Document
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, 2016 |
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 (P.O. Box 976) Rosemead, California 91770 (Address of principal executive offices) | | 2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California 91770 (Address of principal executive offices) |
(626) 302-2222 (Registrant's telephone number, including area code) | | (626) 302-1212 (Registrant's telephone number, including area code) |
Securities registered pursuant to Section 12(b) of the Act: |
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Title of each class | | Name of each exchange on which registered |
Edison International: Common Stock, no par value | | NYSE LLC |
Southern California Edison Company: Cumulative Preferred Stock | | NYSE MKT LLC |
4.08% Series, 4.24% Series, 4.32% Series, 4.78% Series | | |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Edison International Yes þ No o Southern California Edison Company Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Edison International Yes o No þ Southern California Edison Company Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Edison International Yes þ No o Southern California Edison Company Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Edison International Yes þ No o Southern California Edison Company Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Edison International þ Southern California Edison Company þ |
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "accelerated filer," "large accelerated filer," and "smaller reporting company" in Rule 12b-12 of the Exchange Act. (Check One): |
Edison International | Large Accelerated Filer þ | Accelerated Filer o | Non-accelerated Filer o | Smaller Reporting Company o |
Southern California Edison Company | Large Accelerated Filer o | Accelerated Filer o | Non-accelerated Filer þ | Smaller Reporting Company o |
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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 30, 2016, the last business day of the most recently completed second fiscal quarter:
Edison International Approximately $25.3 billion Southern California Edison Company Wholly owned by Edison International |
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Common Stock outstanding as of February 17, 2017: | | |
Edison International | | 325,811,206 shares |
Southern California Edison Company | | 434,888,104 shares (wholly owned by Edison International) |
DOCUMENTS INCORPORATED BY REFERENCE
Designated portions of the Proxy Statement relating to registrants' joint 2017 Annual Meeting of Shareholders have been incorporated by reference into the parts of this report where indicated.
TABLE OF CONTENTS |
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| | | | | SEC Form 10-K Reference Number |
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| | Part II, Item 7 |
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| | Part I, Item 1A |
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| | Part II, Item 7A |
| | 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 3 |
| | Part I, Item 3 |
| | Part I, Item 3 |
| | 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 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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AFUDC | | allowance for funds used during construction |
ALJ | | administrative law judge |
ARO(s) | | asset retirement obligation(s) |
Bcf | | billion cubic feet |
Bonus depreciation | | Current 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 |
CPUC | | California Public Utilities Commission |
DOE | | U.S. Department of Energy |
DERs | | distributed energy resources |
DRP | | Distributed Resources Plan |
Edison Energy | | Edison Energy, LLC, a wholly-owned subsidiary of Edison Energy Group that advises and provides energy solutions to large energy users |
Edison Energy Group | | Edison Energy Group, Inc., the holding company for subsidiaries engaged in competitive businesses focused on providing energy services, including distributed generation and/or storage, 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 |
EMG | | Edison Mission Group Inc., a wholly owned subsidiary of Edison International and the parent company of EME and Edison Capital |
ERRA | | energy resource recovery account |
FERC | | Federal Energy Regulatory Commission |
GAAP | | generally accepted accounting principles |
GHG | | greenhouse gas |
GRC | | general rate case |
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 filed with the SEC in connection with Edison International's and SCE's Annual Shareholders' Meeting held on April 27, 2017 |
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 |
MW | | megawatts |
MWdc | | megawatts measured for solar projects representing the accumulated peak capacity of all the solar modules |
NEIL | | Nuclear Electric Insurance Limited |
NEM | | net energy metering |
NERC | | North American Electric Reliability Corporation |
NRC | | Nuclear Regulatory Commission |
ORA | | CPUC's Office of Ratepayers Advocates |
OII | | Order Instituting Investigation |
Palo Verde | | nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest |
PBOP(s) | | postretirement benefits other than pension(s) |
QF(s) | | qualifying facility(ies) |
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ROE | | return on common equity |
S&P | | Standard & Poor's Ratings Services |
San Onofre | | retired nuclear generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest |
San Onofre OII Settlement Agreement | | Settlement Agreement by and among TURN, ORA, SDG&E, the Coalition of California Utility Employees, and Friends of the Earth, dated November 20, 2014 |
SCE | | Southern California Edison Company |
SDG&E | | San Diego Gas & Electric |
SEC | | U.S. Securities and Exchange Commission |
SED | | Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or CPSD |
SoCalGas | | Southern California Gas Company |
SoCore Energy | | SoCore Energy LLC, a subsidiary of Edison Energy Group that provides solar energy and energy storage solutions |
TURN | | The Utility Reform Network |
US EPA | | U.S. Environmental Protection Agency |
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:
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• | ability of SCE to recover its costs in a timely manner from its customers through regulated rates, including costs related to San Onofre and proposed spending on grid modernization; |
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• | decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities, including determinations of authorized rates of return or return on equity, approval of proposed spending on grid modernization, outcome of San Onofre CPUC proceedings, and delays in regulatory actions; |
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• | ability of Edison International or SCE to borrow funds and access the capital markets on reasonable terms; |
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• | risks associated with cost allocation, including the potential movement of costs to certain customers, caused by the ability of cities, counties and certain other public agencies to generate and/or purchase electricity for their local residents and businesses, along with other possible customer bypass or departure due to increased adoption of distributed energy resources ("DERs") or technological advancements in the generation, storage, transmission, distribution and use of electricity, and supported by public policy, government regulations and incentives; |
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• | risks inherent in the construction of 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), and governmental approvals; |
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• | risks associated with the operation of transmission and distribution assets and power generating facilities including: public safety issues, failure, availability, efficiency, and output of equipment and availability and cost of spare parts; |
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• | risks associated with the decommissioning of San Onofre, including those related to public opposition, permitting, governmental approvals, and cost overruns; |
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• | physical security of Edison International's and SCE's critical assets and personnel and the cybersecurity of Edison International's and SCE's critical information technology systems for grid control, and business and customer data; |
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• | ability of Edison International to develop Edison Energy Group, manage new business risks, and recover and earn a return on its investment in newly developed or acquired businesses; |
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• | cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs in the event of power plant outages or significant counterparty defaults under power-purchase agreements; |
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• | environmental laws and regulations, at both the state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business; |
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• | changes in tax laws and regulations, at both the state and federal levels, or changes in the application of those laws; that could affect recorded deferred tax assets and liabilities and effective tax rate; |
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• | changes in the fair value of investments and other assets; |
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• | changes in interest rates and rates of inflation, including escalation rates, which may be adjusted by public utility regulators; |
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• | 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, WECC and similar regulatory bodies in adjoining regions; |
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• | availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations; |
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• | cost and availability of labor, equipment and materials; |
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• | ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance or in the absence of insurance the ability to recover uninsured losses; |
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• | potential for penalties or disallowance for non-compliance with applicable laws and regulations; |
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• | cost of fuel for generating facilities and related transportation, which could be impacted by, among other things, disruption of natural gas storage facilities, to the extent not recovered through regulated rate cost escalation provisions or balancing accounts; |
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• | disruption of natural gas supply due to unavailability of storage facilities, which could lead to electricity service interruptions; and |
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• | weather conditions and natural disasters. |
See "Risk Factors" in this report for additional information on risks and uncertainties that could cause results to differ from those currently expected or that otherwise could impact Edison International, SCE or their subsidiaries.
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 risk, uncertainties and other factors that affect Edison International's and SCE's businesses. Forward-looking statements speak only as of the date they are made and neither Edison International nor SCE are obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International and SCE with the SEC. Edison International and SCE provide direct links to SCE's regulatory filings with the CPUC and the FERC in open proceedings most important to investors at www.edisoninvestor.com (SCE Regulatory Highlights) so that such filings are available to all investors upon SCE filing with the relevant agency.
Except when otherwise stated, references to each of Edison International, SCE, EMG, Edison Energy Group, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to "Edison International Parent and Other" mean Edison International Parent and its consolidated competitive subsidiaries.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MANAGEMENT OVERVIEW
Highlights of Operating Results
Edison International is the parent holding company of SCE. SCE is a public utility primarily engaged in the business of supplying and delivering electricity to an approximately 50,000 square mile area of southern California. Edison International is also the parent company of Edison Energy Group, a holding company for subsidiaries engaged in pursuing competitive business opportunities across energy services and distributed solar to commercial and industrial customers. Such 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 of the information contained in this annual report relates to both filers.
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(in millions) | 2016 | | 2015 | | 2016 vs 2015 Change | | 2014 |
Net income (loss) attributable to Edison International | | | | | | | |
Continuing operations | | | | | | | |
SCE | $ | 1,376 |
| | $ | 998 |
| | $ | 378 |
| | $ | 1,453 |
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Edison International Parent and Other | (77 | ) | | (13 | ) | | (64 | ) | | (26 | ) |
Discontinued operations | 12 |
| | 35 |
| | (23 | ) | | 185 |
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Edison International | 1,311 |
| | 1,020 |
| | 291 |
| | 1,612 |
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Less: Non-core items | | | | | | | |
SCE | | | | | | | |
Write-down, impairment and other charges | — |
| | (382 | ) | | 382 |
| | (72 | ) |
NEIL insurance recoveries | — |
| | 12 |
| | (12 | ) | | — |
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Edison International Parent and Other | | | | | | | |
Edison Capital sale of affordable housing portfolio | — |
| | 10 |
| | (10 | ) | | — |
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Income from allocation of losses to tax equity investor | 5 |
| | 9 |
| | (4 | ) | | 2 |
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Discontinued operations | 12 |
| | 35 |
| | (23 | ) | | 185 |
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Total non-core items | 17 |
| | (316 | ) | | 333 |
| | 115 |
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Core earnings (losses) | | | | | | | |
SCE | 1,376 |
| | 1,368 |
| | 8 |
| | 1,525 |
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Edison International Parent and Other | (82 | ) | | (32 | ) | | (50 | ) | | (28 | ) |
Edison International | $ | 1,294 |
| | $ | 1,336 |
| | $ | (42 | ) | | $ | 1,497 |
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Edison International's earnings are prepared in accordance with GAAP used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as earnings attributable to Edison International shareholders less non-core items. Non-core items include income or loss from discontinued operations, income resulting from allocation of losses to tax equity investor under the HLBV accounting method and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including sale of certain assets and other activities that are no longer continuing, write downs, asset impairments and other gains and losses related to certain tax, regulatory or legal settlements or proceedings.
Edison International's 2016 earnings increased $291 million, driven by an increase in SCE's earnings of $378 million partially offset by increased costs at Edison International Parent and Other and lower income from discontinued operations. SCE's increased net income consisted of $8 million of higher core earnings and $370 million of higher non-core earnings. The increase in core earnings was due to an increase in revenue from the escalation mechanism set forth in the 2015 GRC decision and lower operations and maintenance expenses, partially offset by higher net financing costs and tax expense.
Edison International Parent and Other results for 2016 consisted of $50 million of higher core losses and $14 million of lower non-core earnings. During 2016, Edison International Parent and Other recorded an after-tax charge of $13 million related to the buy-out of an earn-out provision with the former shareholders of a company acquired by Edison Energy at the end of 2015. The buy-out was completed, together with modification to employment contracts, in order to align long-term incentive compensation. In addition, core losses for 2016 included higher operating and development costs and lower revenue and gross margin from the sale of solar systems at Edison Energy Group. Results during 2015 included income from Edison Capital's investments in affordable housing projects, which were sold at the end of 2015.
Consolidated non-core items for 2016 and 2015 for Edison International included:
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• | SCE's write-down of $382 million in 2015 of regulatory assets previously recorded for recovery of deferred income taxes from 2012 – 2014 incremental tax repair deductions. |
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• | Income of $20 million ($12 million after-tax) in 2015 at SCE related to shareholder's portion of NEIL insurance recoveries arising from the outage and shutdown of the San Onofre Units 2 and 3 generating stations and the recovery of legal costs. |
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• | Income of $16 million ($10 million after-tax) in 2015 related to completion of the sale of Edison Capital's affordable housing investment portfolio which represented the exit from this business activity. |
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• | Income of $5 million and $9 million for 2016 and 2015, respectively, related to losses (net of distributions) allocated to tax equity investors under the HLBV accounting method. Edison International reflected in core earnings the operating results of the solar projects, related financings and the priority return to the tax equity investor. The losses allocated to the tax equity investor under HLBV accounting method results in income allocated to subsidiaries of Edison International, neither of which is due to the operating performance of the projects but rather due to the allocation of income tax attributes under the tax equity financing. Accordingly, Edison International has included the non-operating allocation of income as a non-core item. For further information on HLBV, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies." |
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• | Income from discontinued operations, net of tax, was $12 million and $35 million for 2016 and 2015, respectively, primarily related to the resolution of tax issues related to EME. The discontinued operations from 2015 also reflects proceeds from insurance recoveries related to EME. See "Notes to Consolidated Financial Statements—Note 7. Income Taxes" for further information. |
See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations, including a comparison of 2015 results to 2014.
Electricity Industry Trends
The electric power industry is undergoing transformative change driven by technological advancements such as customer-owned generation and energy storage, which could alter the nature of energy generation and delivery. California's environmental policy objectives are accelerating the pace and scope of the industry change. The electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives, which continue to be publicly supported by California policy makers notwithstanding a potential change in the federal approach to such matters. The grid is also key to enabling more customer choices with respect to new energy technologies. The transformative change taking place in the electric power industry is integral to Edison International's strategy.
SCE plans to be a key enabler of the adoption of new energy technologies that benefit customers of the electric grid while also helping the state of California achieve its environmental goals. SCE expects to achieve these objectives through modernizing the electric grid to improve the safety and reliability of the transmission and distribution network and enabling increased penetration of DERs. SCE's ongoing focus to drive operational and service excellence should allow it to achieve these objectives while controlling costs and customer rates. SCE's focus on the transmission and distribution side of the utility business aligns with California's policy supporting competitive power markets. It also represents a lower risk than investment in conventional, natural gas-fired generation, which faces potentially stricter GHG limits as well as the increasing competitiveness of renewable resource fueled generation. For more information on the distribution grid development, see "—Capital Program—Distribution 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, even if the federal approach to such objectives changes, and large commercial and industrial customers will continue to pursue cost reduction and sustainability goals. Edison Energy Group provides energy services to large commercial and industrial customers who may be impacted by these changes. Edison Energy Group 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.
Capital Program
Total capital expenditures (including accruals), were $3.5 billion in 2016. SCE's year-end rate base was $25.9 billion at December 31, 2016 compared to $24.6 billion at December 31, 2015.
To support a safe and reliable transmission and distribution network, and to modernize the electric grid to enable increased penetration of DERs, SCE forecasts capital expenditures of up to $19.3 billion for 2017 – 2020. The capital forecast for
2017 – 2020 reflects updates primarily to reflect the delay in receipt of project approvals on the West of Devers project and the Mesa Substation project (see "Liquidity—Capital Investment Plan" for further information). The forecasted CPUC capital expenditures include traditional capital spending, such as infrastructure replacement and maintenance, expansions and additions due to load growth and work requested by customers, as well as expenditures for grid modernization to support improved safety and reliability and increased levels of DERs. Traditional capital spending for 2017 reflects SCE's forecast capital expenditures for CPUC and FERC capital projects. Also included in 2017 capital expenditures is a baseline of grid modernization spending that will promote increased safety and reliability and also allow for a timely ramp-up of grid modernization capital expenditures in subsequent years. SCE has requested CPUC approval of a memorandum account to facilitate recovery in rates of such expenditures. The memorandum account has not yet been approved by the CPUC. SCE may receive further guidance on grid modernization spending from the CPUC as part of the DRP proceeding in the second half of 2017. Traditional capital expenditures for 2018 – 2020 reflect the amounts requested in the 2018 GRC filing and FERC capital projects. The CPUC has approved 81%, 89% and 92% of the traditional capital expenditures requested in the 2009, 2012 and 2015 GRC decisions, respectively. While SCE cannot predict the level of traditional capital spending that will be approved in the 2018 GRC decision, management is not aware of factors that would cause the percentage of SCE's request that is ultimately approved to be materially different from what has been approved in recent GRC decisions. SCE does not have prior approval experience with grid modernization capital expenditures and, therefore, is unable to predict an expected outcome.
Forecasted expenditures for FERC capital projects is subject to timely receipt of permitting, licensing and regulatory approvals. The following table sets forth a summary of capital expenditures for 2016 actual spend and a forecast for
2017 – 2020 on the basis described above:
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(in millions) | | 2016 Actual | 2017 | 2018 | 2019 | 2020 | Total 2017 – 2020 |
Traditional capital expenditures | | | | | | | |
Distribution | | $ | 2,840 |
| $ | 3,145 |
| $ | 3,214 |
| $ | 3,156 |
| $ | 3,085 |
| $ | 12,600 |
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Transmission | | 457 |
| 629 |
| 919 |
| 996 |
| 1,033 |
| 3,577 |
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Generation | | 203 |
| 204 |
| 225 |
| 216 |
| 206 |
| 851 |
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Total requested traditional capital expenditures1, 2 | | $ | 3,500 |
| $ | 3,978 |
| $ | 4,358 |
| $ | 4,368 |
| $ | 4,324 |
| $ | 17,028 |
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Grid modernization capital expenditures | | $ | 27 |
| $ | 182 |
| $ | 637 |
| $ | 751 |
| $ | 714 |
| $ | 2,284 |
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Total capital expenditures | | $ | 3,527 |
| $ | 4,160 |
| $ | 4,995 |
| $ | 5,119 |
| $ | 5,038 |
| $ | 19,312 |
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1 | Includes Energy Storage of $50 million in 2016 and $60 million in the 2017 – 2020 period. Also, includes $12 million Charge Ready Pilot in 2017. |
2 Capital expenditures for 2017 reflect management's expectations based on the 2015 GRC decision.
Capital expenditures for traditional capital projects under CPUC jurisdiction for 2017 are included in SCE's 2015 GRC. The 2018 – 2020 capital expenditures are included in the 2018 GRC application request discussed below. Recovery for
2017 – 2020 planned expenditures for traditional capital projects under FERC jurisdiction will be pursued through FERC-authorized mechanisms. For further information regarding the capital program, see "Liquidity and Capital Resources—SCE—Capital Investment Plan."
SCE's estimated weighted average annual rate base for 2017 – 2020 using the capital expenditures set forth in the table above is as follows:
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(in millions) | | 2017 | 2018 | 2019 | 2020 |
Rate base for requested traditional capital expenditures | | $ | 26,241 |
| $ | 29,052 |
| $ | 31,161 |
| $ | 33,229 |
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Rate base for requested grid modernization capital expenditures | | — |
| 279 |
| 802 |
| 1,398 |
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Total rate base | | $ | 26,241 |
| $ | 29,331 |
| $ | 31,963 |
| $ | 34,627 |
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The rate base above does not reflect reductions from the amounts requested in the 2018 GRC that may be included in a final decision.
Distribution Grid Development
Distribution Resources Plan
In July 2015, SCE filed its DRP with the CPUC. The filing was made as part of a CPUC proceeding that was initiated to support California's climate change and GHG reduction targets, modernize the electric distribution system to accommodate two-way flows of energy associated with DERs, such as rooftop solar, and facilitate customer choice of new technologies and services that reduce emissions and improve resilience. SCE's DRP included an indicative forecast of capital investment in distribution automation, substation automation, communications systems, technology platforms and applications, and grid reinforcement. The 2018 GRC includes operation and maintenance and capital expenditure requests consistent with SCE's DRP operation and maintenance and capital spending. Capital investments for 2017 may be updated or revised based on developments and guidance received from the CPUC as a part of the GRC, DRP rule making, technology availability, pace of DER adoption, and other factors. In January 2016, the CPUC issued a scoping memo that provided for the issuance of guidance on utility spending to modify its grid in order to support its DRP. SCE expects to receive such guidance in the second half of 2017.
Charge Ready Program
In January 2016, the CPUC approved SCE's $22 million Charge Ready Phase 1 pilot program, which will allow SCE to install light-duty vehicle charging infrastructure, provide rebates to offset the cost of qualified customer-owned charging stations, and implement a supporting market education effort. Under the Phase 1 pilot program, SCE will build, own and maintain the electric infrastructure needed to serve the qualified charging stations at participating customer locations. Participating customers will install, own, maintain, and operate the charging stations. By the end of January 2017, SCE had executed agreements for 50 sites to deploy 776 charge ports. The results of this pilot will help shape Phase 2 of the program. SCE will file an application to obtain CPUC approval for Phase 2 after at least one year (Phase 1 launched in late May 2016) and 1,000 charge ports have been deployed.
Transportation Electrification Plan
In January 2017, SCE filed a transportation electrification plan with the CPUC that aims to accelerate the adoption of electric transportation, which is critical to California's climate change and GHG reduction objectives. The plan proposes a five-year program to fund medium- and heavy-duty vehicle charging infrastructure that follows the model developed for SCE's Charge Ready program discussed above. The proposal has an estimated five-year cost of $554 million ($532 million capital) in 2016 dollars. In addition, the plan proposes six pilot projects to be considered by the CPUC on an accelerated basis. The pilot projects would install charging infrastructure for electric transit buses and the Port of Long Beach; build clusters of fast charging sites in urban areas, and establish programs that would incentivize electric vehicle adoption. The estimated total cost of the six pilot projects is approximately $19 million ($14 million capital) in 2016 dollars. SCE expects to propose additional programs and pilots in the future.
All of the plan's proposed transportation electrification projects are subject to CPUC review and the timing and amount of capital investments for any approved project will depend upon implementation decisions, including scope and pace of adoption and GRC ratemaking decisions and other CPUC actions. SCE is unable to predict an expected outcome on or timing of implementation of any of the proposed projects. The capital costs for these proposed projects are not included in SCE's capital spending and rate base forecasts provided above.
Edison International Dividend Policy
In December 2016, Edison International declared a 13% increase to the annual dividend rate from $1.92 per share to $2.17 per share. Edison International plans to increase its dividends to common shareholders at a higher than industry average growth rate within its target payout ratio of 45% to 55% of SCE earnings in steps over time. This is expected to yield a dividend growth at a faster pace than SCE's earnings growth.
Regulatory Proceedings
2018 General Rate Case
In September 2016, SCE filed its 2018 GRC application for the three-year period 2018 – 2020, which requested a 2018 revenue requirement of $5.885 billion, an increase of $222 million over the projected 2017 GRC authorized revenue requirement. In addition, SCE requested $48 million in one-time balancing and memorandum account recoveries. This represents a 2.7% increase over presently authorized total rates. SCE's 2018 GRC request also includes proposed revenue requirement increases of $533 million in 2019 and $570 million in 2020. For 2019 and 2020, respectively, these represent 4.2% and 5.2% increases over presently authorized total rates.
The capital programs requested in SCE's 2018 GRC are focused on safety and reliability through investments in the distribution grid to replace aging equipment and enhance capabilities to integrate increasing amounts of DERs. For further information, see "—Capital Program" above.
SCE's 2018 GRC request identifies areas of reduced operating cost to partially mitigate the customer rate impacts of the request.
SCE requested that the CPUC issue a final decision by the end of 2017. If the schedule for a final decision is delayed, SCE will request the CPUC to issue an order directing that the authorized revenue requirement changes be effective January 1, 2018. SCE cannot predict the revenue requirement the CPUC will ultimately authorize for 2018 through 2020 or forecast the timing of a final decision.
Permanent Retirement of San Onofre
Replacement steam generators were installed at San Onofre in 2010 and 2011. On January 31, 2012, a leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. The Unit was safely taken off-line and subsequent inspections revealed excessive tube wear. Unit 2 was off-line for a planned outage when areas of unexpected tube wear were also discovered. On June 6, 2013, SCE decided to permanently retire Units 2 and 3.
San Onofre CPUC Proceedings
In November 2014, the CPUC approved the San Onofre OII Settlement Agreement, which resolved the CPUC's investigation regarding the steam generator replacement project at San Onofre and the related outages and subsequent shutdown of San Onofre. Subsequently, the San Onofre OII proceeding record was reopened by a joint ruling of the Assigned Commissioner and the Assigned ALJ to consider whether, in light of the Company not reporting certain ex parte communications on a timely basis, the San Onofre OII Settlement Agreement remained reasonable, consistent with the law and in the public interest, which is the standard the CPUC applies in reviewing settlements submitted for approval. In comments filed with the CPUC in July 2016, SCE asserted that the Settlement Agreement continues to meet this standard and therefore should not be disturbed. A number of the parties to the OII, however, have requested that the CPUC either modify the San Onofre OII Settlement Agreement or vacate its previous approval of the settlement and reinstate the OII for further proceedings.
In a December 2016 joint ruling, the Assigned Commissioner and the Assigned ALJ expressed concerns about the extent to which the failure to timely report ex parte communications had impacted the settlement negotiations and directed SCE to meet and confer with the other parties in the OII to consider changing the terms of the San Onofre OII Settlement Agreement. The ruling set out a schedule requiring that at least two meet and confer sessions be held in the first quarter of 2017 and requiring the parties to submit a joint status report to the CPUC by April 28, 2017 if no modifications have been agreed to by some or all of the parties as a result of the meet and confer process. SCE has recorded a regulatory asset to reflect the expected recoveries under the San Onofre OII Settlement Agreement. At December 31, 2016, $857 million remains to be collected.
For more information on the challenges to the settlement of the San Onofre OII and the claims that SCE is pursuing against MHI, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—San Onofre Related Matters."
Cost of Capital
On February 7, 2017, SCE, Pacific Gas and Electric Company, SDG&E, and SoCalGas (collectively, the “Investor-Owned Utilities”), ORA and TURN jointly filed a petition to modify the prior CPUC decisions addressing the Investor-Owned Utilities' costs of capital. The requested modifications would extend the next cost of capital application filing deadline two years to April 22, 2019 for the year 2020; reset SCE's authorized cost of long-term debt and preferred stock in 2018; and reduce SCE's authorized ROE. Subject to the CPUC's approval of the petition for modification, SCE's authorized ROE will be reduced from the current 10.45% to 10.30% beginning on January 1, 2018. The updated cost of capital and corresponding revenue requirement impact will be submitted to the CPUC in September 2017, to be effective January 1, 2018. While the actual changes to SCE's revenue requirement resulting from the petition for modification will not be known until SCE's filing in September 2017, SCE estimates that its annual revenue requirement will be reduced by approximately $66 million (approximately $39 million after-tax), beginning in 2018. Changes in market interest rates can have material effects on the cost of SCE’s future financings and consequently on the estimated change in annual revenue requirements.
The petition for modification provides that SCE's long-term debt, preferred stock and common equity costs will be reset for the year 2018 and will then remain unchanged until December 31, 2019 unless they are changed by the operation of the cost of capital adjustment mechanism. SCE’s current ratemaking capital structure (48% common equity, 43% long-term debt, and 9% preferred equity) will remain unchanged and the cost of capital adjustment mechanism would not operate in 2017 but could operate in 2018 to change the cost of capital for 2019. If the mechanism is activated for 2019, SCE’s new 10.30% ROE will be adjusted according to the existing terms of the mechanism.
Energy Efficiency Incentive Mechanism
In December 2016, the CPUC awarded SCE incentives of approximately $18 million, approximately 75% of the requested award, for Part 2 of the 2014 program year and Part 1 of the 2015 program year savings. There is no assurance that the CPUC will make an award for any given year.
FERC Formula Rates
In November 2016, SCE filed its 2017 annual update with the FERC with the rates effective from January 1, 2017 to December 31, 2017. The update provided support for an increase in SCE's transmission revenue requirement of $97 million or 9% over amounts currently authorized in rates. The increase is mainly due to the completion of several major transmission projects in 2015 and to recover prior undercollections. FERC has approved SCE's formula or methodology for setting transmission rates under its jurisdiction through 2017. SCE is required to file a replacement rate methodology by November 2017, to be effective January 2018.
Long Beach Service Interruptions
In July 2015, SCE's customers who are served via the network portion of SCE's electric system in Long Beach, California experienced service interruptions due to multiple underground vault fires and underground cable failures. No personal injuries were reported in connection with these events. SCE expects to incur penalties as a result of these events. Although resolution will be subject to settlement discussions with SED and CPUC review and approval, SCE has recorded a liability for the estimated loss.
RESULTS OF OPERATIONS
SCE
SCE's results of operations are derived mainly through two sources:
| |
• | Earning activities – representing revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of authorized operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in earnings activities are 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 results of operations for the periods indicated.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | 2015 | 2014 |
(in millions) | Earning Activities | Cost- Recovery Activities | Total Consolidated | Earning Activities | Cost- Recovery Activities | Total Consolidated | Earning Activities | Cost- Recovery Activities | Total Consolidated |
Operating revenue | $ | 6,504 |
| $ | 5,326 |
| $ | 11,830 |
| $ | 6,305 |
| $ | 5,180 |
| $ | 11,485 |
| $ | 6,831 |
| $ | 6,549 |
| $ | 13,380 |
|
Purchased power and fuel | — |
| 4,527 |
| 4,527 |
| — |
| 4,266 |
| 4,266 |
| — |
| 5,593 |
| 5,593 |
|
Operation and maintenance | 1,939 |
| 798 |
| 2,737 |
| 1,977 |
| 913 |
| 2,890 |
| 2,106 |
| 951 |
| 3,057 |
|
Depreciation, decommissioning and amortization | 1,998 |
| — |
| 1,998 |
| 1,915 |
| — |
| 1,915 |
| 1,720 |
| — |
| 1,720 |
|
Property and other taxes | 351 |
| — |
| 351 |
| 334 |
| — |
| 334 |
| 318 |
| — |
| 318 |
|
Impairment and other charges | — |
| — |
| — |
| — |
| — |
| — |
| 163 |
| — |
| 163 |
|
Total operating expenses | 4,288 |
| 5,325 |
| 9,613 |
| 4,226 |
| 5,179 |
| 9,405 |
| 4,307 |
| 6,544 |
| 10,851 |
|
Operating income | 2,216 |
| 1 |
| 2,217 |
| 2,079 |
| 1 |
| 2,080 |
| 2,524 |
| 5 |
| 2,529 |
|
Interest expense | (540 | ) | (1 | ) | (541 | ) | (525 | ) | (1 | ) | (526 | ) | (528 | ) | (5 | ) | (533 | ) |
Other income and expenses | 79 |
| — |
| 79 |
| 64 |
| — |
| 64 |
| 43 |
| — |
| 43 |
|
Income before income taxes | 1,755 |
| — |
| 1,755 |
| 1,618 |
| — |
| 1,618 |
| 2,039 |
| — |
| 2,039 |
|
Income tax expense | 256 |
| — |
| 256 |
| 507 |
| — |
| 507 |
| 474 |
| — |
| 474 |
|
Net income | 1,499 |
| — |
| 1,499 |
| 1,111 |
| — |
| 1,111 |
| 1,565 |
| — |
| 1,565 |
|
Preferred and preference stock dividend requirements | 123 |
| — |
| 123 |
| 113 |
| — |
| 113 |
| 112 |
| — |
| 112 |
|
Net income available for common stock | $ | 1,376 |
| $ | — |
| $ | 1,376 |
| $ | 998 |
| $ | — |
| $ | 998 |
| $ | 1,453 |
| $ | — |
| $ | 1,453 |
|
Net income available for common stock | | | $ | 1,376 |
| | | $ | 998 |
| | | $ | 1,453 |
|
Less: Non-core items | | | | | | | | | |
Impairment and other charges | | | — |
| | | (382 | ) | | | (72 | ) |
NEIL insurance recoveries | | | — |
| | | 12 |
| | | — |
|
Core earnings1 | | | $ | 1,376 |
| | | $ | 1,368 |
| | | $ | 1,525 |
|
| |
1 | See use of non-GAAP financial measures in "Management Overview—Highlights of Operating Results." |
Earning Activities
2016 vs 2015
Earning activities were primarily affected by the following:
| |
• | Higher operating revenue of $199 million is primarily due to: |
| |
• | An increase in revenue of approximately $191 million related to the increase in authorized revenue from the escalation mechanism set forth in the 2015 GRC decision. |
| |
• | An increase in FERC-related revenue of $68 million primarily related to higher operating costs including amortization of the regulatory asset associated with the Coolwater-Lugo transmission project and rate base growth partially offset by a $15 million increase in 2015 due to a change in estimate under the FERC formula rate mechanism. |
| |
• | An increase in revenue of $25 million ($15 million after-tax) related to the incremental return on the pole loading rate base recorded through the pole loading balancing account. |
| |
• | An increase of $46 million primarily due to tax benefits recognized in 2015 related to net operating loss carrybacks for San Onofre decommissioning costs resulting in a reduction in revenue in 2015 (offset in income taxes). |
| |
• | A decrease in revenue of $52 million for incremental tax benefits refunded to customers. In 2016, SCE recorded a revenue refund to customers of $133 million for 2012 – 2014 incremental tax benefits related to repair deductions (offset in income taxes as discussed below). This revenue refund resulted from the CPUC's approval of SCE's request to refund incremental tax repair deductions that were not addressed in SCE's 2015 GRC decision. Partially offsetting |
the refund of 2012 – 2014 incremental tax repair deductions, SCE recognized $81 million lower incremental tax repairs and other benefits refunded to customers through balancing accounts in 2016.
| |
• | Energy efficiency incentive awards were $18 million in 2016 compared to $29 million in 2015. In addition, in 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. |
| |
• | SCE's portion of NEIL insurance and legal cost recoveries of approximately $20 million in 2015 arising from the outage and shutdown of the San Onofre Units 2 and 3 generating stations. |
| |
• | A decrease of $29 million for other operating revenue resulting from lower contributions received from customers due to the retroactive extension of bonus depreciation in the PATH Act of 2015. |
| |
• | Lower operation and maintenance expense of $38 million primarily due to lower labor related to SCE's focus on operational and service excellence as well as lower outside services partially offset by higher transmission and distribution costs for rain and storm-related activities. |
| |
• | Higher depreciation, decommissioning and amortization expense of $83 million primarily related to depreciation on higher rate base and amortization of the regulatory asset related to the Coolwater-Lugo plant, as discussed above. |
| |
• | Higher property and other taxes of $17 million primarily due to higher property assessed values in 2016. |
| |
• | Higher interest expense of $15 million primarily due to reduced interest capitalization (AFUDC debt) related to lower construction work in progress balances and a higher interest rate on balancing account overcollections in 2016. |
| |
• | Higher other income and expenses of $15 million primarily due to higher insurance benefits and lower advertising expense in 2016. See "Notes to Consolidated Financial Statements—Note 14. Interest and Other Income and Other Expenses" for further information. |
| |
• | Lower income taxes of $251 million primarily due to the following: |
| |
• | Write-down of $382 million in 2015 of regulatory assets previously recorded for recovery of deferred income taxes from 2012 – 2014 incremental tax repair deductions. |
| |
• | Higher income tax benefits in 2016 of $31 million primarily due to $79 million related to the flow-through of incremental tax benefits for 2012 – 2014 to customers partially offset by lower income tax benefits in 2016 of |
$48 million related to the flow-through of incremental tax repair and other benefits refunded to customers through balancing accounts.
| |
• | Lower income tax expense in 2016 of $13 million related to the adoption of the FASB guidance on accounting for share-based payments (see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Guidance—New Accounting Guidance" for further information). |
| |
• | A change in liabilities related to uncertain tax positions related to repair deductions, which resulted in income tax benefits of $100 million during the second quarter of 2015. See "—Income Taxes" below for more information. |
| |
• | Higher pre-tax income in 2016, as discussed above. |
| |
• | Higher preferred and preference stock dividends of $10 million primarily related to new issuances in 2016 and late 2015 partially offset by redemptions of preferred stock. |
2015 vs 2014
Earning activities were primarily affected by the following:
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• | Lower operating revenue of $526 million is primarily due to: |
| |
• | A decrease in authorized CPUC revenue of $379 million (excludes amounts classified as cost-recovery activities). The decrease in revenue is primarily due to lower authorized revenue for operation and maintenance expenses and for flow-through items for income tax benefits related to repair and cost of removal deductions. |
| |
• | A decrease in revenue from approximately $300 million of tax benefits in excess of amounts authorized in the 2015 GRC and recognized through the TAMA and the pole loading balancing account (offset in income tax benefits |
discussed below). In addition, SCE recorded $39 million ($26 million after-tax) of incremental return on the pole loading rate base recorded through this balancing account.
| |
• | An increase in FERC-related revenue of $83 million primarily related to rate base growth and higher operating costs. |
| |
• | An increase in San Onofre-related revenue of $40 million due to the implementation of the San Onofre OII Settlement Agreement. Revenue for San Onofre for 2015 primarily related to recovery of amortization of the regulatory asset and authorized return as provided by the San Onofre Settlement Agreement compared to revenue in 2014 related to recovery of San Onofre's cost of service. |
| |
• | Energy efficiency incentive awards were $29 million in 2015 compared to $22 million in 2014. |
| |
• | SCE's portion of NEIL insurance and legal cost recoveries of approximately $20 million in 2015 (See "Notes to the Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—San Onofre Related Matters" for further information on the agreement with NEIL). |
| |
• | Higher revenue in 2014 from approval by the CPUC of a $30 million increase in the 2012 – 2014 authorized revenue requirement related to deferred income taxes and from $15 million of generator settlements. See “Notes to the Consolidated Financial Statements—Note 10. Regulatory Assets and Liabilities—Net Regulatory Balancing Accounts.” |
| |
• | Lower operation and maintenance expense of $129 million primarily due to: |
| |
• | Lower San Onofre-related expense of $93 million. During 2014, San Onofre-related expenses were recorded as operation and maintenance expenses. During 2015, the CPUC authorized SCE reimbursement of 2014 costs from the nuclear decommissioning trusts with such reimbursement subsequently refunded to customers. During 2015, decommissioning expenses were reimbursed from the nuclear decommissioning trust and, therefore, did not result in operation and maintenance expenses. |
| |
• | A decrease of $77 million primarily related to transmission and distribution, legal, and customer service costs partially offset by higher outside service costs in 2015. |
| |
• | Higher severance costs related to workforce reduction efforts ($26 million in 2015 and $2 million in 2014). |
| |
• | In 2015, SCE incurred a penalty of approximately $17 million related to not reporting certain ex parte communications on a timely basis. |
| |
• | Higher depreciation, decommissioning and amortization expense of $195 million primarily due to San Onofre-related expense of $134 million in 2015 related to the amortization of the regulatory asset and a $61 million increase in depreciation primarily related to transmission and distribution investments. |
| |
• | Higher property and other taxes of $16 million primarily due to an increase in assessed property values in 2015. |
| |
• | Impairment and other charges of $163 million ($72 million after-tax) in 2014 related to the San Onofre OII Settlement Agreement, as discussed below. |
| |
• | Higher other income and expenses of $21 million primarily due to higher AFUDC equity income related to a higher rate and higher construction work in progress balances in 2015 and a $15 million penalty recorded in 2014 resulting from the San Bernardino and San Gabriel settlements. These increases were offset by $10 million of lower insurance benefits in 2015 and a $7 million of sales tax refund related to San Onofre received in 2014. See "Notes to Consolidated Financial Statements—Note 14. Interest and Other Income and Other Expenses" for further information. |
| |
• | Higher income taxes of $33 million primarily due to the following: |
| |
• | Write-down of $382 million in 2015 of regulatory assets previously recorded for recovery of deferred income taxes from 2012 – 2014 incremental tax repair deductions. |
| |
• | An increase in income tax benefits in 2015 primarily related to $263 million (after-tax) of repair deductions (offset in operating revenue above) for TAMA and pole loading balancing account partially offset by lower tax benefits on other property-related items in 2015. |
| |
• | A change in liabilities related to uncertain tax positions related to repair deductions, which resulted in income tax benefits of $100 million and $29 million during the second quarters of 2015 and 2014, respectively. See "—Income Taxes" below for more information. |
| |
• | Lower pre-tax income in 2015, as discussed above, partially offset by the impact of the San Onofre OII Settlement Agreement. |
Cost-Recovery Activities
2016 vs 2015
Cost-recovery activities were primarily affected by the following:
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• | Higher purchased power and fuel of $261 million primarily due to the NEIL insurance recoveries received in 2015 (discussed below) and a change in portfolio mix partially offset by lower load related to cooler weather. |
In October 2015, San Onofre owners reached an agreement with NEIL to resolve all insurance claims arising out of the failures of the San Onofre replacement steam generators. SCE customer's portion of amounts recovered from NEIL has been distributed to SCE customers via a credit to SCE's ERRA account of approximately $300 million in 2015.
| |
• | Lower operation and maintenance expense of $115 million primarily due to lower transmission access charges and lower spending on various public purpose programs partially offset by an increase in transmission and distribution costs for drought related activities. |
2015 vs 2014
Cost-recovery activities were primarily affected by the following:
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• | Lower purchased power and fuel of $1.3 billion primarily driven by lower power and gas prices, the NEIL insurance recoveries and the CAISO generation surcharge of $83 million in 2014 (as discussed below). These decreases were partially offset by higher realized losses on economic hedging activities ($148 million in 2015 compared to $57 million in 2014). Fuel costs were $176 million in 2015 and $256 million in 2014. |
During 2014, the CAISO issued invoices implementing a FERC order which revised FERC tariffs for costs associated with scheduling coordinator activities. The impact of implementing the order and revised invoices resulted in a transmission refund of $106 million reflected in operation and maintenance expense and a generation surcharge of $83 million reflected in purchased power expense. These transactions did not impact earnings as the net refund was provided to customers through a FERC balancing account mechanism.
| |
• | Lower operation and maintenance expense of $38 million primarily due to lower spending on various public purpose programs, lower pension and benefit expenses and a decrease in transmission access charges, partially offset by the 2014 CAISO refund of $106 million as discussed above. |
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was
$10.7 billion in 2016 and $12.2 billion for both 2015 and 2014.
The 2016 revenue reflects:
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• | A decrease of $1.15 billion primarily due to the implementations of the 2016 ERRA rate decrease and the 2015 GRC decision in January 2016. |
| |
• | A sales volume decrease of $321 million due to lower load requirements related to cooler weather experienced in 2016 compared to 2015. |
The 2015 revenue reflects:
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• | An increase of $160 million primarily due to the implementations of the 2014 ERRA rate increase in June 2014 and the San Onofre-related rate adjustment in January 2015. |
| |
• | A sales volume decrease of $169 million due to lower load requirements related to cooler weather experienced in 2015 compared to 2014. |
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 $251 million in 2016 compared to 2015 and increased by $33 million in 2015 compared to 2014. The effective tax rates were 14.6%, 31.3% and 23.2% for 2016, 2015 and 2014, respectively. SCE's effective tax rate is below the federal statutory rate of 35% primarily due to CPUC's ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences, which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense. The effective tax rate decrease in 2016 was primarily due to the
$382 million write-down in 2015 of regulatory assets (discussed in "Management Overview—Highlights of Operating Results") partially offset by revisions in liabilities related to uncertain tax positions in 2015. The effective tax rate increase in 2015 was primarily due to a $382 million write-down in 2015 of regulatory assets and income tax benefits in 2014 related to San Onofre OII Settlement Agreement, partially offset by higher income tax benefits related to tax repair deductions (as discussed above) and the change in liabilities related to uncertain tax positions.
See "Notes to Consolidated Financial Statements—Note 7. Income Taxes" for a reconciliation of the federal statutory rate of 35% to the effective income tax rates and "Management Overview—Permanent Retirement of San Onofre" above for more information.
Edison International Parent and Other
Results of operations for Edison International Parent and Other includes amounts from other subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.
Loss from Continuing Operations
The following table summarizes the results of Edison International Parent and Other:
|
| | | | | | | | | | | |
| Years ended December 31, |
(in millions) | 2016 | | 2015 | | 2014 |
Edison Energy Group and subsidiaries1 | $ | (38 | ) | | $ | (6 | ) | | $ | (5 | ) |
Edison Mission Group and subsidiaries | — |
| | 32 |
| | 36 |
|
Corporate expenses and other2 | (39 | ) | | (39 | ) | | (57 | ) |
Total Edison International Parent and Other3 | $ | (77 | ) | | $ | (13 | ) | | $ | (26 | ) |
| |
1 | Includes income of $5 million, $9 million and $2 million in 2016, 2015, 2014 related to losses (net of distributions) allocated to tax equity investors under the HLBV accounting method. |
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2 | Includes interest expense (pre-tax) of $37 million, $31 million and $25 million in 2016, 2015, and 2014, respectively. |
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3 | Includes income tax benefits of $15 million in 2016 related to the adoption of an accounting standard for share-based payments. See "Notes to Consolidated Financial Statements—Note 1" for further information. |
The loss from continuing operations of Edison International Parent and Other increased $64 million in 2016 compared to 2015 primarily due to:
| |
• | An increase in losses of Edison Energy Group of $32 million, including a $13 million after-tax charge during 2016 from a buy-out of an earn-out provision contained in one of the 2015 acquisitions, higher operating and development expenses and lower revenue and gross margin from the sale of solar systems in 2016 compared to 2015. The results for the twelve months ended December 31, 2016 include the three businesses acquired by Edison Energy in December 2015 and expanded sales and support personnel. Revenue for the Edison Energy Group was $42 million and $34 million for the twelve months ended December 31, 2016 and 2015, respectively. |
| |
• | A decrease in income from Edison Mission Group and subsidiaries of $32 million in 2016 primarily due to income related to affordable housing projects in 2015. In December 2015, EMG's subsidiary, Edison Capital, completed the sale of its remaining affordable housing investment portfolio which represents the exit of this business activity. |
The loss from continuing operations of Edison International Parent and Other decreased $13 million in 2015 compared to 2014 primarily due to:
| |
• | An increase in losses of Edison Energy Group primarily due to higher operating expenses for 2015. The change was partially offset by an increase in income allocated to subsidiaries of Edison Energy Group under the HLBV accounting method that resulted in losses allocated to tax equity investors. For further information, see "Management Overview—Highlights of Operating Results." |
| |
• | In December 2015, EMG's subsidiary, Edison Capital, completed the sale of its remaining affordable housing investment portfolio which represents the exit of this business activity. Earnings from Edison Capital were $30 million and $34 million for 2015 and 2014, respectively. |
| |
• | A decrease in the loss from corporate expenses and other primarily due to income tax benefits and lower corporate expenses during 2015. |
Income from Discontinued Operations (Net of Tax)
Income from discontinued operations, net of tax, was $12 million, $35 million and $185 million for the years ended December 31, 2016, 2015 and 2014, respectively. The 2016 and 2015 income were primarily related to the resolution of tax issues related to EME. The 2015 income also included insurance recoveries. The 2014 income was related to the impact of completing the transactions called for in the EME Settlement Agreement and income tax benefits from resolution of uncertain tax positions and other impacts related to EME.
LIQUIDITY AND CAPITAL RESOURCES
SCE
SCE's ability to operate its business, fund capital expenditures, and implement its business strategy is dependent upon its cash flow and access to the bank and capital markets. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, interest obligations, dividend payments to Edison International, and the outcome of tax and regulatory matters.
In the next 12 months, SCE expects to fund its obligations, capital expenditures and dividends through operating cash flows, tax benefits and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities to fund cash requirements.
Available Liquidity
At December 31, 2016, SCE had $1.89 billion available under its $2.75 billion credit facility. For further details see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." SCE may finance balancing account undercollections and working capital requirements to support operations and capital expenditures with commercial paper or other borrowings, subject to availability in the capital markets.
Debt Covenant
The debt covenant in SCE's credit facility limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At December 31, 2016, SCE's debt to total capitalization ratio was 0.43 to 1.
At December 31, 2016, SCE was in compliance with all other financial covenants that affect access to capital.
Capital Investment Plan
Major Transmission Projects
A summary of SCE's large transmission and substation projects during the next four years is presented below. The timing of the projects below is subject to timely receipt of permitting, licensing and regulatory approvals. |
| | | | |
Project Name | Project Lifecycle Phase | Direct Expenditures (in millions)1 | Inception to Date (in millions)1 | Scheduled In-Service Date |
West of Devers | Construction | $1,075 | $58 | 2021 |
Mesa Substation | Construction | $608 | $24 | 2020 – 2021 |
Alberhill System | Licensing | $397 | $36 | 2021 |
Riverside Transmission Reliability | Licensing | $233 | $5 | 2021 |
Eldorado-Lugo-Mohave Upgrade | Planning | $269 | $5 | 2020 |
| |
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 forecasted for remaining investment. |
West of Devers
The West of Devers Project consists of upgrading and reconfiguring approximately 48 miles of existing 220 kV transmission lines between the Devers, El Casco, Vista and San Bernardino substations, increasing the power transfer capabilities in support of California's renewable portfolio standards goals.
In August 2016, the CPUC approved the construction of the West of Devers Project. As a result of the delay in receipt of the Project's approval from the CPUC, SCE has deferred the timing of project capital expenditures. ORA 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 the alternative project with the amended scope. SCE does not know when the CPUC will issue a decision on the Application for Rehearing. There is no stay of activities pending determination of the Application for Rehearing and SCE is continuing to perform activities related to construction, such as environmental permitting and mitigation planning in order to achieve a 2021 in-service date.
Mesa Substation
The Mesa Substation Project consists of demolishing the existing 220 kV Mesa Substation and constructing a new 500 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 SCE's proposed project. Construction planning activities that had been delayed pending the CPUC's final decision have commenced.
Alberhill System
The Alberhill System Project consists of constructing a new 500-kV substation, two 500-kV transmission lines to connect the proposed substation to the existing Serrano-Valley 500-kV transmission line, telecommunication equipment and subtransmission lines in unincorporated and incorporated portions of western Riverside County. The Project was designed to meet long-term forecasted electrical demand in the proposed Alberhill Project area and to increase electrical system reliability. In April 2016, the CPUC issued a draft environmental impact report that identified an alternative substation site. The $397 million estimated cost for this project reflects the scope proposed by SCE.
Riverside Transmission Reliability
The Riverside Transmission Reliability Project is a joint project between SCE and Riverside Public Utilities (RPU), the municipal utility department of the City of Riverside. While RPU would be responsible for constructing some of the Project's facilities within Riverside, SCE's portion of the Project consists of constructing upgrades to its system, including a new 230-kV Substation; certain interconnection and telecommunication facilities and transmission lines in the cities of Riverside, Jurupa Valley and Norco and in portions of unincorporated Riverside County. The purpose of the Project is to provide RPU and its customers with adequate transmission capacity to serve existing and projected load, to provide for long-term system capacity for load growth, and to provide needed system reliability. Due to changed circumstances since the time the Project
was originally developed, SCE informed the CPUC in July 2016 that it supports a revised description of the Project. The CPUC continues to collect information regarding the revised Project in support of a supplemental environmental review. Potential revisions to the Project have not been reflected in the direct expenditures or scheduled in service date in the table above, however, revisions are likely to increase the total direct expenditures and delay the completion of the Project.
Eldorado-Lugo-Mohave Upgrade
The Eldorado-Lugo-Mohave Upgrade Project will increase capacity on existing transmission lines to allow additional renewable energy to flow from Nevada to southern California. The Project would modify SCE’s existing Eldorado, Lugo, and Mohave electrical substations to accommodate the increased current flow from Nevada to southern California; increase the power flow through the existing 500 kV transmission lines by constructing two new capacitors along the lines; raise transmission tower heights to meet ground clearance requirements; and install communication wire on our transmission lines to allow for communication between existing SCE substations.
Tehachapi
The Tehachapi 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.
SCE filed a petition for modification with the CPUC in January 2017 to update the cost estimate for all elements of segments 4-11 to $2.7 billion (2016 dollars) from $2.0 billion (2016 dollars) of CPUC-approved cost findings. The cost increase is based on several factors, including additional project scope, schedule delays and work stoppages due to regulatory activity, increased environmental activities, and higher costs than the historical data used for estimates. Many of the cost increases are due to external factors not contemplated when the initial cost estimates were developed and not accounted for in the CPUC's original cost findings, which had also reduced the amount of contingency significantly below SCE's original estimates. Cost recovery for nearly all transmission elements of the project is incorporated in the existing FERC rates, subject to FERC review and approval.
Coolwater-Lugo
In February 2016, SCE filed an abandoned plant recovery request at FERC for the costs of the cancelled Coolwater-Lugo transmission project pursuant to the authority granted by FERC for SCE to recover 100% of all prudently-incurred costs if the project is cancelled for reasons beyond SCE's control. The project was cancelled by the CPUC in 2015 due to a reduction in need. SCE requested recovery of the $37.1 million in costs that SCE incurred for the project over a twelve-month period through the FERC transmission formula rate. In December 2016, SCE reached a settlement under which it will recover 100% of the requested $37.1 million of costs incurred in return for certain additional procedural safeguards to be implemented in all future abandoned plant recovery requests. The period for parties to file any protests to the settlement has expired without any protests filed but the settlement remains subject to FERC approval.
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. The decommissioning process is expected to take many years. Decommissioning of San Onofre Unit 1 began in 1999 and major decommissioning work was completed in 2008, except for reactor vessel disposal and certain underground work that was deferred to allow for the construction of the San Onofre Independent Spent Fuel Storage Installation. The initial activity phase of radiological decommissioning of 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. SCE is currently permitted to start major radiological decommissioning activities pursuant to NRC regulations, provided SCE obtains all necessary environmental permits for decommissioning. SCE has engaged a decommissioning general contractor to undertake a significant scope of decommissioning activities for Units 1, 2 and 3 at San Onofre.
During the second quarter of 2014, SCE updated its decommissioning cost estimate based on a site specific assessment. The decommissioning cost estimate in 2014 dollars is $4.4 billion (SCE share is $3.3 billion) and includes costs from June 7, 2013 through to the respective completion dates to decommission San Onofre Units 2 and 3 estimated to be in 2052. 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 may remove spent fuel canisters from the San Onofre site, as to which there can be no assurance. The cost estimate is subject to change and such changes may be material. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Nuclear Decommissioning and Asset
Retirement Obligations." The CPUC will conduct a reasonableness review for costs for each year. SCE's share of the decommissioning costs recorded during 2016 were $168 million and are subject to reasonableness review by the CPUC.
SCE has nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $2.8 billion as of December 31, 2016. If the decommissioning cost estimate and assumptions regarding trust performance do not change, SCE believes that future contributions to the trust funds will not be necessary.
SCE Dividends
SCE made $701 million and $758 million in dividend payments to its parent, Edison International, in 2016 and 2015, respectively. The timing and amount of future dividends are dependent upon several factors including the level of capital expenditures, operating cash flows and earnings. See "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—SCE Dividend Restrictions" for discussion of dividend restrictions.
Margin and Collateral Deposits
Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at December 31, 2016, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.
Some of the power procurement contracts contain provisions that require SCE to maintain an investment grade credit rating from the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral.
The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of December 31, 2016.
|
| | | | |
(in millions) | | |
Collateral posted as of December 31, 20161 | | $ | 91 |
|
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade | | 37 |
|
Incremental collateral requirements for power procurement contracts resulting from adverse market price movement2 | | 3 |
|
Posted and potential collateral requirements | | $ | 131 |
|
| |
1 | Net collateral provided to counterparties and other brokers consisted $93 million in letters of credit and surety bonds and $2 million of cash reflected in "Other current liabilities" on the consolidated balance sheets. |
| |
2 | Incremental collateral requirements were based on potential changes in SCE's forward positions as of December 31, 2016 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level. |
Regulatory Balancing Accounts
SCE's cash flows are affected by regulatory balancing accounts over- or under-collections. Over- and under-collections 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 account. Under- or over-collections in these balancing accounts impact cash flows and can change rapidly. Over- and under-collections accrue interest based on a three-month commercial paper rate published by the Federal Reserve.
As of December 31, 2016, SCE had regulatory balancing account net overcollections of $1.7 billion, primarily consisting of overcollections related to the base rate revenue account and public purpose-related and energy efficiency program costs. Overcollections related to the base rate revenue account are expected to decrease as refunds are provided to customers during 2017. Overcollections related to public purpose-related programs are expected to decrease as costs are incurred to fund programs established by the CPUC. See "Notes to Consolidated Financial Statements—Note 10. Regulatory Assets and Liabilities" for further information.
Edison International Parent and Other
Edison International Parent and Other's liquidity and its ability to pay operating expenses and pay dividends to common shareholders are dependent on dividends from SCE, realization of tax benefits and access to bank and capital markets. Edison International may also finance working capital requirements, payment of obligations and capital investments, including capital contributions to subsidiaries to fund new businesses, with commercial paper or other borrowings, subject to availability in the capital markets.
At December 31, 2016, Edison International Parent had $712 million available under its $1.25 billion multi-year revolving credit facility. For further details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
The debt covenant in Edison International Parent's credit facility requires a consolidated debt to total capitalization ratio as defined in the credit agreement of less than or equal to 0.65 to 1. At December 31, 2016, Edison International Parent's consolidated debt to total capitalization ratio was 0.47 to 1.
At December 31, 2016, Edison International Parent was in compliance with all financial covenants that affect access to capital.
Net Operating Loss and Tax Credit Carryforwards
Edison International has approximately $1,152 million of net operating loss and tax credit carryforwards at December 31, 2016 (excluding $176 million of unrecognized tax benefits and $242 million of Capistrano Wind net operating loss and tax credit carryforwards) which are available to offset future consolidated taxable income or tax liabilities (see Note 7 for further information on taxes payable to Capistrano Wind). In December 2015, the PATH Act of 2015 extended 50% bonus depreciation for qualifying property retroactive to January 1, 2015 and through 2017 and provided for 40% bonus depreciation in 2018 and 30% in 2019. As a result, realization of these tax benefits has been deferred (currently forecasted to be realized through 2021). The timing of realization of these tax benefits may be further delayed in the event of other changes in tax regulations and the value of the net operating loss carryforwards could be permanently reduced if tax reform decreases the corporate tax rate.
Edison Energy Group Capital Expenditures
Forecasted capital expenditures for Edison Energy Group's commercial solar activities are estimated to be $114 million in 2017. Edison Energy Group expects to finance a majority of these expenditures through project debt and tax equity financings. For further information, see "Notes to Consolidated Financial Statements—Note 9. Investments."
Historical Cash Flows
SCE
|
| | | | | | | | | | | |
(in millions) | 2016 | | 2015 | | 2014 |
Net cash provided by operating activities | $ | 3,523 |
| | $ | 4,624 |
| | $ | 3,660 |
|
Net cash (used in) provided by financing activities | (219 | ) | | (812 | ) | | 181 |
|
Net cash used in investing activities | (3,291 | ) | | (3,824 | ) | | (3,857 | ) |
Net increase (decrease) in cash and cash equivalents | $ | 13 |
| | $ | (12 | ) | | $ | (16 | ) |
Net Cash Provided by Operating Activities
The following table summarizes major categories of net cash provided by operating activities as provided in more detail in SCE's consolidated statements of cash flows for 2016, 2015 and 2014.
|
| | | | | | | | | | | | | | | | |
| Years ended December 31, | | Change in cash flows |
(in millions) | 2016 | 2015 | 2014 | | 2016/2015 | 2015/2014 |
Net income | $ | 1,499 |
| $ | 1,111 |
| $ | 1,565 |
| |
| |
Non cash items1 | 2,108 |
| 2,231 |
| 2,381 |
| | | |
Subtotal | $ | 3,607 |
| $ | 3,342 |
| $ | 3,946 |
| | $ | 265 |
| $ | (604 | ) |
Changes in cash flow resulting from working capital2 | 236 |
| 16 |
| 79 |
| | 220 |
| (63 | ) |
Derivative assets and liabilities, net | 13 |
| 45 |
| (40 | ) | | (32 | ) | 85 |
|
Regulatory assets and liabilities, net | (292 | ) | 1,729 |
| (358 | ) | | (2,021 | ) | 2,087 |
|
Other noncurrent assets and liabilities, net3 | (41 | ) | (508 | ) | 33 |
| | 467 |
| (541 | ) |
Net cash provided by operating activities | $ | 3,523 |
| $ | 4,624 |
| $ | 3,660 |
| | $ | (1,101 | ) | $ | 964 |
|
| |
1 | Non cash items include depreciation, decommissioning and amortization, allowance for equity during construction, impairment and other charges, deferred income taxes and investment tax credits and other. |
| |
2 | Changes in working capital items include receivables, inventory, accounts payable, prepaid and accrued taxes, and other current assets and liabilities. |
| |
3 | Includes the nuclear decommissioning trusts. |
Net cash provided by operating activities was impacted by the following:
Net income and noncash items increased in 2016 by $265 million from 2015 and decreased in 2015 by $604 million from 2014. The increase in 2016 was primarily due to higher authorized revenue in 2016 from the escalation mechanism set forth in the 2015 GRC decision. The decrease in 2015 was primarily due to the implementation of the 2015 GRC decision. The factors that impacted these items are discussed under "Results of Operations—SCE—Earning Activities."
Net cash for working capital was $236 million, $16 million and $79 million in 2016, 2015 and 2014, respectively. The net cash for 2016 and 2015 was primarily related to timing of disbursements ($45 million in 2016 and $120 million in 2015) and timing of receipts from customers ($230 million in 2016 and $70 million in 2015). In addition, SCE had net tax payments of $78 million in 2016 and $144 million in 2015. The net cash in 2014 was primarily related to net tax refunds of $88 million due to net operating loss carrybacks to periods that SCE previously had taxable income.
Net cash provided by regulatory assets and liabilities, including changes in over (under) collections of balancing accounts, was $(292) million, $1.7 billion and $(358) million in 2016, 2015 and 2014, 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:
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. |
2015
| |
• | Higher cash due to a decrease in ERRA undercollections of $1.5 billion in 2015 primarily due to lower power and gas prices experienced in 2015, the 2015 application of 2013 and 2014 nuclear decommissioning costs refunds against ERRA undercollections and the NEIL settlement proceeds from insurance claims arising out of the failures of the San Onofre replacement steam generators. In January 2015, SCE reclassified the regulatory liability for generator settlements to ERRA to refund customers as required by the CPUC. |
| |
• | During 2015, BRRBA overcollections increased by $314 million primarily due to revenue previously collected from customers that was expected to be refunded as part of the 2015 GRC decision. |
| |
• | Overcollections for the public purpose and energy efficiency programs decreased by $191 million in 2015 primarily due to higher spending for these programs. The decrease was partially offset by an increase in funding of the new system generation program for 2015. |
| |
• | The 2015 GRC Decision established a tax accounting memorandum account (referred to as "TAMA"). As a result of this memorandum account, together with a balancing account for pole loading expenditures, any differences between the forecasted tax repair deductions and actual tax repair deductions will be adjusted through customer rates. At December 31, 2015, SCE had a regulatory liability of $248 million related to these accounts (impact of TAMA is offset in non-cash items above). |
2014
| |
• | During 2014, BRRBA overcollections decreased by $242 million primarily due to refunds to customers of approximately $150 million, related to the sale of Four Corners, an electric generating facility in which SCE held a 48% ownership interest, in December 2013. |
| |
• | Overcollections for the public purpose and energy efficiency programs decreased by $278 million in 2014, respectively, primarily due to higher spending for these programs. The decrease was partially offset by an increase in funding of the new system generation program for 2014. |
| |
• | During 2014, ERRA undercollections increased by $23 million primarily due to the amount and price of power and fuel being higher than forecasted. The increase was partially offset by a $540 million reclassification from regulatory liabilities to ERRA for collection of GRC revenue in excess of cost of service related to San Onofre consistent with its advice filing in November 2014. |
Cash flows (used in) provided by other noncurrent assets and liabilities were $(41) million, $(508) million and $33 million in 2016, 2015 and 2014, respectively. Major factors affecting cash flow related to noncurrent assets and liabilities were activities related to SCE's nuclear decommissioning trusts (principally related to the payment of decommissioning costs). Decommissioning costs of San Onofre were approximately $168 million and $216 million in 2016 and 2015, respectively (such costs were recorded as a reduction of SCE's asset retirement obligation).
Net Cash (Used in) Provided by Financing Activities
The following table summarizes cash provided by financing activities for 2016, 2015 and 2014. Issuances of debt and preference stock are discussed in "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "—Note 12. Preferred and Preference Stock of Utility."
|
| | | | | | | | | | | |
(in millions) | 2016 | | 2015 | | 2014 |
Issuances of first and refunding mortgage bonds, net | $ | — |
| | $ | 1,287 |
| | $ | 498 |
|
Issuances of pollution control bonds, net and other | — |
| | 126 |
| | — |
|
Long-term debt matured or repurchased | (217 | ) | | (761 | ) | | (607 | ) |
Short-term debt financing, net | 719 |
| | (619 | ) | | 490 |
|
Issuances of preference stock, net | 294 |
| | 319 |
| | 269 |
|
Payments of common stock dividends to Edison International | (701 | ) | | (758 | ) | | (378 | ) |
Redemptions of preference stock | (125 | ) | | (325 | ) | | — |
|
Payments of preferred and preference stock dividends | (123 | ) | | (116 | ) | | (111 | ) |
Other | (66 | ) | | 35 |
| | 20 |
|
Net cash (used in) provided by financing activities | $ | (219 | ) | | $ | (812 | ) | | $ | 181 |
|
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 $3.6 billion for 2016, $4.2 billion for 2015 and $3.9 billion for 2014, primarily related to transmission, distribution and generation investments. The decrease in capital expenditures during 2016 was primarily due to lower FERC capital spending. Net proceeds (purchases) of nuclear decommissioning trust investments were $179 million, $374 million and $(44) million for 2016, 2015 and 2014, respectively. See "Nuclear Decommissioning Trusts" below for further discussion. The 2016 net proceeds from sale of nuclear decommissioning trust investments was used to fund decommissioning costs less net earnings during the period. The 2015 net proceeds from sale of nuclear decommissioning trust investments was used to fund 2013, 2014 and a portion of 2015 decommissioning costs less net earnings during the period. The 2014 net purchase of nuclear decommissioning trust investments was due to net earnings during the period. In addition, during the third quarter of 2016, SCE received proceeds of $140 million for a loan on the cash surrender value of life insurance policies. The proceeds were used for general corporate purposes.
Nuclear Decommissioning Trusts
SCE's statement of cash flows includes activities of the Nuclear Decommissioning Trusts which are reflected in the following line items:
|
| | | | | | | | | | | |
(in millions) | 2016 | | 2015 | | 2014 |
Net cash (used in) provided by operating activities: Nuclear decommissioning trusts | $ | (179 | ) | | $ | (428 | ) | | $ | 39 |
|
Net cash flow from investing activities: Proceeds from sale of investments | 3,212 |
| | 3,506 |
| | 2,617 |
|
Purchases of investments | (3,033 | ) | | (3,132 | ) | | (2,661 | ) |
Net cash impact | $ | — |
| | $ | (54 | ) | | $ | (5 | ) |
Net cash (used in) provided by operating activities of the nuclear decommissioning trusts relate to interest and dividends less administrative expenses, taxes and decommissioning costs. See "Notes to Consolidated Financial Statements—Note 9. Investments" for further information. Such activities represent the source (use) of the funds for investing activities. The net cash impact represents the contributions made by SCE to the nuclear decommissioning trusts. During 2015, SCE made a contribution of $54 million to the non-qualified decommissioning trust related to tax benefits received and pursuant to a CPUC decision related to decommissioning costs for San Onofre Unit 1.
In future periods, decommissioning costs of San Onofre will increase significantly. Beginning in March 2016, 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 9. Investments" for further information.
Edison International Parent and Other
The table below sets forth condensed historical cash flow from operations for Edison International Parent and Other. |
| | | | | | | | | | | |
(in millions) | 2016 | | 2015 | | 2014 |
Net cash used in operating activities | $ | (267 | ) | | $ | (115 | ) | | $ | (412 | ) |
Net cash provided by financing activities | 314 |
| | 224 |
| | 464 |
|
Net cash used in investing activities | (125 | ) | | (68 | ) | | (50 | ) |
Net (decrease) increase in cash and cash equivalents | $ | (78 | ) | | $ | 41 |
| | $ | 2 |
|
Net Cash Used in Operating Activities
Net cash used in operating activities increased in 2016 by $152 million from 2015 and decreased in 2015 by $297 million from 2014 due to:
| |
• | $214 million, $204 million and $225 million of cash payments made to the Reorganization Trust in September 2016, September 2015 and April 2014, respectively, related to the EME Settlement Agreement. See "Notes to Consolidated Financial Statements—Note 15. Discontinued Operations—EME Chapter 11 Bankruptcy" for further information. |
| |
• | $143 million receipt of intercompany tax-allocation payments in 2015 and a $189 million deposit made with the IRS in 2014 related to open tax years 2003 through 2006. |
| |
• | $21 million outflow in June 2016 related to the buy-out of an earn-out provision with the former shareholders of a company acquired by Edison Energy in 2015. See "Results of Operations—Edison International Parent and Other—Loss from Continuing Operations" for further information. |
| |
• | $32 million cash outflow from operating activities in 2016, compared to $54 million cash inflow in 2015 and $2 million cash outflow in 2014, due to timing of payments and receipts relating to interest and operating costs. |
Net Cash Provided by Financing Activities
Net cash provided by financing activities were as follows: |
| | | | | | | | | | | | |
(in millions) | | 2016 | | 2015 | | 2014 |
Dividends paid to Edison International common shareholders | | $ | (626 | ) | | $ | (544 | ) | | $ | (463 | ) |
Dividends received from SCE | | 701 |
| | 758 |
| | 378 |
|
Payment for stock-based compensation | | (110 | ) | | (119 | ) | | (106 | ) |
Receipt from stock option exercises | | 59 |
| | 67 |
| | 66 |
|
Long-term debt issuance, net | | 397 |
| | 7 |
| | (4 | ) |
Short-term debt financing, net | | (108 | ) | | 47 |
| | 589 |
|
Other | | 1 |
| | 8 |
| | 4 |
|
Net cash provided by financing activities | | $ | 314 |
| | $ | 224 |
| | $ | 464 |
|
Net Cash Used in Investing Activities
Net cash used in investing activities relates to Edison Energy Group's capital expenditures primarily for commercial solar installations ($101 million in 2016, $15 million in 2015 and $49 million in 2014). In addition, the cash outflow in 2015 was due to the acquisitions of three companies for approximately $100 million to support Edison Energy Group's commercial and industrial services growth strategy. See "Notes to Consolidated Financial Statements—Note 9. Investments" for further information.
Contractual Obligations and Contingencies
Contractual Obligations
Edison International Parent and Other and SCE's contractual obligations as of December 31, 2016, for the years 2017 through 2021 and thereafter are estimated below.
|
| | | | | | | | | | | | | | | | | | | |
(in millions) | Total | | Less than 1 year | | 1 to 3 years | | 3 to 5 years | | More than 5 years |
SCE: | | | | | | | | | |
Long-term debt maturities and interest1 | $ | 18,801 |
| | $ | 1,044 |
| | $ | 1,442 |
| | $ | 1,509 |
| | $ | 14,806 |
|
Power purchase agreements:2 | | | | | | | | | |
Renewable energy contracts | 31,199 |
| | 1,516 |
| | 3,310 |
| | 3,562 |
| | 22,811 |
|
Qualifying facility contracts | 530 |
| | 187 |
| | 235 |
| | 55 |
| | 53 |
|
Other power purchase agreements | 4,039 |
| | 769 |
| | 1,120 |
| | 892 |
| | 1,258 |
|
Other operating lease obligations3 | 443 |
| | 52 |
| | 83 |
| | 50 |
| | 258 |
|
Purchase obligations:4 | | | | | | | | | |
Other contractual obligations | 1,211 |
| | 156 |
| | 244 |
| | 180 |
| | 631 |
|
Total SCE5,6,7 | 56,223 |
| | 3,724 |
| | 6,434 |
| | 6,248 |
| | 39,817 |
|
Edison International Parent and Other: | | | | | | | | | |
Long-term debt maturities and interest1 | 925 |
| | 426 |
| | 32 |
| | 28 |
| | 439 |
|
Total Edison International Parent and Other5 | 925 |
| | 426 |
| | 32 |
| | 28 |
| | 439 |
|
Total Edison International6,7 | $ | 57,148 |
| | $ | 4,150 |
| | $ | 6,466 |
| | $ | 6,276 |
| | $ | 40,256 |
|
| |
1 | For additional details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Amount includes interest payments totaling $8.36 billion and $93 million over applicable period of the debt for SCE and Edison International Parent and Other, respectively. |
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2 | Certain power purchase agreements entered into with independent power producers are treated as operating or capital leases. For further discussion, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies." |
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3 | At December 31, 2016, 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 11. Commitments and Contingencies." |
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4 | For additional details, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies." At December 31, 2016, other commitments were primarily related to maintaining reliability and expanding SCE's transmission and distribution system and capacity reduction contracts. |
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5 | At December 31, 2016, Edison International Parent and Other and SCE had estimated contributions to the pension and PBOP plans. SCE estimated contributions are $106 million, $106 million, $115 million, $157 million and $160 million in 2017, 2018, 2019, 2020 and 2021, respectively, which are excluded from the table above. Edison International Parent and Other estimated contributions are $51 million, $18 million, $28 million, $26 million and $26 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 8. Compensation and Benefit Plans" for further information. |
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6 | At December 31, 2016, Edison International and SCE had a total net liability recorded for uncertain tax positions of $471 million and $371 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. |
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7 | The contractual obligations table does not include derivative obligations and asset retirement obligations, which are discussed in "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments," and "—Note 1. Summary of Significant Accounting Policies" and "—Note 9. Investments," respectively. |
Contingencies
SCE has contingencies related to San Onofre Related Matters, Long Beach Service Interruptions, Nuclear Insurance, Wildfire Insurance and Spent Nuclear Fuel, which are discussed in "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies."
Environmental Remediation
For a discussion of SCE's environmental remediation liabilities, see "Notes to Consolidated Financial Statements—Note 11. Commitments and 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 I, Trust II, Trust III, Trust IV and Trust V that issued $475 million (aggregate liquidation preference) of 5.625%, $400 million (aggregate liquidation preference) of 5.10%, $275 million (aggregate liquidation preference) of 5.75%, $325 million (aggregate liquidation preference) of 5.375% and $300 million (aggregate liquidation preference) of 5.45%, trust securities, respectively, to the public, see "Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities."
Environmental Developments
For a discussion of environmental developments, see "Business—Environmental Regulation of Edison International and Subsidiaries."
MARKET RISK EXPOSURES
Edison International's and SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Derivative instruments are used to manage market risks including market risks of SCE's customers. For a further discussion of market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments" and "—Note 4. Fair Value Measurements."
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 2017, 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 as of December 31, 2016, if the market interest rates were changed while leaving all other assumptions the same:
|
| | | | | | | | | | | | | | | |
(in millions) | Carrying Value | | Fair Value | | 10% Increase | | 10% Decrease |
Edison International | $ | 11,156 |
| | $ | 12,368 |
| | $ | 11,892 |
| | $ | 12,876 |
|
SCE | 10,333 |
| | 11,539 |
| | 11,070 |
| | 12,040 |
|
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, tolling arrangements, and congestion revenue rights ("CRRs"). The transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans.
Fair Value of Derivative Instruments
The fair value of derivative instruments is included in the consolidated balance sheets unless subject to an exception under the applicable accounting guidance. Realized gains and losses from derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, accordingly, changes in SCE's fair value have no impact on earnings. SCE does not use hedge accounting for these transactions due to this regulatory accounting treatment. For further discussion on fair value measurements and the fair value hierarchy, see "Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."
The fair value of outstanding derivative instruments used to mitigate exposure to commodity price risk was a net liability of $1.1 billion and $1.2 billion at December 31, 2016 and 2015, respectively. The following table summarizes the increase or decrease to the fair values of the net liability of derivative instruments included in the consolidated balance sheets as of December 31, 2016, if the electricity prices or gas prices were changed while leaving all other assumptions constant:
|
| | | |
(in millions) | December 31, 2016 |
|
Increase in electricity prices by 10% | $ | 112 |
|
Decrease in electricity prices by 10% | (92 | ) |
Increase in gas prices by 10% | (36 | ) |
Decrease in gas prices by 10% | 43 |
|
Credit Risk
For information related to credit risks, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments."
Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements.
As of December 31, 2016, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:
|
| | | | | | | | | | | |
| December 31, 2016 |
(in millions) | Exposure2 | | Collateral | | Net Exposure |
S&P Credit Rating1 | | | | | |
A or higher | $ | 74 |
| | $ | (3 | ) | | $ | 71 |
|
| |
1 | SCE assigns a credit rating based on the lower of a counterparty's S&P, Fitch or Moody's Investors Service rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the three credit ratings. |
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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 certain penalties or grant certain 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 November 2014, the CPUC approved the San Onofre OII Settlement Agreement, which resolved the CPUC's investigation regarding the steam generator replacement project at San Onofre and the related outages and subsequent shutdown of San Onofre. In a December 2016 joint ruling, the Assigned Commissioner and the Assigned ALJ expressed concerns about the extent to which the failure to timely report ex parte communications had impacted the settlement negotiations and directed SCE to meet and confer with the other parties in the OII to consider changing the terms of the San Onofre OII Settlement Agreement.
In November 2015, SCE received the 2015 GRC decision. As part of this decision, the CPUC adopted a rate base offset associated with forecasted tax repair deductions during 2012 – 2014. The 2015 rate base offset is $324 million and amortizes on a straight line basis over 27 years. As a result of the rate base offset included in the final decision, SCE recorded an after tax charge of $382 million during the fourth quarter of 2015 to write down the regulatory assets previously recorded for recovery of deferred income taxes related to 2012 – 2014 incremental tax repair deductions.
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's judgment that the San Onofre Regulatory Asset recorded at December 31, 2016 is probable, though not certain, of recovery is based on SCE's knowledge of the facts and judgment in applying the relevant regulatory principles to the issue. Such judgment is subject to uncertainty, and regulatory principles and precedents are not necessarily binding and are capable of interpretation. SCE has recorded a regulatory asset to reflect the expected recoveries under the San Onofre OII Settlement Agreement. At
December 31, 2016, $857 million remains to be collected.
Effect if Different Assumptions Used. Significant management judgment is required to evaluate the anticipated recovery of regulatory assets, 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 and liabilities would have to be written off against current period earnings. At December 31, 2016, the consolidated balance sheets included regulatory assets of $7.8 billion and regulatory liabilities of $6.5 billion. If different judgments were reached on recovery of costs and timing of income recognition, SCE's earnings may vary from the amounts reported.
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. The liability to decommission SCE's nuclear power facilities is based on decommissioning studies performed in 2013 for Palo Verde and in 2014 for San Onofre Units 1, 2 and 3. See "Liquidity and Capital Resources—SCE—Decommissioning of San Onofre" for further discussion of the plans for decommissioning of San Onofre. SCE estimates that it will spend approximately $6.3 billion through 2079 to decommission its nuclear facilities. San Onofre Units 1, 2 and 3 decommissioning cost estimates are updated in each Nuclear Decommissioning Triennial Proceeding. Palo Verde decommissioning cost estimates are updated every three years by the operating agent, Arizona Public Services.
The current ARO estimates for San Onofre and Palo Verde are based on the assumptions from these decommissioning studies:
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• | 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. |
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• | 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 1.7% to 7.5% (depending on the cost element) annually. |
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• | 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. San Onofre Unit 1 started decommissioning in 1998 and Units 2 and 3 began in 2013. Cost estimates for San Onofre Units are currently based on completion of decommissioning activities by 2052. |
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• | Spent Fuel Dry Storage Costs. Cost estimates are based on an assumption that the DOE will begin to take spent fuel in 2024, and will remove the last spent fuel from the San Onofre and Palo Verde sites by 2051 and 2075, respectively. Costs for spent fuel monitoring are included until 2051 and 2075, respectively. |
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• | 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. |
Effect if Different Assumptions Used. The ARO for decommissioning SCE's nuclear facilities was $2.5 billion as of December 31, 2016, based on decommissioning studies performed in 2013 for Palo Verde and in 2014 for San Onofre Units 1, 2 and 3. 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 ARO for decommissioning San Onofre Units 2 & 3 is expected to be updated after onboarding the decommissioning general contractor and the subsequent development of a new decommissioning cost estimate during 2017.
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, 2016 |
Uniform increase in escalation rate of 1 percentage point | $ | 481 |
|
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 ("PBOP(s)")
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 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, 2016, Edison International's and SCE's pension plans had a $4.3 billion and $3.8 billion benefit obligation, respectively, and total 2016 expense for these plans was $101 million and $93 million, respectively. As of December 31, 2016, the benefit obligation for both Edison International's and SCE's PBOP plans were $2.3 billion, and total 2016 expense for Edison International's and SCE's plans was $20 million and $19 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, 2016, this cumulative difference amounted to a regulatory asset of $95 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 2016:
|
| | | | |
(in millions) | Pension Plans | Postretirement Benefits Other than Pensions |
Discount rate1 | 4.18 | % | 4.55 | % |
Expected long-term return on plan assets2 | 7.00 | % | 5.60 | % |
Assumed health care cost trend rates3 | * |
| 7.50 | % |
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* | 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, matching the timing and amount of expected benefit payments. The AON-Hewitt yield curve is considered in determining the discount rate. |
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2 | To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns on plan assets. A portion of PBOP trusts asset returns are subject to taxation, so the 5.6% 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 8.5%, 9.7% and 5.8% for the one-year, five-year and ten-year periods ended December 31, 2016, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 7.0%, 9.5% and 5.0% 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 2022 and beyond. |
As of December 31, 2016, Edison International and SCE had unrecognized pension costs of $666 million and $598 million, and unrecognized PBOP costs of $140 million and $136 million, respectively. The unrecognized pension and PBOP costs 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, $479 million of SCE's pension costs and $33 million of SCE's PBOP costs are recorded as regulatory assets and is expected to be recovered 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 | $ | (422 | ) | | $ | 513 |
| | $ | (365 | ) | | $ | 444 |
|
Change to accumulated benefit obligation for PBOP | (319 | ) | | 372 |
| | (318 | ) | | 370 |
|
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 $31 million and $29 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 $20 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 | $ | 244 |
| | $ | (200 | ) | | $ | 243 |
| | $ | (199 | ) |
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 reserve 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 11. Commitments and Contingencies."
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 depends on SCE's ability to pay dividends and tax allocation payments to Edison International, monetization of tax benefits retained by EME, ability to borrow funds, and access to capital markets.
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 its ability to make upstream distributions. Prior to paying dividends to Edison International, SCE has financial and regulatory obligations that must be satisfied, including, among others, debt service and preferred stock dividends. In addition, 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. SCE may also owe tax-allocation payments to Edison International under applicable tax-allocation agreements. Access to capital markets may be impacted by economic conditions that have an adverse effect on Edison International's liquidity. See "Risks Relating to Southern California Edison Company" below for further discussion.
The Edison International consolidated tax group retains significant net operating loss and tax credit carryforwards. Realization of such tax benefits may be delayed or permanently reduced by future tax legislation that extends bonus depreciation or reduces the current corporate tax rate.
Edison International's business activities are concentrated in one industry and in one region.
Edison International business activities are concentrated in the electricity industry. Its principal subsidiary, SCE, serves customers only in southern and central California. Although Edison International, through Edison Energy Group, is developing competitive businesses that are diversified geographically, these businesses are not material. As a result, Edison International's future performance may be affected by events and economic factors unique to California or by regional regulation or legislation.
Edison International is developing businesses held by Edison Energy Group that may not be successful.
Edison International, through Edison Energy Group, is developing businesses to capitalize on changes in the electricity industry. Edison International intends to invest in companies to develop the capabilities of the Edison Energy Group entities but there can be no assurance that these entities will be profitable.
RISKS RELATING TO SOUTHERN CALIFORNIA EDISON COMPANY
Regulatory Risks
SCE is subject to extensive regulation and the risk of adverse regulatory 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. 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 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 penalties or disallowances on SCE, SCE's 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.
In September 2016, the California Governor signed into law several CPUC reform bills that establish rules governing, among other subjects, communications between the CPUC officials, staff and the regulated utilities. Changes to the rules 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.
In addition, existing regulations may be revised or reinterpreted 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 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, the recovery of the Tehachapi transmission project costs are subject to FERC approval and the public need for the project is reviewed by the CPUC. SCE filed a petition for modification with the CPUC in January 2017 to update the cost estimate for all elements of segments 4-11 to $2.7 billion (2016 dollars) from $2.0 billion (2016 dollars) of CPUC-approved cost findings. For further information, see "Liquidity and Capital Resources—SCE—Capital Investment Plan—Tehachapi" in the MD&A.
Changes in laws and regulations or changes in the political and regulatory environment also may have an adverse effect on the SCE's ability to timely recover its costs and earn its authorized rate of return. In addition, SCE may be required to incur costs to comply with new state laws or to implement new state policies before SCE is assured of cost recovery.
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—Regulatory Proceedings—2018 General Rate Case" and "—FERC Formula Rates" in the MD&A.
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. For instance, natural gas prices have increased due to the closure of the SoCalGas underground gas storage facility in Aliso Canyon, California. 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.
Financing Risks
As a capital 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. 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
The electricity industry is undergoing change, including increased competition, technological advancements, and political and regulatory developments
California utilities are experiencing increasing deployment by customers and third parties of DERs, such as solar generation, energy storage, energy efficiency and demand response technologies. This growth 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. To this end, the CPUC is conducting proceedings to: evaluate 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 these proceedings is unknown. These changes could materially affect SCE's business model and its financial condition and results of operations. For more information, see "Management Overview—Capital Program—Distribution Grid Development" in the MD&A.
Customer-owned generation and community choice aggregators each reduce the amount of electricity 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, customers in California that generate their own power do not currently pay all transmission and distribution charges and non-bypassable charges, subject to limitations, which result in increased utility rates for those customers who do not own their generation. Such increases influence the public discussion regarding changes in the electric utility business model.
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."
Operating Risks
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.
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, wildfires and earthquakes, can disrupt the generation and transmission of electricity, and can seriously damage the infrastructure necessary to deliver power to SCE's customers. These events can lead to lost revenues and increased expenses, including higher maintenance and repair costs. They can also result in regulatory penalties and disallowances, particularly if SCE encounters difficulties in restoring power to its customers on a timely basis. 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.
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. 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 $50,000 per violation per day, pursuant to the CPUC's jurisdiction for violations of safety rules found in statutes, regulations, and the CPUC's General Orders. Such penalties and liabilities could be significant and materially affect SCE's liquidity and results of operations.
There are inherent risks associated with owning and decommissioning nuclear power generating facilities and obtaining cost reimbursement, including, among other things, costs exceeding estimates, execution risks, potential harmful effects on the environment and human health and the danger 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 expects to fund decommissioning costs with assets that are currently held in nuclear decommissioning trusts. SCE believes that the nuclear decommissioning trusts' assets will be sufficient to pay the estimated costs of decommissioning without further contributions but the costs ultimately incurred could exceed the current estimates. 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.
Despite the fact that 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 $13.4 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available of $450 million per site. If nuclear incident liability claims were to exceed $450 million, the remaining amount would be made up from contributions of approximately $13.0 billion made by all of the nuclear facility owners in the U.S., up to an aggregate total of $13.4 billion. There is no assurance that the CPUC would allow SCE to recover the required contribution made in the case of one or more nuclear incident claims that exceeded $450 million. If this public liability limit of $13.4 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 11. Commitments and Contingencies—Contingencies—Nuclear Insurance."
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 from SCE's ordinary operations. Edison International, SCE or its contractors may experience coverage reductions and/or increased wildfire insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's or its contractors' insurance coverage. Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates. A loss which is not fully insured or cannot be recovered in customer 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 11. Commitments and Contingencies—Contingencies—Wildfire Insurance."
Cybersecurity and Physical Security Risks
SCE's systems and network infrastructure may be vulnerable to physical and cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality.
Regulators, such as the NERC, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, have noted 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 becoming increasingly sophisticated and dynamic. As SCE moves from an analog to a digital electric grid, new cyber security risks may arise. An example of such new risks is the installation of "smart" meters in SCE's service territory. This technology may represent a new route for attacks on SCE's information systems. SCE's operations require the continuous availability of critical information technology systems and network infrastructure. 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 cyber security breach. Although SCE actively monitors developments in this area and is involved in various industry groups and government initiatives, no security measures can completely shield such 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 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, financial loss to SCE or to its customers, loss of confidence in SCE's security measures, customer dissatisfaction, and significant litigation 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.
Environmental Risks
SCE is subject to extensive environmental regulations that may involve significant and increasing costs and materially affect SCE.
SCE is subject to extensive environmental regulations and permitting requirements that involve significant and increasing costs and substantial uncertainty. SCE devotes significant resources to environmental monitoring, pollution control equipment, mitigation projects, and emission allowances to comply with existing and anticipated environmental regulatory requirements. Environmental regulations and permitting requirements also affect the cost and timing of transmission and distribution projects. At the state level, the current trend is toward more stringent standards, stricter regulation, higher reductions of GHG emissions, and more expansive application of environmental regulations. The adoption of laws and regulations to implement greenhouse gas controls could materially affect operations of power plants, which could in turn impact electricity markets and SCE's customer rates. SCE may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or with respect to offsite waste disposal sites that have been used in its operations. Current and future California laws and regulations also increase the required amount of energy that must be procured from renewable resources. See "Business—Environmental Regulation of Edison International and Subsidiaries" for further discussion of environmental regulations under which SCE operates.
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 Firm
To the Board of Directors and
Shareholders of Edison International
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in equity and cash flows present fairly, in all material respects, the financial position of Edison International and its subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedules, 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 Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.
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.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 21, 2017
Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Shareholders of Southern California Edison Company
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in equity and cash flows present fairly, in all material respects, the financial position of Southern California Edison Company and its subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 21, 2017
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| | | | | | | | | | | |
Consolidated Statements of Income | Edison International | |
|
| | |
| Years ended December 31, |
(in millions, except per-share amounts) | 2016 | | 2015 | | 2014 |
Total operating revenue | $ | 11,869 |
| | $ | 11,524 |
| | $ | 13,413 |
|
Purchased power and fuel | 4,527 |
| | 4,266 |
| | 5,593 |
|
Operation and maintenance | 2,868 |
| | 2,990 |
| | 3,149 |
|
Depreciation, decommissioning and amortization | 2,007 |
| | 1,919 |
| | 1,720 |
|
Property and other taxes | 354 |
| | 336 |
| | 322 |
|
Impairment and other charges | 21 |
| | 5 |
| | 157 |
|
Total operating expenses | 9,777 |
| | 9,516 |
| | 10,941 |
|
Operating income | 2,092 |
| | 2,008 |
| | 2,472 |
|
Interest and other income | 123 |
| | 174 |
| | 147 |
|
Interest expense | (581 | ) | | (555 | ) | | (560 | ) |
Other expenses | (44 | ) | | (59 | ) | | (80 | ) |
Income from continuing operations before income taxes | 1,590 |
| | 1,568 |
| | 1,979 |
|
Income tax expense | 177 |
| | 486 |
| | 443 |
|
Income from continuing operations | 1,413 |
| | 1,082 |
| | 1,536 |
|
Income from discontinued operations, net of tax | 12 |
| | 35 |
| | 185 |
|
Net income | 1,425 |
| | 1,117 |
| | 1,721 |
|
Preferred and preference stock dividend requirements of utility | 123 |
| | 113 |
| | 112 |
|
Other noncontrolling interests | (9 | ) | | (16 | ) | | (3 | ) |
Net income attributable to Edison International common shareholders | $ | 1,311 |
| | $ | 1,020 |
| | $ | 1,612 |
|
Amounts attributable to Edison International common shareholders: | | | | | |
Income from continuing operations, net of tax | $ | 1,299 |
| | $ | 985 |
| | $ | 1,427 |
|
Income from discontinued operations, net of tax | 12 |
| | 35 |
| | 185 |
|
Net income attributable to Edison International common shareholders | $ | 1,311 |
| | $ | 1,020 |
| | $ | 1,612 |
|
Basic earnings per common share attributable to Edison International common shareholders: | | | | | |
Weighted-average shares of common stock outstanding | 326 |
| | 326 |
| | 326 |
|
Continuing operations | $ | 3.99 |
| | $ | 3.02 |
| | $ | 4.38 |
|
Discontinued operations | 0.03 |
| | 0.11 |
| | 0.57 |
|
Total | $ | 4.02 |
| | $ | 3.13 |
| | $ | 4.95 |
|
Diluted earnings per common share attributable to Edison International common shareholders: | | | | | |
Weighted-average shares of common stock outstanding, including effect of dilutive securities | 330 |
| | 329 |
| | 329 |
|
Continuing operations | $ | 3.94 |
| | $ | 2.99 |
| | $ | 4.33 |
|
Discontinued operations | 0.03 |
| | 0.11 |
| | 0.56 |
|
Total | $ | 3.97 |
| | $ | 3.10 |
| | $ | 4.89 |
|
Dividends declared per common share | $ | 1.9825 |
| | $ | 1.7325 |
| | $ | 1.4825 |
|
The accompanying notes are an integral part of these consolidated financial statements.
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Consolidated Statements of Comprehensive Income | |