewable resources are recommended by the CAISO through a regular transmission planning process that highlights the need for and key issues associated with each project. Much of SCE's current transmission investment program is for transmission projects that facilitate access to renewable energy resources in desert and mountain regions east and north of its load center to meet the 33% renewable mandate by 2020. The CAISO will similarly be initiating long-term transmission planning for 50% of SCE's retail electricity to be from qualifying renewable resources by 2030 and is conducting informational studies on achieving higher percentages from qualifying renewable resources.
NERC
The FERC assigned administrative responsibility to the NERC to establish and enforce reliability standards and critical infrastructure protection standards, which protect the bulk power system against potential disruptions from cyber and physical security breaches. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets, including supervisory control and data acquisition systems for the electric grid. Compliance with these standards is mandatory. The maximum penalty that may be levied for violating a NERC reliability or critical infrastructure protection standard is $1 million per violation, per day.
SCE has a formal cyber security programand physical security programs that coverscover SCE's information technology and operational technology systems, as well asincluding customer data. Program staff is engaged with industry groups as well as public-private initiatives to reduce risk and to strengthen the security and reliability of SCE's systems and infrastructure. The program is also engaged in the protection of SCE's customer information.
Nuclear Power Plant Regulation
The NRC has jurisdiction with respect to the safety of San Onofre and Palo Verde Nuclear Generating Stations. The NRC regulates commercial nuclear power plants through licensing, oversight and inspection, performance assessment, and enforcement of its requirements. In June 2013, SCE decided to permanently retire and decommission San Onofre. For further information, see "Liquidity and Capital Resources—SCE—Decommissioning of San Onofre" in the MD&A.
Other Regulatory Agencies
The construction, planning and project site identification of SCE's transmission lines and substation facilities require the compliance with various laws and approval of many governmental agencies in addition to the CPUC and FERC. These include various state regulatory agencies depending on the project location; the CAISO, the US EPA, and other environmental, land management and resource agencies such as the Bureau of Land Management, the U.S. Forest Service, the California Department of Fish and Game, and the California Coastal Commission; the South Coast Air Quality Management District; and regional water quality control boards.the California Water Quality Control Board. In addition, to the extent that SCE transmission line projects pass through lands owned or controlled by Native American tribes, consent and approval from the affected tribes and the Bureau of Indian Affairs are also necessary for the project to proceed.
Overview of Ratemaking Process
CPUC
Revenue authorized by the CPUC through triennial GRC proceedings is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investments in generation and distribution assets and general plant (also referred to as "rate base") on a forecast basis. TheStarting with SCE's 2021 GRC, revenue will be authorized through quadrennial GRC proceedings where the CPUC sets an annual revenue requirement for the base year which is made up of the operation and maintenance costs, depreciation, taxes and a return consistent with the authorized cost of capital (discussed below). In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecast basis. Following the base year, the revenue requirements for the remaining twothree years arewill be set by a methodology established in the GRC proceeding, which has generally, among other items, includesincluded annual allowances for escalation in operation and maintenance costs and additional changes in capital-related investments. The CPUC is conducting a triennial safety model assessment proceeding ("S-MAP") to evaluate the utility models used to prioritize safety risks, examine the utilities' assessment of their key risks and their proposed mitigation programs, and develop requirements for annual reporting of risk spending and mitigation results. The risk assessment approach developed in the S-MAP will be incorporated intoBeginning with SCE's triennial2025 GRC, through a Risk Assessment and Mitigation Phase (RAMP), which will be initiated by NovemberMay 15 in the year preceding each GRC application filing date. SCE's first RAMP was filed in November 2018 for its 2021 GRC. The purpose ofdate, SCE is required to file a Risk Assessment and Mitigation Phase ("RAMP") application with the RAMP isCPUC to provide information about the utility'sSCE's assessment of its key safety risks and its proposed programs and spending for mitigating those risks. The information developed during the RAMP will inform the utility's recommendedinforms SCE's proposed projects and funding requests in the subsequent phase of the GRC.
In September 2016, SCE filed itsSCE's 2018 GRC, Application, which coversa triennial proceeding, authorized revenue requirements for 2018, – 2020.2019 and 2020 were $5.1 billion, $5.5 billion and $5.9 billion, respectively. For further discussion of the 2018 GRC, see "Management Overview—2018 General Rate Case" in the MD&A.
SCE's first RAMP application was timely filed in November 2018 for its 2021 GRC. In August 2019, SCE filed its 2021 GRC Application, which covers 2021 – 2023 in addition to a review of wildfire mitigation spending incremental to amounts authorized in SCE's 2018 GRC incurred from 2018 – 2020. SCE will be required to file an amendment to its 2021 GRC application to expand the filing to include 2024. For further discussion of the 2021 GRC, see "Management Overview – 2021 General Rate Case" in the MD&A.
The CPUC regulates SCE's cost of capital, including its capital structure and authorized rates of return. As of January 1, 2020, SCE's authorized capital structure is 43% long-term debt, 9%5% preferred equity and 48%52% common equity. SCE's 2018 and 20192020 authorized cost of capital consisted of: costconsists of long-term debt of 4.98%4.74%, cost of preferred equity of 5.82%5.70% and return on common
equity of 10.3%. For further discussion of the Cost of Capital, see "Liquidity and Capital Resources—SCE—Regulatory Proceedings—"Management Overview—2020 Cost of Capital"Capital Application" in the MD&A.
SCE's authorized return on investment is established by multiplying an authorized rate of return, determined in separate cost of capital proceedings, by SCE's authorized CPUC rate base.
CPUC rates decouple authorized revenue from the volume of electricity sales and the price of energy procured so that SCE receives revenue equal to amounts authorized. Differences between amounts collected and authorized levels are either collected from or refunded to customers, and, therefore, such differences do not impact operating revenue. Accordingly, SCE is neither benefited nor burdened by the volumetric or price risk related to retail electricity sales.
Cost-recovery balancing accounts (also referred to as cost-recovery mechanisms) are used to track and recover SCE's decoupled costs of fuel and purchased-power,purchased power, as well as certain operation and maintenance expenses, including energy efficiency and demand-side management program costs. SCE earns no return on these activities and although differences between forecasted and actual costs do not impact earnings, such differences do impact cash flows and can change rapidly. SCE has other capital-related balancing accounts on which it earns a return, such as the pole loading balancing account.
SCE's balancing accountcost-recovery mechanism for its fuel and power procurement-relatedpurchased power-related costs is referred to asfacilitated in three main balancing accounts, the ERRA.ERRA, the PABA, and the NSGBA. For all three accounts, SCE sets rates based on an annual forecast of the costs that it expects to incur during the subsequent year. In addition, the CPUC has established a "trigger" mechanism for the ERRA.ERRA and the PABA. The trigger mechanism allowsrequires SCE to request an expeditious rate change if the balancing account overcollection or undercollection either exceeds 5%sum of SCE's prior year generation rate revenue orthe ERRA balance and the bundled service customers' pro-rata share of the PABA balance exceeds 4% of SCE's prior year generation rate revenue and SCE does not expect the aggregate overcollection or undercollection to fall below 4%5% of SCE's prior year generation rate revenue within 120 days. For 2019,2020, SCE estimates the 4% and 5% trigger amounts areto be approximately $213$200 million and $266$250 million, respectively. At December 31, 2018, SCE's undercollection in2019, the ERRA was overcollected by approximately $815$23 million, whichthe PABA was undercollected by approximately $537 million, and the NSGBA was undercollected by $85 million. SCE anticipates will be collected from customers inincorporating these year-end balances into customer rates beginning in April 2019.2020.
The majority of procurement-related costs eligible for recovery through cost-recovery rates are pre-approved by the CPUC through specific decisions and a procurement plan with predefined standards that establish the eligibility for cost-recovery. If such costs are subsequently found to be non-compliant with this procurement plan, then this could negatively impact SCE's earnings and cash flows. In addition, the CPUC retrospectively reviews outages associated with utility-owned generation and SCE's power procurement contract administration activities through the annual ERRA review proceeding. A CPUC finding that SCE was unreasonable or imprudent with respect to its utility-owned generation outages and contract administration activities, could negatively impact SCE's earnings and cash flows.
FERC
Transmission capital and operating costs that are prudently incurred, including a return on its net investment in transmission assets (also referred to as "rate base"), are recovered through revenue authorized by the FERC. Since 2012, SCE has used a formula rate to determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP")(CWIP) revenue requirement. Under operation of the formula rate, transmission revenue will be updated to actual cost of service annually. The transmission revenue requirement and rates are updated each December, to reflect a forecast of costs for the upcoming rate period, as well as a true up of the transmission revenue to actual costs incurred by SCE in the prior calendar year on its formula rate.
The FERC weighted average ROE, including project and other incentives, for the FERC 2018 Settlement Period was 11.2%. In the 2019 Formula Rate case, SCE has requested a new FERC ROE of approximately 11.6%13.25%, inclusive of projects and incentives, with an effective dateas of January 1, 2018 when it filed a new formula rate for 2018. FERC has not issued a final determination on whether SCE's requested 2018 formula rate is just and reasonable, and, as a result, SCE's 2018 rates remainNovember 12, 2019. The 2019 Formula Rate remains subject to refund.hearing and settlement procedures and amounts billed to customers under the 2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved. Once approved, the FERC weighted average ROE can vary based on the mix of project costs that have different incentives. For further information on the current FERC formula rates, related transmission revenue requirements and rate changes, see "Liquidity"Management Overview——2018 and Capital Resources—SCE—Regulatory Proceedings—2019 FERC Formula Rate" in the MD&A.
Retail Rates Structure and Residential Rate Design
To develop retail rates, the authorized revenue requirements are allocated among all customer classes (residential, commercial, industrial, agricultural and street lighting) on a functional basis (i.e., generation, distribution, transmission, etc.). Specific rate components are designed to recover the authorized revenue allocated to each customer class.
SCE has a two-tier residential rate structure with a separate High Usage Charge (HUC)("HUC") for customers consuming more than 400% of average usage. The first tier is priced at below-average cost and is intended to cover the customer's essential electricity needs. The second tier is priced at 25% more than the first tier, and the HUC rate is set at more than twice the rate of the first tier. The CPUC has ordered a transition from tiered to TOU rates for most residential customers unless they opt to stay on the tiered rate structure, and the CPUC approved SCE's plan to beginstructure. SCE anticipates starting that transition in Octoberthe fourth quarter of 2020. To recover a portion of the fixed costs of serving no- or low-usage residential customers, SCE assesses both fixed charges of less than $1 per month, and a minimum charge of $10 per month ($5 for low-income customers), and will seek higher residential fixed charges to be implemented one year after the transition to TOU rates.. For information on residential rates for customers with renewable generation systems, see "—Competition" below.
Energy Efficiency Incentive Mechanism
In September 2013, the CPUC adopted an energy efficiency incentive mechanism called the Efficiency Savings and Performance Incentive Mechanism ("ESPI"). The ESPI is comprised of performance/savings rewards and management fees based on actual energy efficiency expenditures and does not contain any provisions for penalties. The ESPI schedule anticipates payments of the incentive rewards occurring between one and two years after the relevant program year. For further information on the energy efficiency awards, see "Liquidity and Capital Resources—SCE—Regulatory Proceedings—Energy Efficiency Incentive Mechanism" in the MD&A.
Purchased Power and Fuel Supply
SCE obtains the power, energy, and local grid support needed to serve its customers primarily from purchases from external parties. Approximately 14%19% of the needed power in 20182019 was provided by SCE's own generating facilities.
Natural Gas Supply
SCE requires natural gas to meet contractual obligations for power tolling agreements (power contracts in which SCE has agreed to provide or pay for the natural gas used to generate electricity). SCE also requires natural gas to fuel its Mountainview and peaker plants, which are generation units that operate in response to wholesale market signals related to power prices and reliability needs. The physical natural gas purchased by SCE is sourced in competitive interstate markets and at the "citygate" trading point on the SoCalGas local distribution company system. SoCalGas is the primary provider of intrastate pipeline transportation service to the gas-fueled generation stations that SCE controls. In 2015 – 2016, SoCalGas experienced a significant natural gas fuel leak at its Aliso Canyon underground gas storage facility. As a result, there arecontinue to be limitations on the use and capability of the facility. To date, SCE has found that increased gas storage-use restrictions combined with SoCalGas pipeline maintenance constraints increased the cost of electricity for customers but did not impact grid reliability. However, there is no certainty that these restrictions or pipeline constraints will not impact grid reliability in the future. Price increases faced by customers would not affect SCE's earnings because SCE expects recovery of these costs through the ERRA balancing account or other CPUC approved procurement plans. However, these higher prices may impact cash flow due to the timing of those recoveries. For more information on cost-recovery mechanisms, see "—Overview of Ratemaking Process" above. SCE is actively monitoring legislative and regulatory processes that are addressing pipeline and electric grid operations impacted by the Aliso Canyon leak, including an OIIOrder Instituting Investigation issued by the CPUC in February 2017 to consider the feasibility of minimizing or eliminating the use of the Aliso Canyon facility. SCE has also made additional procurement efforts to alleviate the impact of the partial closure of Aliso Canyon, including acceleration of existing contracts for new capacity, energy storage procurement from third-parties, contracting for design, build, and transfer of utility-owned storage, additional demand response procurement, and additional energy efficiency procurement.
CAISO Wholesale Energy Market
The CAISO operates a wholesale energy market primarily in California through which competing electricity generators offer their electricity output to market participants, including electricity retailers. The CAISO schedules power in hourly increments with hourly prices through a day-ahead market in California and schedules power in fifteen-minute and five-minute increments with fifteen-minute and five-minute prices through two real-time markets that cover California and portions of six neighboring states through the Energy Imbalance Market. Both markets optimize energy procurement, ancillary service procurement, unit commitment and congestion management. SCE participates in the day-ahead and real-time markets for the sale of its own generation and generation under contract purchases for its load requirements. The CPUC's Resource Adequacy program imposes resource adequacy requirements on load-serving entities like SCE that are designed to provide sufficient resources to the CAISO to ensure the safe and reliable operation of the grid in real time. The CPUC is considering a central procurement structure for local resource adequacy that would transfer the responsibility for procuring local resource adequacy from load-serving entities to a central procurement entity. There are various central procurement models and central procurement entities being considered, including the investor-owned utilities such as SCE.
Competition
SCE faces retail competition in the sale of electricity to the extent that federal and California laws permit other entitiessources to provide electricity and related services to retail customers within SCE's service area. While retail competition impacts customer rates it does not generally impact SCE's earnings activities. The increased retail competition is fromgovernmental entities formed by cities, counties, and certain other public agencies to generate and/or purchase electricity for their local residents and businesses, known as CCAs. While California law provides only limited opportunities for customers in SCE's service area to choose to purchase power directly from an Electric Service Provider, other than SCE, a limited, phased-in expansion of customer choice ("Direct Access") for nonresidential customers was authorized beginning in 2009, and an additional limited expansion of Direct Access was authorized in 2018. When an SCEa customer who previously took bundled service customer takesfrom SCE converts to taking retail electricity service from an Electric Service Provider or a CCA, SCE remains that customer's transmission and distribution provider. Other forms of departing load include customer generation, and load that departs SCE service entirely to take electricity service from a publicly owned utility or a tribal utility.
California law requires bundled service customer indifferencecustomers remain financially indifferent to departing load customers and to the mass return of departing load customers in the event of an Electric Service Provider or CCA's failure or other service termination. The CPUC is conducting a rulemaking proceeding to review, revise, and consider alternatives to the PCIA a chargemethodology, which determines the charges that isare applied to
departing load customers (including those who take service from CCAs) and is intended to maintain bundled service customer indifference to legacypreviously authorized procurement costs. In October 2018, the CPUC issued a final decision revising the PCIA methodology in a manner that reduceseffectively addressed the cost shifts to remaining bundled service customers. In October 2019, the CPUC issued a final decision implementing a PCIA true-up process to ensure that remaining bundled service and departing load customers are treated equitably. The CPUC is expected to provide guidance on utility portfolio optimization, and pre-payment of PCIA pre-payment optionscharges for entitiesDirect Access customers and CCAs serving departing load customers and implementation of the PCIA true-up process in 2019. 2020.
In February 2018, the CPUC issued a resolution to address cost shifting to bundled service customers associated with utilities' short-term resource adequacy purchases for CCAs in their launch or expansion year. The Resolution requires new and expanding CCAs to submit implementation plans by January 1 in order to serve customers in the following year and also requires new and expanding CCAs to participate in the CPUC's year-ahead resource adequacy program prior to beginning service. In May 2018, the CPUC issued a final decision to adopt a financial security requirement for CCAs, which is intended to cover the re-entry fees imposed on CCA customers for incremental procurement and administrative costs if they are involuntarily returned en masse to the utility's procurement service. The CPUC has not yet authorized SCE and other investor-owned utilities to implement this decision in its tariffs.
As of year-end 2018,2019, SCE had six CCAs serving customers in its service territory that represent less than 4%20% of SCE's total service load. One CCA has been approved to significantly expandexpanded in 2019 and approximately 10six new or expanded CCAs have submitted implementation plansbeen approved by the CPUC to serve customers in 2020. Based on recent load statistics, SCE anticipates that Direct Access and CCA load will be approximately 35% of its total service load by the end of 2019 and approximately 45% by the end of 2020.
Customer-owned power generation and storage alternatives, such as roof-top solar facilities and battery systems, are increasingly used by SCE's customers as a result of technological developments, federal and state subsidies, and declining costs of such alternatives. Beginning in 2020, and subject to certain exceptions, California will require all newly built homes to be solar-powered.
California legislation passed in 1995 encouraged private residential and commercial investment in renewable energy resources by requiring SCE and other investor-owned utilities to offer a NEM billing option to customers who install eligible power generation systems to supply all or part of their energy needs. NEM customers are interconnected to SCE's grid and credited for the net difference between the electricity SCE supplied to them through the grid and the electricity the customer exported to SCE over a twelve month12-month period. SCE is required to credit the NEM customer for most of the power they sell back to SCE at the retail rate. Through the credit they receive, NEM customers effectively avoid paying certain grid-related costs. NEM customers are also exempted from some non-bypassable, standby and departing load charges and interconnection fees. Electric Service Providers and CCAs are not required by law to offer NEM rates.
In January 2016, the CPUC issued a decision implementing AB 327, a rate reform bill enacted in 2013 that instructed the CPUC to develop new standard rates for customers with renewable generation systems. The changes that the CPUC decision made to the existing NEM tariff do not significantly impact the NEM subsidy. Specifically, the decision requires customers that take service on SCE's NEM tariff after June 2017 to continue to be compensated at the retail rate, minus certain non-bypassable charges. NEM customers also continue to be exempted from standby and departing load charges but will beare required to pay a $75 interconnection fee and to select a TOU retail rate. The CPUC will consider making additional adjustments to the NEM tariff when it adopts default TOU rates in 2019.
The effect of these types of competition on SCE generally is to reduce the amount of electricity purchased by retail customers. Customers who use alternative electricity providerssources typically continue to utilize and pay for SCE's transmission and distribution services, however, NEM customers utilize, but do not pay the full cost for, those services. While changes in volume or rates generally do not impact SCE's earnings activities, decreased retail electricity sales by SCE has the effect of increasing utility rates because the costs of the distribution grid are not currently borne by all customers that benefit from its use. See "Risk Factors—Risks Relating to Southern California Edison Company—Competitive and Market Risks."
In the area of transmission infrastructure, SCE has experienced increased competition from independent transmission providers under the FERC's transmission planning requirements rules, effective in 2011, that removed the incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities and mandated regional and interregional transmission planning. Regional entities, such as independent system operators, have processes for regional and interregional transmission planning and the competitive solicitation and selection of developers (including incumbent utilities) to build and own certain types of new transmission projects. The CAISO has held competitive solicitations pursuant to these rules and independent service providers were selected.
Properties
SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, which include sub-transmission facilities and are located primarily in California but also in Nevada and Arizona, deliver power from generating sources to the distribution network and consist of lines ranging from 33 kV to 500 kV and substations. SCE's distribution system, which takes power from substations to customers, includes over 53,000 line milesline-miles of overhead lines, 38,000 line milesline-miles of underground lines and approximately 800 substations, all of which are located in California. SCE owns thehas ownership interests in generating and energy storage facilities, listedprimarily located in the following table:California, that generate approximately 7,000 megawatts of net physical capacity, of which SCE's pro-rata share is approximately 3,000 megawatts.
|
| | | | | | | | | | | | | | | | |
| Generating and Energy Storage Facility | | Location (in CA, unless otherwise noted) | | Fuel Type | | Operator | | SCE's Ownership Interest (%) | Net Physical Capacity (in MW) | | SCE's Capacity pro rata share (in MW) |
Hydroelectric Plants (33)1 | | Various | | Hydroelectric | | SCE | | 100 | % | 1,177 |
| | | 1,177 |
| |
| Pebbly Beach Generating Station (including battery storage) | | Catalina Island | | Diesel/Liquid Petroleum Gas | | SCE | | 100 | % | 12 |
| 2 | | 12 |
| 2 |
| Mountainview Units 3 and 4 | | Redlands, CA | | Natural Gas | | SCE | | 100 | % | 1,072 |
| | | 1,072 |
| |
| Peaker Plants (3) | | Various | | Natural Gas | | SCE | | 100 | % | 147 |
| | | 147 |
| |
Enhanced Peaker Plants (2) (gas turbine and battery storage) | | Various | | Natural gas | | SCE | | 100 | % | 100 |
| 3 | | 100 |
| 3 |
| Palo Verde Nuclear Generating Station | | Phoenix, AZ | | Nuclear | | APS4 | | 15.8 | % | 4,235 |
| | | 669 |
| |
| Solar PV Plants (25) | | Various | | Photovoltaic | | SCE | | 100 | % | 68 |
| | | 68 |
| |
| Fuel Cells (2) | | Various | | Natural Gas | | SCE | | 100 | % | 2 |
| | | 2 |
| |
| Mira Loma Energy Storage (2) | | Ontario, CA | | Electricity | | SCE | | 100 | % | 20 |
| | | 20 |
| |
Energy Storage Projects (5)
| | Various | | Electricity | | SCE | | 100% |
| 16.6 |
| | | 16.6 |
| |
| Total | | | | | | | | |
| 6,849.6 |
| | | 3,283.6 |
| |
| |
1
| In addition to the 33 hydroelectric plants, includes 2 small generators representing an aggregate capacity of 1 MW. |
| |
2
| Pebbly Beach Generating Station consists of 11 MW of diesel generators and liquid petroleum gas micro-turbines and a 1 MW of battery system. |
| |
3
| Each enhanced peaker plant consists of one 49.9 MW gas turbine supported by a 10 MW battery storage system. |
| |
4
| Arizona Public Service, an investor-owned electric utility. |
Certain of SCE's substations, and portions of its transmission, distribution and communication systems are located on lands owned by the federal, state or local governments under licenses, permits, easements or leases, or on public streets or highways pursuant to franchises. Certain of the documents evidencing such rights obligate SCE, under specified circumstances and at its expense, to relocate such transmission, distribution, and communication facilities located on lands owned or controlled by federal, state, or local governments.
The majority of SCE'sSCE owns and operates hydroelectric plants and related reservoirs, the majority of which are located in whole or in part on U.S.-owned lands and are subject to FERC licenses. Slightly over half of these plants have FERC licenses that expire at various times between 2021 and 2046. FERC licenses impose numerous restrictions and obligations on SCE, including the right of the United States to acquire projects upon payment of specified compensation. When existing licenses expire, the FERC has the authority to issue new licenses to third parties that have filed competing license applications, but only if their license application is superior to SCE's and then only upon payment of specified compensation to SCE. New licenses issued to SCE are expected to contain more restrictions and obligations than the expired licenses because laws enacted since the existing licenses were issued require the FERC to give environmental objectives greater consideration in the licensing process. In addition, SCE expects additional opposition to new licenses by environmental stakeholder groups. If, in the future, SCE decides to, or is forced to, decommission one or more hydroelectric projects, the costs related to the decommissioning will be substantial. SCE does not currently recover decommissioning costs for hydroelectric projects in rates but plans to request recovery of anticipated decommissioning costs for hydroelectric projects in a future applications to the CPUC.
Substantially all of SCE's properties are subject to the lien of a trust indenture securing first and refunding mortgage bonds. See "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
Seasonality
Due to warm weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than the other quarters. However, as discussed above, SCE earnings are not affected by changes in retail electricity sales. See "Overview of Ratemaking Process" above.
ENVIRONMENTAL CONSIDERATIONS
Greenhouse Gas Regulation
Edison International recognizes that its industry and the global economy are in the midst of a profound transformation toward a low-carbon future as a response to climate change. SCE plans to be a key enabler of the adoption of new energy technologies that benefit customers of the electric grid. See "Management Overview—Electricity Industry Trends" in the MD&A.
Approximately 14%19% of power delivered to SCE's customers in 20182019 came from utility-owned generation. In 2018,2019, the sources of utility-owned generation were largely carbon-free, with approximately 6%8% nuclear, 4%6% large hydroelectric, 3% natural gas, less than 1% small hydroelectric, and less than 1% solar generation. Approximately 35%5% were natural gas sources. Since 2010, SCE has reported its annual GHG emissions from utility-owned generation each year to the US EPA by March 31 of power that SCE deliveredthe following year. SCE's 2019 GHG emissions from utility-owned generation are estimated to customers in 2018 came from renewable sources.be approximately 1,290,000 metric tons.
Federal Regulation
In 2015,June 2019, the US EPA issued rules governing GHG emission standards for existing fossil-fuel power plants. Known as the Clean Power Plan, the rules established state-specific goals and guidelines for the reduction of GHG emissions from existing sources. In 2016, the US Supreme Court blocked the implementation of the Clean Power Plan pending the completion of judicial challenges. In August 2018, the US EPA proposedadopted the Affordable Clean Energy Rule, to replace the Clean Power Plan. The Affordable Clean Energy Rule, if adopted, will establishwhich establishes GHG emissions guidelines for states to use to develop plans to address GHG emissions from existing coal-fired power plants. Litigation filed in August 2019, by California and 28 public entities to block the implementation of the Affordable Clean Energy Rule is pending. SCE does not expect the impact of the Affordable Clean Energy Rule to be material because it does not own or purchase power from coal-fired generating facilities and a significant portion of the power it delivers to its customers comes from renewable resources.facilities.
California Regulation
In 2006, California adoptedis committed to reducing its GHG emissions, improving local air quality and supporting continued economic growth. California’s major initiatives for reducing GHG emissions include a law that targets the reduction of GHG emissions across the entire state economy to 40% below 1990 levels by 2030, an Executive Order that targets the reduction of GHG emissions across the entire state economy to 80% below 1990 levels by 2050, and a California cap-and-trade program established a comprehensive program to reduce GHG emissions. The law requiredby the California Air Resources Board ("CARB") to develop regulations that would reduce California's GHG emissions to 1990 levels by 2020. In 2012,. Other major policy measures include the CARB regulations established a California cap-and-trade program and in July 2017, California law extended California's market-based GHG reduction regulatory framework, which includes the Cap-and-Trade and Low Carbon Fuel Standard programs, to 2030. program established by CARB.
In the California cap-and-trade program, all covered GHG emitters, including SCE, are subject to a "cap" on their emissions designed to encourage entities to reduce emissions from their operations. Covered entities must remit a compliance instrument for each ton of carbon dioxide equivalent gas emitted and can do so buying state-issued emission allowances at auction or purchasing them in the secondary allowance market. GHG emitters can also meet up to 8% of their cap-and-trade obligations by participating in verified offset programs, such as reforestation, that have recognized effects on reducing atmospheric GHGs.
California has adopted RPS targets which require California retail sellers of electricity to provide certain percentages of energy sales from renewable resources defined in the statute, including 33% of retail sales by December 2020; 44% of retail sales by December 2024, 52% of retail sales by December 2027, and 60% of retail sales by December 2030. Approximately 36% of SCE's supply portfolio in 2018 came from renewable sources eligible under California's RPS. SCE estimates that approximately 38% of its supply portfolio in 2019 came from renewable sources eligible under California's RPS, of which 35% was delivered to customers and 3% was sold for resale. As such, SCE has already met California's 2020 RPS target. Separate from RPS targets, California also requires all retail electricity sales to be from carbon-free resources (such as hydroelectric energy) by 2045. In 2019 approximately 48% of SCE's customer deliveries came from carbon-free resources. California also supports climate action to meet the December 2015 Paris Agreement. SCE's climate change objectives align with California’s requirements, and SCE anticipates it will meet its own objectives, and therefore California’s requirements, through 2045.
Additionally, the CPUC and the California Energy Commission adopted GHG emission performance standards that apply to California investor-owned and publicly owned utilities' long-term arrangements for the purchase of electricity. The standards that have been adopted prohibit these entities, including SCE, from owning or entering into long-term financial commitments with generators, such as coal plants, that emit more GHG than a combined-cycle natural gas turbine generator.
California law also requires California retail sellers of electricity to deliver 33% of their customers' electricity requirements from renewable resources, as defined in the statute, by 2020. The CPUC set delivery quantity requirements applicable to SCE that incrementally increase to 33% over several periods between January 2011 and December 2020. In September 2018, California enacted a law that increased the amount of electricity from renewable resources that California retail sellers must deliver after 2020 to 44% of retail sales by December 2024, 52% of retail sales by December 2027, and 60% of retail sales by December 2030. In September 2018, California also enacted a requirement that the remaining 40% of retail electricity sales not from renewable energy must be from “zero-carbon” resources (such as hydroelectric energy) by 2045. SCE's delivery of eligible renewable energy to customers was approximately 21% of its total energy portfolio for the compliance period 2011 – 2013, which met SCE's goal for that period. SCE also met its compliance goal for the compliance period 2014 – 2016 by supplying its customer load with approximately 25% eligible renewable energy. SCE's 2017 eligible renewable energy deliveries were approximately 32% of its total energy portfolio. SCE estimates its 2018 eligible renewable energy deliveries to be approximately 35% of its total energy portfolio. SCE anticipates that it will comply with the requirements through 2030.
California has also enacted a law that requires the reduction of GHG emissions across the entire state economy to 40% below 1990 levels by 2030. California also supports climate action to meet the December 2015 Paris Agreement. Edison International supports these California environmental initiatives and believeshas undertaken analysis which, consistent with third-party analysis, shows that this change in focus electrification across multiple sectors, including transportation and industrial sectors, is among the most cost-effective ways to achieve California's goals. Edison International and SCE believe that these initiatives
will likely lead to increased electrification ofacross the transportationeconomy and industrial sectors. A companion billSCE is investing in grid technologies and charging infrastructure to the emission reduction law prioritized direct emission reductions, established joint-legislative oversight committee on climate change, and highlighted the increasing California legislative focus on disadvantaged community impacts of air pollution and climate change. See "Management Overview—Electricity Industry Trends" in the MD&A
Since 2010, SCE has reported its annual emissions from utility-owned generation each year to the US EPA by March 31 of the following year. SCE's 2018 GHG emissions from utility-owned generation are estimated to be approximately 813,000 metric tons.support California's goals.
Environmental Risks
Severe droughts and windstorms contributed to the devastating wildfires that swept through parts of California in 2017 and 2018, demonstrating the serious threat that weather extremes caused by climate change pose to California's communities and the environment. See "Management Overview—Southern California Wildfires and Mudslides" in the MD&A. Severe weather events, including drought, increasingly severe wind stormswindstorms and rising sea-levels, pose risks to SCE's infrastructure and SCE and Edison International are investing in building a more resilient grid to reduce climate- and weather-related vulnerabilities. See "Management Overview—Capital Program—Grid Development"Wildfire Mitigation and Wildfire Insurance Expenses" in the MD&A.
For more information on risks related to climate change, environmental regulation, and SCE's business strategy, see "Risk Factors—Risks Relating to Southern California Edison Company—Operating Risks."
UNRESOLVED STAFF COMMENTS
None.
PROPERTIES
As a holding company, Edison International does not directly own any significant properties other than the stock of its subsidiaries. The principal properties of SCE are described above under "Business—SCE—Properties."
LEGAL PROCEEDINGS
Thomas Fire and Koenigstein Fire Litigation
In December 2017, several wind-driven wildfires impacted portions of SCE's service territory, and causedcausing loss of life, substantial damage to both residential and business properties, and service outages for SCE customers. The VCFD and CAL FIRE have determined that the largest of thesethe 2017 fires knownoriginated on December 4, 2017, in the Anlauf Canyon area of Ventura County (the investigating agencies refer to this fire as the Thomas Fire, originated in Ventura County and burned acreage located in both Ventura and Santa Barbara Counties."Thomas Fire"), followed shortly thereafter by the Koenigstein Fire. According to CAL FIRE, information, the Thomas Fireand Koenigstein Fires burned over 280,000 acres, destroyed or damages an estimated 1,063 structures, damaged an estimated 2801,343 structures and resulted in two fatalities.
As of February 26, 2019,24, 2020, SCE was aware of at least 132328 lawsuits, representing approximately 2,1004,845 plaintiffs, related to the Thomas Fireand Koenigstein Fires naming SCE as a defendant. Sixty-sevenOne Hundred Forty-two of these lawsuits also name Edison International as a defendant based on its ownership and alleged control of SCE. At least four of the lawsuits were filed as purported class actions. The lawsuits, which have been filed in the superior courts of Ventura, Santa Barbara and Los Angeles Counties allege, among other things, negligence, inverse condemnation, trespass, private nuisance, and violations of the public utilities and health and safety codes. By order of the Chair of the California Judicial Council, theThe lawsuits have been coordinated in the Los Angeles Superior Court. Three categories of plaintiffs have filed lawsuits against SCE and Edison International relating to the Thomas Fire, Koenigstein Fire and Montecito Mudslides: individual plaintiffs, subrogation plaintiffs and public entity plaintiffs. An initial jury trial for a limited number of plaintiffs, sometimes referred to as a bellwether jury trial, on certain fire only matters is scheduled for June 15, 2020.
In November 2019, SCE and Edison International reached a settlement with certain local public entity plaintiffs in the Thomas Fire, Koenigstein Fire and Montecito Mudslides litigation under which SCE paid those local public entity plaintiffs parties an aggregate of $150 million and, other than as set forth below, the plaintiffs released SCE and Edison International from all claims and potential claims in the Thomas Fire, Koenigstein Fire and Montecito Mudslides litigation and/or related to or arising from the Thomas Fire, Koenigstein Fire or Montecito Mudslides. Certain of the local public entity plaintiffs will retain the right to pursue certain indemnity claims against SCE and Edison International. Edison International and SCE did not admit liability as part of the settlement.
For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."
Montecito Mudslides Litigation
In January 2018, torrential rains in Santa Barbara County produced mudslides and flooding in Montecito and surrounding areas. According to Santa Barbara County initial reports, the Montecito Mudslides destroyed an estimated 135 structures, damaged an estimated 324 structures, and resulted in at least 21 fatalities, with two additional fatalities presumed.
Fifty-fiveEighty-one of the 132328 lawsuits mentioned under "Thomas Fire and Koenigstein Fire Litigation" above allege that SCE has responsibility for the Thomas Fireand/or Koenigstein Fires and that the Thomas Fireand/or Koenigstein Fires proximately caused the Montecito Mudslides, resulting in the plaintiffs' claimed damages. Twenty-oneForty of the 5581 Montecito Mudslides lawsuits also name Edison International as a defendant based on its ownership and alleged control of SCE. In addition to other causes of action, some of the Montecito Mudslides lawsuits also allege personal injury and wrongful death. By order ofThe Thomas and Koenigstein Fires lawsuits and the Chair of the California Judicial Council, the Thomas Fire and Montecito Mudslides lawsuits have been coordinated in the Los Angeles Superior Court. Three categories of plaintiffs have filed lawsuits against SCE and Edison International relating to the Thomas Fire, Koenigstein Fire and Montecito Mudslides: individual plaintiffs, subrogation plaintiffs and public entity plaintiffs. An initial jury trial for a limited number of plaintiffs, sometimes referred to as a bellwether jury trial, is scheduled for October 12, 2020.
In November 2019, SCE and Edison International reached a settlement with certain local public entity plaintiffs in the Thomas Fire, Koenigstein Fire and Montecito Mudslides litigation under which SCE paid those local public entity plaintiffs parties an aggregate of $150 million and, other than as set forth below, the plaintiffs released SCE and Edison International from all claims and potential claims in the Thomas Fire, Koenigstein Fire and Montecito Mudslides litigation and/or related to or arising from the Thomas Fire, Koenigstein Fire or Montecito Mudslides. SCE and Edison International did not release their cross-claims against the public entity plaintiffs in the Montecito Mudslides litigation, and certain of the public entity plaintiffs will retain the right to pursue certain indemnity claims against SCE and Edison International. Edison International and SCE did not admit liability as part of the settlement.
For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."
Woolsey Fire Litigation
In November 2018, several wind-driven wildfires impacted portions of SCE's service territory and caused substantial damage to both residential and business properties and service outages for SCE customers. The largest of these fires, known as the Woolsey Fire, originated in Ventura County and burned acreage located in both Ventura and Los Angeles Counties. According to CAL FIRE, information, the Woolsey Fire burned almost 100,000 acres, destroyed an estimated 1,643 structures, damaged an estimated 364 structures and resulted in three fatalities. Two additional fatalities have also been associated with the Woolsey Fire.
As of February 26, 2019,24, 2020, SCE was aware of at least 26193 lawsuits, representing approximately 4003,605 plaintiffs, related to the Woolsey Fire naming SCE as a defendant. SeventeenOne Hundred Twenty-nine of these lawsuits also name Edison International as a defendant based on its ownership and alleged control of SCE. At least two of the lawsuits were filed as purported class actions. The lawsuits, which have been filed in the superior courts of Ventura and Los Angeles Counties allege, among other things, negligence, inverse condemnation, personal injury, wrongful death, trespass, private nuisance, and violations of the public utilities and health and safety codes. The Woolsey Fire lawsuits have also been recommended for coordinationcoordinated in the Los Angeles Superior Court. Three categories of plaintiffs have filed lawsuits against SCE and Edison International relating to the Woolsey Fire: individual plaintiffs, subrogation plaintiffs and public entity plaintiffs.
In November 2019, SCE and Edison International reached a settlement with certain local public entity plaintiffs in the Woolsey Fire litigation under which SCE paid the local public entity plaintiffs an aggregate of $210 million and those local public entity plaintiffs released SCE and Edison International from all claims and potential claims in the Woolsey Fire litigation and/or related to or arising from the Woolsey Fire. Edison International and SCE did not admit liability as part of the settlement.
For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."
MINE SAFETY DISCLOSURE
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS OF EDISON INTERNATIONAL
Executive Officers of Edison International
|
| | | | |
| Executive Officer | | Age at
February 26, 201920, 2020 | | Company Position |
| Pedro J. Pizarro | | 5354 | | President and Chief Executive Officer |
| Maria Rigatti | | 5556 | | Executive Vice President and Chief Financial Officer |
| Adam S. Umanoff | | 5960 | | Executive Vice President and General Counsel |
J. Andrew MurphyCaroline Choi | | 5851 | | Senior Vice President, Strategic PlanningCorporate Affairs |
Gaddi H. VasquezJ. Andrew Murphy | | 6459 | | Senior Vice President, Government AffairsStrategy and Corporate Development |
| Jacqueline Trapp | | 52 | | Senior Vice President, Human Resources |
| Kevin M. Payne | | 5859 | | President and Chief Executive Officer, SCE |
Ronald O. NicholsSteven D. Powell | | 6541 | | Executive Vice President, Operations, SCE |
Caroline Choi | | 50 | | Senior Vice President, Corporate Affairs |
As set forth in Article IV of Edison International's and the relevant subsidiary's Bylaws, the elected officers of Edison International and its subsidiaries are chosen annually by, and serve at the pleasure of, Edison International and the relevant subsidiary's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the officers of Edison International and its subsidiaries have been actively engaged in the business of Edison International and its subsidiaries for more than five years, except for Messrs. Umanoff, Nichols, andMr. Murphy, and have served in their present positions for the periods stated below. Additionally, those officers who have had other or additional principal positions in the past five years had the following business experience during that period:
|
| | | | |
| Executive Officers | | Company Position | | Effective Dates |
Pedro J. Pizarro
| | Chief Executive Officer, Edison International President, Edison International President, SCE President, EME1
| | September 2016 to present June 2016 to present October 2014 to June 2016 January 2011 to March 2014
|
| | | | | |
| Maria Rigatti | | Executive Vice President and Chief Financial Officer, Edison International Senior Vice President and Chief Financial Officer, SCE President, Edison Mission Reorganization Trust (EME Reorg Trust)1
Senior Vice President, Chief Financial Officer, EME2
| | September 2016 to present July 2014 to September 2016 April 2014 to June 2014
March 2011 to March 2014
|
| | | | | |
| Adam S. Umanoff | | Executive Vice President and General Counsel, Edison International Partner, Akin Gump Strauss Hauer & Feld3
| | January 2015 to present May 2011 to December 2014
|
| | | | |
J. Andrew Murphy | | Senior Vice President, Strategy and Corporate Development, Edison International
Senior Managing Director, Macquarie Infrastructure and Real Assets4
| | September 2015 to present
January 2012 to August 2015
|
| | | | |
Gaddi H. Vasquez | | Senior Vice President, Government Affairs, Edison International and SCE | | April 2013 to present |
| | | | |
Jacqueline Trapp | | Senior Vice President, Human Resources Officer, Edison International and SCE
Vice President, Human Resources Officer, SCE Director, Executive Talent and Rewards, Edison International
| | February 2018 to present June 2016 to February 2018
July 2012 to June 2016
|
| | | | |
Kevin M. Payne | | Chief Executive Officer, SCE
Senior Vice President, Customer Service, SCE
Vice President, Engineering and Technical Services, SCE
| | June 2016 to present
March 2014 to June 2016
September 2011 to February 2014
|
| | | | |
Ronald O. Nichols | | President, SCE
Senior Vice President, Regulatory Affairs, SCE
General Manager/Chief Executive Officer, Los Angeles Department of Water and Power5
| | June 2016 to present
April 2014 to June 2016
January 2011 to February 2014
|
| | | | | |
| Caroline Choi | | Senior Vice President, Corporate Affairs, Edison International and SCE Senior Vice President, Regulatory Affairs, SCE Vice President Integrated Planning andEnergy & Environmental Affairs,Policy, SCE
| | February 2019 to present June 2016 to February 2019 January 2012 to June 2016 |
| | | | |
1
J. Andrew Murphy | EME Reorg Trust was an entity formed as part of the EME bankruptcy to hold creditors' interests after the sale of EME's assets to NRG | Senior Vice President, Strategy and is not a parent, affiliate or subsidiary of SCE. |
| |
2
| EME is a wholly-owned subsidiary ofCorporate Development, Edison International and an affiliate of SCE. EME filed for bankruptcy on December 17, 2012. |
| |
3
| Akin Gump Strauss Hauer & Feld is a global law firm and is not a parent, affiliate or subsidiary of Edison International. |
| |
4
| Senior Managing Director, Macquarie Infrastructure and Real Assets is a global infrastructure management company and is not a parent, affiliate or subsidiary of Edison International. |
| 1 | | September 2015 to present
January 2012 to August 2015 |
| | | | |
| Jacqueline Trapp | | 5Senior Vice President, Human Resources Edison International and SCE
Vice President, Human Resources, SCE Director, Executive Talent and Rewards, Edison International | Los Angeles Department of Water | February 2018 to present June 2016 to February 2018 July 2012 to June 2016 |
| | | | |
| Kevin M. Payne | | President and Power is a municipal waterChief Executive Officer, SCE Chief Executive Officer, SCE Senior Vice President, Customer Service, SCE | | June 2019 to present June 2016 to June 2019 March 2014 to June 2016 |
| | | | |
| Steven D. Powell | | Executive Vice President, Operations, SCE Senior Vice President, Strategy, Planning and power utility company and is not a parent, affiliate or subsidiary of Edison International.Operational Performance, SCE Vice President, Strategy & Integrated Planning, SCE Director, Organizational Performance, SCE | | September 2019 to present August 2018 to September 2019 February 2016 to August 2018 January 2015 to February 2016 |
1 Macquarie Infrastructure and Real Assets is a global infrastructure management company and is not a parent, affiliate or subsidiary of Edison International.
EXECUTIVE OFFICERS OF SOUTHERN CALIFORNIA EDISON COMPANYExecutive Officers of Southern California Edison Company
|
| | | | |
| Executive Officer | | Age at February 26, 201920, 2020 | | Company Position |
| Kevin M. Payne | | 5859 | | President and Chief Executive Officer |
Ronald O. NicholsSteven D. Powell | | 6541 | | Executive Vice President, Operations |
| William M. Petmecky III | | 4950 | | Senior Vice President and Chief Financial Officer |
| Russell C. Swartz | | 6768 | | Senior Vice President and General Counsel |
| Jill C. Anderson | | 39 | | Senior Vice President, Strategic Planning & Power Supply |
| Philip R. Herrington | | 5657 | | Senior Vice President, Transmission and Distribution |
| Kevin E. Walker | | 56 | | Senior Vice President, Customer and Operational Services |
Caroline Choi | | 50 | | Senior Vice President, Corporate AffairsService & Nuclear |
As set forth in Article IV of SCE's Bylaws, the elected officers of SCE are chosen annually by, and serve at the pleasure of, SCE's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the above officers have been actively engaged in the business of SCE, its parent company Edison International, and/or one of SCE's subsidiaries or other affiliates for more than five years, except for Messrs. NicholsMs. Anderson, Mr. Herrington and Herrington,Mr. Walker, and have served in their present positions for the periods stated below. Additionally, those officers who have had other or additional principal positions in the past five years had the following business experience during that period:
|
| | | | |
| Executive Officer | | Company Position | | Effective Dates |
| Kevin M. Payne | | President and Chief Executive Officer, SCE Chief Executive Officer, SCE Senior Vice President, Customer Service, SCE Vice President, Engineering and Technical Services, SCE
| | June 2019 to present June 2016 to presentJune 2019 March 2014 to June 2016 September 2011 to March 2014
|
| | | | | |
Ronald O. Nichols
Steven D. Powell | | Executive Vice President, Operations, SCE Senior Vice President, Regulatory Affairs,Strategy, Planning and Operational Performance, SCE General Manager/Chief Executive Officer, Los Angeles Department of Water and Power1Vice President, Strategy & Integrated Planning, SCE
Director, Organizational Performance, SCE | | JuneSeptember 2019 to present
August 2018 to September 2019
February 2016 to present April 2014 to June 2016August 2018
January 20112015 to February 2014
2016
|
| | | | | |
| William M. Petmecky III | | Senior Vice President and Chief Financial Officer, SCE Vice President and Treasurer, SCE Vice President and Treasurer, EME2
| | September 2016 to present September 2014 to September 2016 September 2011 to March 2014
|
| | | | | |
| Russell C. Swartz | | Senior Vice President and General Counsel, SCE | | February 2011 to present |
| | | | | |
| Jill C. Anderson | | Senior Vice President, Strategic Planning and Power Supply, SCE Vice President, Customer Programs and Services, SCE Executive Vice President, Chief Commercial Officer, New York Power Authority1 Senior Vice President, Business Development, New York Power Authority1 | | September 2019 to present January 2018 to September 2019 January 2016 to January 2018
March 2013 to December 2015 |
| | | | |
| Philip R. Herrington | | Senior Vice President, Transmission and Distribution, SCE Vice President, Power Production, SCE President, US Competitive Generation/Market Business Lead, The AES Corporation President and Chief Executive Officer, Dayton Power and Light2 | | September 2017 to present August 2015 to September 2017 July 2013 to July 2015 March 2012 to March 2014 |
| | | | | |
| Kevin E. Walker | | Senior Vice President, Customer Service & Nuclear, SCE Senior Vice President, Customer and Operational Services, SCE Senior Vice President, Power Supply, SCE Strategy Advisor, Power and Utilities, Ernst & Young3 Chief Operating Officer, Iberdrola USA4 | | June 2019 to present October 2018 to presentJune 2019 December 2017 to September 2018 June 2017 to December 2017 November 2009 to May 2016 |
| | | | |
Caroline Choi | | Senior Vice President, Corporate Affairs, Edison International and SCE
Senior Vice President, Regulatory Affairs, SCE
Vice President Integrated Planning and Environmental Affairs, SCE
| | February 2019 to present
June 2016 to February 2019
January 2012 to June 2016
|
| |
1
| Los Angeles Department of Water and Power is a municipal water and power utility company and is not a parent, affiliate or subsidiary of SCE. |
| |
2
| EME is a wholly-owned subsidiary of Edison International and an affiliate of SCE. EME filed for bankruptcy on December 17, 2012. |
1 New York Power Authority is the largest state power organization in the United States, and is not a parent, affiliate or subsidiary of SCE.
2 AES Corporation is an investor-owned power generation and utility company, and is not a parent, affiliate or subsidiary of SCE.
3 Ernst & Young is an accounting and professional services firm, and is not a parent, affiliate or subsidiary of SCE.
4 Iberdrola USA, an energy company, is now known as Avengrid, Inc. Avengrid, Inc. is not a parent, affiliate or subsidiary of SCE.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information concerning executive officers of Edison International is set forth above under "Executive Officers of Edison International." Information concerning executive officers of SCE is set forth above under "Executive Officers of Southern California Edison Company." Other information responding to this section will appear in Edison International's and SCE's Joint Proxy Statement under the headings "Item 1: Election of Directors," and is incorporated herein by this reference.
The Edison International Employee Code of Conduct is applicable to all officers and employees of Edison International and its subsidiaries. The Code is available on Edison International's Internet website at www.edisoninvestor.com at "Corporate Governance." Any amendments or waivers of Code provisions for the Company's principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, will be posted on Edison International's Internet website at www.edisoninvestor.com.
EXECUTIVE COMPENSATION
Information responding to this section will appear in the Joint Proxy Statement under the headings "Compensation Discussion and Analysis," "Compensation Committee Interlocks and Insider Participation," "Executive Compensation" "Director Compensation" and "Compensation Committee Report," and is incorporated herein by this reference.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information responding to this section will appear in the Joint Proxy Statement under the heading "Our Stock Ownership," and is incorporated herein by this reference.
Equity Compensation Plans
All of Edison International's equity compensation plans that were in effect as of December 31, 20182019 have been approved by security holders. The following table sets forth, for each of Edison International's equity compensation plans, the number of shares of Edison International Common Stock subject to outstanding options, warrants and rights to acquire such stock, the weighted-averageweighted average exercise price of those outstanding options, warrants and rights, and the number of shares remaining available for future award grants as of December 31, 2018.2019.
|
| | | | | | | |
| Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | | Weighted-averageWeighted average exercise price of outstanding options, warrants and rights
(b)
| Number of securities remaining for future issuance under equity compensation plans (excluding securities reflected in column (a))(c) | |
| Equity compensation plans approved by security holders | 9,308,3189,873,3531
| | | 59.8162.27 | 28,295,44325,550,0602
| | |
| |
1 | This amount includes 8,833,6109,278,677 shares covered by outstanding stock options, 311,384332,775 shares covered by outstanding restricted stock unit awards, and 163,324137,825 shares covered by outstanding deferred stock unit awards, and 124,075 shares covered by outstanding performance share awards and payable in Edison International common stock (calculated at 100% of the target number of shares subject to each performance share award; the actual payout for each award will be zero to twice the target number of shares for the award, depending on performance), with the outstanding shares covered by outstanding restricted stock unit, and deferred stock unit, and performance share awards including the crediting of dividend equivalents through December 31, 2018.2019. The weighted-averageweighted average exercise price of awards outstanding under equity compensation plans approved by security holders reflected in column (b) above is calculated based on the outstanding stock options under these plans as the other forms of awards outstanding have no exercise price. Awards payable solely in cash are not reflected in this table. |
| |
2 | This amount is the aggregate number of shares available for new awards under the Edison International 2007 Performance Incentive Plan as of December 31, 2018.2019. The maximum number of shares of Edison International Common Stock that may be issued or transferred pursuant to awards under the Edison International 2007 Performance Incentive Plan is 71,031,524. Shares available under the Edison International 2007 Performance Incentive Plan may generally, subject to certain limits set forth in the plan, be used for any type of award authorized under that plan, including stock options, restricted stock, performance shares, restricted or deferred units, and stock bonuses. |
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information responding to this section will appear in the Joint Proxy Statement under the headings "Certain Relationships and Related Transactions," "Our Corporate Governance—Applicability of Stock Exchange Rules to SCE" and "Our Corporate Governance—Director Independence", and is incorporated herein by this reference.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information responding to this section will appear in the Joint Proxy Statement under the heading "Independent Auditor Fees," and is incorporated herein by this reference.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Edison International
Edison International Common Stock is traded on the New York Stock Exchange under the symbol "EIX."
There are restrictions on the ability of SCE to transfer funds to Edison International that materially limit the ability of Edison International to pay cash dividends. Such restrictions are discussed in the MD&A under the heading "Liquidity and Capital Resources—SCE—SCE Dividends," and in "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends." The number of common stockholders of record of Edison International was 30,78429,483 on February 26, 2019.20, 2020. In addition, Edison International cannot pay dividends if it does not meet California law requirements on retained earnings and solvency.
Southern California Edison Company
As a result of the formation of a holding company described under the heading "Business" above, all of the issued and outstanding common stock of SCE is owned by Edison International and there is no market for such stock. There are restrictions on SCE's ability to pay dividends to Edison International and to its preferred shareholders. Such restrictions are discussed in the MD&A under the heading "Liquidity and Capital Resources—SCE—SCE Dividends," and in "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends."
Purchases of Equity Securities by Edison International and Affiliated Purchasers
The following table contains information about all purchases of Edison International Common Stock made by or on behalf of Edison International in the fourth quarter of 2018. |
| | | | | | | | | | | | |
| Period | (a) Total Number of Shares (or Units) Purchased1 | | (b) Average Price Paid per Share (or Unit)1 | | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs |
| October 1, 2018 to October 31, 2018 | 163,205 |
| | | $ | 69.39 |
| | | — | | — |
| November 1, 2018 to November 30, 2018 | 316,738 |
| | | 60.03 |
| | | — | | — |
| December 1, 2018 to December 31, 2018 | 145,257 |
| | | 57.66 |
| | | — | | — |
| Total | 625,200 |
| | | $ | 61.92 |
| | | — | | — |
| |
1
| The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's: (i) 401(k) Savings Plan; (ii) Dividend Reinvestment and Direct Stock Purchase Plan; and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions. |
Comparison of Five-Year Cumulative Total Return
| | | | | | | | | | | | | |
| | | 2013 |
| | 2014 |
| | 2015 |
| | 2016 |
| | 2017 |
| | 2018 |
| | 2014 |
| | 2015 |
| | 2016 |
| | 2017 |
| | 2018 |
| | 2019 |
|
| Edison International | | $ | 100 |
| | $ | 145 |
| | $ | 135 |
| | $ | 169 |
| | $ | 153 |
| | $ | 142 |
| | $ | 100 |
| | $ | 93 |
| | $ | 116 |
| | $ | 105 |
| | $ | 98 |
| | $ | 135 |
|
| S & P 500 Index | | $ | 100 |
| | $ | 114 |
| | $ | 115 |
| | $ | 129 |
| | $ | 157 |
| | $ | 150 |
| | $ | 100 |
| | $ | 101 |
| | $ | 113 |
| | $ | 138 |
| | $ | 132 |
| | $ | 174 |
|
| Philadelphia Utility Index | | $ | 100 |
| | $ | 129 |
| | $ | 121 |
| | $ | 142 |
| | $ | 160 |
| | $ | 166 |
| | $ | 100 |
| | $ | 94 |
| | $ | 110 |
| | $ | 124 |
| | $ | 129 |
| | $ | 163 |
|
Note: Assumes $100 invested on December 31, 20132014 in stock or index including reinvestment of dividends. Performance of the Philadelphia Utility Index is regularly reviewed by management and the Board of Directors in understanding Edison International's relative performance and is used in conjunction with elements of Edison International's compensation program.
FORM 10-K SUMMARY
None.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) (1) Financial Statements
See Consolidated Financial Statements listed in the Table of Contents of this report.
(a) (2) Report of Independent Registered Public Accounting Firm and Schedules Supplementing Financial Statements
Edison International
The following documents may be found in this report at the indicated page numbers under the headings "Financial Statements and Supplementary Data"Data—Reports of Independent Registered Accounting Firm" and "Exhibits and Financial Statement Schedules"Schedules—Schedules Supplementing Financial Statements" in the Table of Contents of this report.
|
|
| Report of Independent Registered Public Accounting Firm - Edison International |
|
|
Schedules III through V, inclusive, for Edison International are omitted as not required or not applicable.
Southern California Edison Company
The following documents may be found in this report at the indicated page numbers under the headings "Financial Statements and Supplementary Data"Data—Reports of Independent Registered Accounting Firm" and "Exhibits and Financial Statement Schedules"Schedules—Schedules Supplementing Financial Statements" in the Table of Contents of this report.
|
|
| Report of Independent Registered Public Accounting Firm - SCE |
|
Schedules I and III through V, inclusive, for SCE are omitted as not required or not applicable.
(a) (3) Exhibits
|
| | |
Exhibit Number | | Description |
| | | |
| Edison International |
| | | |
| 3.1 | | |
| | | |
| 3.2 | | |
| | | |
| Southern California Edison Company |
| | | |
| 3.3 | | |
| | | |
| 3.4 | | |
| | | |
| Edison International |
| 4.1 | | |
| | | |
4.14.2 | | |
| | | |
| Southern California Edison Company |
| 4.3 | | |
| | | |
4.24.4 | | |
| | | |
4.34.5 | | |
| | | |
| Edison International and Southern California Edison Company |
| | | |
| 10.1** | | |
| | | |
| 10.2** | | |
| | | |
10.310.3** | | |
| | | |
| 10.4** | | |
| | | |
| 10.4.1** | | |
| | | |
| 10.4.2** | | |
| | | |
| 10.5** | | |
| | | |
| 10.5.1** | | |
| | | |
| 10.6** | | |
| | | |
|
| | |
Exhibit Number | | Description |
| 10.7** | | |
| | | |
|
| | |
Exhibit
Number
| | Description |
| 10.8** | | |
| | | |
| 10.8.1** | | |
| | |
10.8.2** | | |
| | | |
10.8.3*10.8.2** | | |
| | | |
10.8.4*10.8.3** | | |
| | | |
10.8.5*10.8.4** | | |
| | | |
10.8.6*10.8.5** | | |
| | | |
10.8.7*10.8.6** | | |
| | | |
10.8.8*10.8.7** | | |
| | | |
10.8.9*10.8.8** | |
|
| | | |
10.8.10*10.8.9** | | |
| | | |
10.8.11*10.8.10** | | |
| | |
| 10.8.11** | | |
| | | |
| 10.9** | | |
| | | |
| 10.10** | | |
| | | |
| 10.11** | | |
| | | |
| 10.12** | | |
| | | |
| 10.13 | | |
| | | |
| 10.14 | | |
| | | |
| 10.14.1 | | |
| | | |
| 10.14.2 | | |
| | | |
|
| | |
Exhibit Number | | Description |
| 10.14.3 | | |
| | | |
|
| | |
Exhibit
Number
| | Description |
| 10.14.4 | | |
| | | |
| 10.15** | | |
| | | |
10.16**10.16 | | |
| | |
10.17** | | |
| | |
10.17.1** | | |
| | |
10.18 | | |
| | | |
10.1910.17 | | |
| | |
10.20 | | Term Loan Credit Agreement, dated as of January 26, 2018, among Edison International, the several banks and other financial institutions from time to time parties thereto, and Wells Fargo Bank, N.A., as administrative agent for the lenders (File 1-2313, filed as Exhibit 10.1 to Southern California Edison Company's Form 8-K dated January 26, 2018 and filed January 26, 2018)* |
| | |
10.21 | | |
| | |
10.22 | | |
| | | |
| 21 | | |
| | | |
| 23.1 | | |
| | | |
| 23.2 | | |
| | | |
| 24.1 | | |
| | | |
| 24.2 | | |
| | | |
| 31.1 | | |
| | | |
| 31.2 | | |
| | | |
| 32.1 | | |
| | | |
| 32.2 | | |
| | | |
| 101.1 | | Financial statements from the annual report on Form 10-K of Edison International for the year ended December 31, 2018,2019, filed on February 28, 2019,27, 2020, formatted in Inline XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; (v) Consolidated Statements of Changes in Equity and (vi) the Notes to Consolidated Financial Statements |
| | | |
|
| | |
Exhibit
Number
| | Description |
| 101.2 | | Financial statements from the annual report on Form 10-K of Southern California Edison Company for the year ended December 31, 2018,2019, filed on February 28, 2019,27, 2020, formatted in Inline XBRL: (i) the Consolidated Statements of Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets; (iv) the Consolidated Statements of Cash Flows; (v) Consolidated Statements of Changes in Equity and (vi) the Notes to Consolidated Financial Statements |
| | |
| 104 | | The cover page of this report formatted in Inline XBRL (included as Exhibit 101) |
| |
| * | Incorporated by reference pursuant to Rule 12b-32. |
| |
| ** | Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)(3). |
Edison International and SCE will furnish a copy of any exhibit listed in the accompanying Exhibit Index upon written request and upon payment to Edison International or SCE of their reasonable expenses of furnishing such exhibit, which shall be limited to photocopying charges and, if mailed to the requesting party, the cost of first-class postage.
SCHEDULES SUPPLEMENTING FINANCIAL STATEMENTS
EDISON INTERNATIONAL
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
|
| | | | | | | |
| | December 31, |
| (in millions) | 2019 | | 2018 |
| Assets: | | | |
| Cash and cash equivalents | $ | 15 |
| | $ | 97 |
|
| Other current assets | 260 |
| | 52 |
|
| Total current assets | 275 |
| | 149 |
|
| Investments in subsidiaries | 16,530 |
| | 12,521 |
|
| Deferred income taxes | 608 |
| | 516 |
|
| Other long-term assets | 76 |
| | 78 |
|
| Total assets | $ | 17,489 |
| | $ | 13,264 |
|
| Liabilities and equity: | | | |
| Current portion of long-term debt | 400 |
| | — |
|
| Other current liabilities | 481 |
| | 498 |
|
| Total current liabilities | 881 |
| | 498 |
|
| Long-term debt | 2,733 |
| | 1,740 |
|
| Other long-term liabilities | 572 |
| | 567 |
|
| Total equity | 13,303 |
| | 10,459 |
|
| Total liabilities and equity | $ | 17,489 |
| | $ | 13,264 |
|
|
| | | | | | | |
| | December 31, |
| (in millions) | 2018 | | 2017 |
| Assets: | | | |
| Cash and cash equivalents | $ | 97 |
| | $ | 524 |
|
| Other current assets | 52 |
| | 340 |
|
| Total current assets | 149 |
| | 864 |
|
| Investments in subsidiaries | 12,521 |
| | 13,659 |
|
| Deferred income taxes | 516 |
| | 500 |
|
| Other long-term assets | 78 |
| | 91 |
|
| Total assets | $ | 13,264 |
| | $ | 15,114 |
|
| Liabilities and equity: | | | |
| Short-term debt | $ | — |
| | $ | 1,139 |
|
| Other current liabilities | 498 |
| | 467 |
|
| Total current liabilities | 498 |
| | 1,606 |
|
| Long-term debt | 1,740 |
| | 1,193 |
|
| Other long-term liabilities | 567 |
| | 644 |
|
| Total equity | 10,459 |
| | 11,671 |
|
| Total liabilities and equity | $ | 13,264 |
| | $ | 15,114 |
|
EDISON INTERNATIONAL
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2019, 2018 2017 and 20162017
| | | (in millions) | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Interest income from affiliates | $ | — |
| | $ | — |
| | $ | 6 |
| $ | 5 |
| | $ | — |
| | $ | — |
|
| Operating, interest and other expenses | 98 |
| | 92 |
| | 86 |
| 150 |
| | 98 |
| | 92 |
|
| Loss before equity in (loss) earnings of subsidiaries | (98 | ) | | (92 | ) | | (80 | ) | |
| Equity in (loss) earnings of subsidiaries | (376 | ) | | 739 |
| | 1,337 |
| |
| (Loss) income before income taxes | (474 | ) | | 647 |
| | 1,257 |
| |
| Loss before equity in earnings (loss) of subsidiaries | | (145 | ) | | (98 | ) | | (92 | ) |
| Equity in earnings (loss) of subsidiaries | | 1,385 |
| | (376 | ) | | 739 |
|
| Income (loss) before income taxes | | 1,240 |
| | (474 | ) | | 647 |
|
| Income tax (benefit) expense | (17 | ) | | 82 |
| | (42 | ) | (44 | ) | | (17 | ) | | 82 |
|
| (Loss) income from continuing operations | (457 | ) | | 565 |
| | 1,299 |
| |
| Income (loss) from continuing operations | | 1,284 |
| | (457 | ) | | 565 |
|
| Income from discontinued operations, net of tax | 34 |
| | — |
| | 12 |
| — |
| | 34 |
| | — |
|
| Net (loss) income | $ | (423 | ) | | $ | 565 |
| | $ | 1,311 |
| |
| Net income (loss) | | $ | 1,284 |
| | $ | (423 | ) | | $ | 565 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2019, 2018 2017 and 20162017
|
| | | | | | | | | | | |
| (in millions) | 2019 | | 2018 | | 2017 |
| Net income (loss) | $ | 1,284 |
| | $ | (423 | ) | | $ | 565 |
|
| Other comprehensive (loss) income, net of tax | (9 | ) | | (7 | ) | | 10 |
|
| Comprehensive income (loss) | $ | 1,275 |
| | $ | (430 | ) | | $ | 575 |
|
|
| | | | | | | | | | | |
| (in millions) | 2018 | | 2017 | | 2016 |
| Net (loss) income | $ | (423 | ) | | $ | 565 |
| | $ | 1,311 |
|
| Other comprehensive (loss) income, net of tax | (7 | ) | | 10 |
| | 3 |
|
| Comprehensive (loss) income | $ | (430 | ) | | $ | 575 |
| | $ | 1,314 |
|
EDISON INTERNATIONAL
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2019, 2018 2017 and 20162017
| | | (in millions) | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| Net cash provided by operating activities | $ | 785 |
| | $ | 462 |
| | $ | 493 |
| $ | 181 |
| | $ | 785 |
| | $ | 462 |
|
| Cash flows from financing activities: | | | | | | | | | | |
| Long-term debt issued | 549 |
| | 798 |
| | 400 |
| 1,399 |
| | 549 |
| | 798 |
|
| Long-term debt issuance costs | (4 | ) | | (5 | ) | | (3 | ) | (9 | ) | | (4 | ) | | (5 | ) |
| Long-term debt matured | — |
| | (400 | ) | | — |
| |
| Long-term debt repaid | | — |
| | — |
| | (400 | ) |
| Term loan issued | | 1,000 |
| | — |
| | — |
|
| Term loan repaid | | (1,000 | ) | | — |
| | — |
|
| Common stock issued | | 2,391 |
| | — |
| | — |
|
| Payable due to affiliates | 13 |
| | 8 |
| | 34 |
| 5 |
| | 13 |
| | 8 |
|
| Short-term debt financing, net | (1,141 | ) | | 600 |
| | (108 | ) | (1 | ) | | (1,141 | ) | | 600 |
|
| Payments for stock-based compensation | (24 | ) | | (260 | ) | | (95 | ) | (27 | ) | | (24 | ) | | (260 | ) |
| Receipts for stock-based compensation | 14 |
| | 144 |
| | 51 |
| 39 |
| | 14 |
| | 144 |
|
| Dividends paid | (788 | ) | | (707 | ) | | (626 | ) | (810 | ) | | (788 | ) | | (707 | ) |
| Net cash (used in) provided by financing activities | (1,381 | ) | | 178 |
| | (347 | ) | |
| Net cash provided by (used in) financing activities | | 2,987 |
| | (1,381 | ) | | 178 |
|
| Capital contributions to affiliate | (10 | ) | | (122 | ) | | (147 | ) | (3,258 | ) | | (10 | ) | | (122 | ) |
| Dividends from affiliate | 179 |
| | — |
| | — |
| 8 |
| | 179 |
| | — |
|
| Net cash provided by (used in) investing activities: | 169 |
| | (122 | ) | | (147 | ) | |
| Net cash (used in) provided by investing activities: | | (3,250 | ) | | 169 |
| | (122 | ) |
| Net (decrease) increase in cash and cash equivalents | (427 | ) | | 518 |
| | (1 | ) | (82 | ) | | (427 | ) | | 518 |
|
| Cash and cash equivalents, beginning of year | 524 |
| | 6 |
| | 7 |
| 97 |
| | 524 |
| | 6 |
|
| Cash and cash equivalents, end of year | $ | 97 |
| | $ | 524 |
| | $ | 6 |
| $ | 15 |
| | $ | 97 |
| | $ | 524 |
|
Note 1. Basis of Presentation
The accompanying condensed financial statements of Edison International Parent should be read in conjunction with the consolidated financial statements and notes thereto of Edison International and subsidiaries ("Registrant") included in this Form 10-K. Edison International's ParentInternational Parent's significant accounting policies are consistent with those of the Registrant, SCE and other wholly owned and controlled subsidiaries.
Dividends Received
Edison International Parent received cash dividends from SCE of $788$400 million, $788 million and $573 million in 2019, 2018 and $701 million in 2018, 2017, and 2016, respectively.
Dividend Restrictions
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
Prior to January 1, 2020, under SCE's interpretation of CPUC regulations and capital structure decisions, the common equity component of SCE's capital structure mustwas required to remain at or above 48% on a weighted average basis over the 37-month period that SCE's capital structure iswas in effect for ratemaking purposes. As allowed under the Revised San Onofre Settlement Agreement, whichpurposes and SCE 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%. Effective January 1, 2020, the common equity component of SCE's authorized capital structure was increased from
48% to 52%. Under AB 1054, the impact of SCE's contributions to the Wildfire Insurance Fund are excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure.
On February 28, 2019, SCE is submittingsubmitted 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 seekingrequested a limited waiver to exclude wildfire-related charges and wildfire-related debt issuances from its equity ratio calculations until a determination regarding cost
recovery is made. The CPUC has ruled that while the application is pending resolution, SCE must notify the CPUC if an adverse financial event reduces SCE's spot equity ratio by more than one percent from the level most recently filed with the CPUC in the proceeding. The last spot equity ratio SCE filed with the CPUC in the proceeding was 45.2% as of December 31, 2018. Under the CPUC's rules, SCE will not be deemed to be in violation of the equity ratio requirement, and therefore may continue to issue debt and dividends, while the waiver application is pending resolution. For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides." At December 31, 2019, without excluding the $2.0 billion after-tax wildfire-related charges incurred in 2018 and 2019, SCE's 37-month average common equity component of total capitalization was 48.5% and the maximum additional dividend that SCE could pay to Edison International under this limitation was $179 million, resulting in a restriction on net assets of approximately $17.6 billion. If the wildfire-related charges were excluded at December 31, 2019, SCE's 37-month average common equity component of total capitalization would have been 49.6%. See "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividends."
Note 2. Debt and Credit AgreementsEquity Financing
Long-Term Debt
In January 2018, Edison International Parent borrowed $500 million under a Term Loan Agreement due in JanuaryJune 2019, with a variable interest rate based on the London Interbank Offered Rate plus 60 basis points. The proceeds were used to repay Edison International Parent's commercial paper borrowings. In March 2018, Edison International Parent issued $550$600 million of 4.125%5.75% senior notes due in 2028. TheJune 15, 2027. Of the proceeds fromof the March 2018 issuance weresenior note offering, $450 million was contributed to SCE with the remainder to be used for general corporate and working capital purposes.
In November 2019, Edison International Parent issued $300 million of 3.125% senior notes due 2022 and $500 million of 3.550% senior notes due 2024. A portion of the proceeds of the November 2019 offering was used to repay a borrowing under a term loan agreement due in April 2020, a portion is used to repay at maturity some or all of Edison International Parent's outstanding 2.125% senior notes due 2020, and the $500 million Term Loan discussed above andremainder for general corporate purposes.
In addition, at December 31, 20182019 and 2017,2018, Edison International Parent had $400 million of 2.125% senior notes due in 2020, $400 million of 2.40% senior notes due in 2022, and $400 million of 2.95% senior notes due in 2023.and $550 million of 4.125% senior notes due in 2028.
Credit Agreements and Short-Term Debt
The following table summarizes the status of the credit facility at December 31, 2018:2019:
|
| | | |
| (in millions) | |
| Commitment | $ | 1,500 |
|
| Outstanding borrowings | — |
|
| Amount available | $ | 1,500 |
|
|
| | | |
| (in millions) | |
| Commitment | $ | 1,500 |
|
| Outstanding borrowings | — |
|
| Amount available | $ | 1,500 |
|
In May 2018,April 2019, Edison International Parent borrowed $1.0 billion under a term loan agreement due in April 2020, with a
variable interest rate based on the London Interbank Offered Rate plus 90 basis points. Of the proceeds of the term loan,
$750 million was contributed to SCE with the remainder used for general corporate and working capital purposes. The term loan was fully repaid in December 2019.
In June 2019, Edison International Parent amended the maturity date of its multi-year revolving credit facility to increase the facility from $1.25 billion to $1.5of
$1.5 billion. The facility now matures in May 20232024, with an option to extend for an additional year, which may be exercised upon agreement between Edison International Parent and has two 1-year extension options. its lenders.
At December 31, 2019 and December 31, 2018, Edison International Parent had no0 outstanding commercial paper. At December 31, 2017, the outstanding commercial paper, net of discount, was $639 million at a weighted-average interest rate of 1.70%.
The debt covenant in Edison International's credit facility requires a consolidated debt to total capitalization ratio of less than or equal to 0.70 to 1. At December 31, 2018,2019, Edison International's consolidated debt to total capitalization ratio was 0.55 to 1.
Equity
In May 2019, Edison International filed a prospectus supplement and executed several distribution agreements with certain sales agents to establish an ATM program under which it may sell shares of its common stock having an aggregate sales price of up to $1.5 billion. In the fourth quarter of 2019, Edison International issued 2.8 million shares through the ATM program and received proceeds of $198 million, net of fees and offering expenses of $2 million. The proceeds from the sales were used for equity contributions to SCE and for general corporate and working capital purposes. As of December 31, 2019, shares of common stock having an aggregate offering price of $1.3 billion remained available to be sold under the ATM program. Edison International has no obligation to sell the remaining available shares.
In July 2019, Edison International issued 32.2 million shares of common stock and received proceeds of approximately $2.2 billion, net of fees and offering expenses of $52 million in an underwritten offering. Of the proceeds, $1.9 billion was contributed to SCE. The remaining was used for general corporate purposes.
Beginning in July 2019, Edison International settled the ongoing common stock requirements of various internal programs through issuance of new common stock. In the year ended December 31, 2019, 0.6 million shares of new common stock were purchased by employees through the 401(k) defined contribution savings plan for net cash receipts of $41 million, 0.4 million shares of common stock were issued as stock compensation awards for net cash receipts of $22 million and 0.1 million shares of new common stock were issued in lieu of distributing $8 million to shareholders opting to receive dividend payments in the form of additional common stock.
Note 3. Related-Party Transactions
Edison International's Parent expense from services provided by SCE was $2 million in 2018, $32019, $2 million in 20172018 and $3 million in 2016.2017. Edison International's Parent interest expense from loans due to affiliates was $5 million in 2019, 2018 $5 million in 2017 and $3 million in 2016.2017. Edison International Parent had current related-party receivables of $41$272 million and $256$41 million and current related-party payables of $249$198 million and $235$249 million at December 31, 20182019 and 2017,2018, respectively. Edison International Parent had long-term related-party receivables of $73 million and $81 million at both December 31, 20182019 and 2017, respectively,2018, and long-term related-party payables of $213 million and $200 million at both December 31, 20182019 and 2017, respectively.2018.
Note 4. Contingencies
For a discussion of material contingencies see "Notes to Consolidated Financial Statements—Note 8. Income Taxes" and "—Note 12. Commitments and Contingencies."
EDISON INTERNATIONAL
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
| | | | | | Additions | | | | | | | Additions | | | | |
| (in millions) | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| For the Year ended December 31, 2019 | | | | | | | | | | |
| Allowance for uncollectible accounts | | | | | | | | | | |
| Customers | | $ | 32.0 |
| | $ | 22.2 |
| | $ | — |
| | $ | 18.4 |
| | $ | 35.8 |
|
| All others | | 19.5 |
| | 10.0 |
| | — |
| | 15.6 |
| | 13.9 |
|
| Total allowance for uncollectible amounts | | $ | 51.5 |
| | $ | 32.2 |
| | $ | — |
| | $ | 34.0 |
| a | $ | 49.7 |
|
| Tax valuation allowance | | $ | 36.0 |
| | $ | — |
| | $ | — |
| | $ | 1.0 |
| | $ | 35.0 |
|
| | | | | | | | | | |
| For the Year ended December 31, 2018 | | | | | | | | | | | | | | | | | | |
| Allowance for uncollectible accounts | | | | | | | | | | | | | | | | | | |
| Customers | $ | 36.6 |
| | $ | 19.0 |
| | $ | — |
| | $ | 23.6 |
| | $ | 32.0 |
| $ | 36.6 |
| | $ | 19.0 |
| | $ | — |
| | $ | 23.6 |
| | $ | 32.0 |
|
| All others | 17.3 |
| | 16.2 |
| | — |
| | 14.0 |
| | 19.5 |
| 17.3 |
| | 16.2 |
| | — |
| | 14.0 |
| | 19.5 |
|
| Total allowance for uncollectible amounts | $ | 53.9 |
| | $ | 35.2 |
| | $ | — |
| | $ | 37.6 |
| a | $ | 51.5 |
| $ | 53.9 |
| | $ | 35.2 |
| | $ | — |
| | $ | 37.6 |
| a | $ | 51.5 |
|
| Tax valuation allowance | $ | 28.0 |
| | $ | — |
| | $ | 8.0 |
| c | $ | — |
| | $ | 36.0 |
| $ | 28.0 |
| | $ | — |
| | $ | 8.0 |
| b | $ | — |
| | $ | 36.0 |
|
| | | | | | | | | | | | | | | | | | |
| For the Year ended December 31, 2017 | | | | | | | | | | | | | | | | | | |
| Allowance for uncollectible accounts | | | | | | | | | | | | | | | | | | |
| Customers | $ | 41.2 |
| | $ | 12.9 |
| | $ | — |
| | $ | 17.5 |
| | $ | 36.6 |
| $ | 41.2 |
| | $ | 12.9 |
| | $ | — |
| | $ | 17.5 |
| | $ | 36.6 |
|
| All others | 20.6 |
| | 13.5 |
| | — |
| | 16.8 |
| | 17.3 |
| 20.6 |
| | 13.5 |
| | — |
| | 16.8 |
| | 17.3 |
|
| Total allowance for uncollectible amounts | $ | 61.8 |
| | $ | 26.4 |
| | $ | — |
| | $ | 34.3 |
| a | $ | 53.9 |
| $ | 61.8 |
| | $ | 26.4 |
| | $ | — |
| | $ | 34.3 |
| a | $ | 53.9 |
|
| Tax valuation allowance | $ | 24.0 |
| | $ | — |
| | $ | 4.0 |
| c | $ | — |
| | $ | 28.0 |
| $ | 24.0 |
| | $ | — |
| | $ | 4.0 |
| b | $ | — |
| | $ | 28.0 |
|
| | | | | | | | | | |
| For the Year ended December 31, 2016 | | | | | | | | | | |
| Allowance for uncollectible accounts | | | | | | | | | | |
| Customers | $ | 46.2 |
| | $ | 17.7 |
| | $ | — |
| | $ | 22.7 |
| | $ | 41.2 |
| |
| All others | 15.5 |
| | 15.9 |
| | — |
| | 10.8 |
| | 20.6 |
| |
| Total allowance for uncollectible amounts | $ | 61.7 |
| | $ | 33.6 |
| | $ | — |
| | $ | 33.5 |
| a | $ | 61.8 |
| |
| Tax valuation allowance | $ | 32.0 |
| | $ | — |
| | $ | — |
| | $ | 8.0 |
| b | $ | 24.0 |
| |
| |
a | Accounts written off, net. |
| |
b | In 2016, Edison International determined that $8 million of the assets subject to a valuation allowance had no expectation of recovery and were written off. |
| |
c
| During 2018, Edison International recorded an additional valuation allowance of $4 million for non-California state net operating loss carryforwards and $4 million for California capital losslosses generated from the April 2018 sale of SoCore Energy, which are estimated to expire before being utilized. The additional valuation allowance in 2017 was a result of Tax Reform. |
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
| | | | | | Additions | | | | | | | Additions | | | | |
| (in millions) | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| For the Year ended December 31, 2019 | | | | | | | | | | |
| Allowance for uncollectible accounts | | | | | | | | | | |
| Customers | | $ | 31.6 |
| | $ | 22.0 |
| | $ | — |
| | $ | 18.1 |
| | $ | 35.5 |
|
| All others | | 19.5 |
| | 10.0 |
| | — |
| | 15.6 |
| | 13.9 |
|
| Total allowance for uncollectible accounts | | $ | 51.1 |
| | $ | 32.0 |
| | $ | — |
| | $ | 33.7 |
| a | $ | 49.4 |
|
| | | | | | | | | | | |
| For the Year ended December 31, 2018 | | | | | | | | | | | | | | | | | | |
| For the Year ended | | | | | | | | | | |
| Allowance for uncollectible accounts | | | | | | | | | | |
| Customers | $ | 36.0 |
| | $ | 18.9 |
| | $ | — |
| | $ | 23.3 |
| | $ | 31.6 |
| $ | 36.0 |
| | $ | 18.9 |
| | $ | — |
| | $ | 23.3 |
| | $ | 31.6 |
|
| All others | 17.3 |
| | 16.2 |
| | — |
| | 14.0 |
| | 19.5 |
| 17.3 |
| | 16.2 |
| | — |
| | 14.0 |
| | 19.5 |
|
| Total allowance for uncollectible accounts | $ | 53.3 |
| | $ | 35.1 |
| | $ | — |
| | $ | 37.3 |
| a | $ | 51.1 |
| $ | 53.3 |
| | $ | 35.1 |
| | $ | — |
| | $ | 37.3 |
| a | $ | 51.1 |
|
| | | | | | | | | | | | | | | | | | | |
| For the Year ended December 31, 2017 | | | | | | | | | | | | | | | | | | |
| Allowance for uncollectible accounts | | | | | | | | | | | | | | | | | | |
| Customers | $ | 40.5 |
| | $ | 12.9 |
| | $ | — |
| | $ | 17.4 |
| | $ | 36.0 |
| $ | 40.5 |
| | $ | 12.9 |
| | $ | — |
| | $ | 17.4 |
| | $ | 36.0 |
|
| All others | 20.6 |
| | 13.5 |
| | — |
| | 16.8 |
| | 17.3 |
| 20.6 |
| | 13.5 |
| | — |
| | 16.8 |
| | 17.3 |
|
| Total allowance for uncollectible accounts | $ | 61.1 |
| | $ | 26.4 |
| | $ | — |
| | $ | 34.2 |
| a | $ | 53.3 |
| $ | 61.1 |
| | $ | 26.4 |
| | $ | — |
| | $ | 34.2 |
| a | $ | 53.3 |
|
| | | | | | | | | | | |
| For the Year ended December 31, 2016 | | | | | | | | | | |
| Allowance for uncollectible accounts | | | | | | | | | | |
| Customers | $ | 46.2 |
| | $ | 17.0 |
| | $ | — |
| | $ | 22.7 |
| | $ | 40.5 |
| |
| All others | 15.5 |
| | 15.9 |
| | — |
| | 10.8 |
| | 20.6 |
| |
| Total allowance for uncollectible accounts | $ | 61.7 |
| | $ | 32.9 |
| | $ | — |
| | $ | 33.5 |
| a | $ | 61.1 |
| |
| |
a | Accounts written off, net. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.
|
| | | | |
| | EDISON INTERNATIONAL | | | SOUTHERN CALIFORNIA EDISON COMPANY |
| | | | | |
| By: | /s/ Aaron D. Moss | | By: | /s/ Aaron D. Moss |
| | | | | |
| | Aaron D. Moss Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer) | | | Aaron D. Moss Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer) |
| | | | | |
| Date: | February 28, 201927, 2020 | | Date: | February 28, 201927, 2020 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the date indicated.
|
| | |
| Signature | | Title |
| | | |
| A. Principal Executive Officers | | |
| | | |
| Pedro J. Pizarro* | | President, Chief Executive Officer and Director (Edison International) |
| | | |
| Kevin Payne* | | President and Chief Executive Officer and SCE Director (Southern California Edison Company) |
| | | |
| B. Principal Financial Officers | | |
| | | |
| Maria Rigatti* | | Executive Vice President and Chief Financial Officer (Edison International) |
| | | |
| William M. Petmecky III* | | Senior Vice President and Chief Financial Officer (Southern California Edison Company) |
| | | |
| C. Principal Accounting Officers | | |
| | | |
| /s/ Aaron D. Moss | | Vice President and Controller (Edison International) |
| Aaron D. Moss |
| | | |
/s/ Aaron D. Moss
| | Vice President and Controller (Southern California Edison Company) |
| Aaron D. Moss |
| | | |
| D. Directors (Edison International and Southern California Edison Company, unless otherwise noted) | | |
| | |
| Jeanne Beliveau-Dunn* | | Director |
| | | |
| Michael C. Camuñez* | | Director |
| | | |
| Vanessa C.L. Chang* | | Director |
| | | |
Keith Trent* | | Director |
| | |
| James T. Morris* | | Director |
| | | |
Pedro J. Pizarro*Timothy T. O'Toole* | | Director |
| | | |
| Kevin Payne (SCE only)* | | Director |
| | | |
Timothy T. O'Toole*Pedro J. Pizarro* | | Director |
| | |
| Carey A. Smith* | | Director |
| | | |
| Linda G. Stuntz* | | Director |
| | | |
| William P. Sullivan* | | Chair of the Edison International Board and Director |
| | | |
Ellen O. Tauscher* | | Director |
| | |
| Peter J. Taylor* | | Director |
| | | |
Brett White*Keith Trent* | | Director |
| | |
|
| | | |
| | | | |
| | | | |
| *By: | /s/ Aaron D. Moss | *By: | /s/ Aaron D. Moss |
| | | | |
| | Aaron D. Moss Vice President and Controller (Attorney-in-fact for EIX Directors and Officers) | | Aaron D. Moss Vice President and Controller (Attorney-in-fact for SCE Directors and Officers) |
| | | | |
| Date: | February 28, 201927, 2020 | Date: | February 28, 201927, 2020 |
