10-K



 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2015
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                        to
Commission
File Number
 
Exact Name of Registrant
as specified in its charter
 
State or Other Jurisdiction of
Incorporation or Organization
 
IRS Employer
Identification Number
1-9936
 
EDISON INTERNATIONAL
 
California
 
95-4137452
1-2313
 
SOUTHERN CALIFORNIA EDISON COMPANY
 
California
 
95-1240335
EDISON INTERNATIONAL
 
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue
(P.O. Box 976)
Rosemead, California 91770
(Address of principal executive offices)
 
2244 Walnut Grove Avenue
(P.O. Box 800)
Rosemead, California 91770
(Address of principal executive offices)
(626) 302-2222
(Registrant's telephone number, including area code)
 
(626) 302-1212
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Edison International: Common Stock, no par value
 
NYSE LLC
Southern California Edison Company: Cumulative Preferred Stock
 
NYSE 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
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
 
 
 
 
 
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, 2015, the last business day of the most recently completed second fiscal quarter:
Edison International    Approximately $18.1 billion    Southern California Edison Company    Wholly owned by Edison International
Common Stock outstanding as of February 19, 2016:
 
 
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 2016 Annual Meeting of Shareholders have been incorporated by reference into the parts of this report where indicated.
 
 
 
 
 
 









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


i



 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Part I, Item 1A
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Part II, Item 7A
Part II, Item 8
 
 
 
 
 
 
 
 
 
 
 
 
 


ii



 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Part II, Item 6
Part II, Item 9A
Part II, Item 9B
Part II, Item 9
Part I, Item 1
 
 
 
 
 
 
 
 
 
 
 
 
 
 


iii



 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
Part IV, Item 15
 
 
This is a combined Form 10-K separately filed by Edison International and Southern California Edison Company. Information contained herein relating to an individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.


iv



GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
Amended Plan of Reorganization
 
EME Chapter 11 Bankruptcy Plan of Reorganization as amended to incorporate the terms of the Settlement Agreement, dated February 19, 2014
AFUDC
 
allowance for funds used during construction
APS
 
Arizona Public Service Company, operator of Four Corners
ARO(s)
 
asset retirement obligation(s)
Bankruptcy Code
 
Chapter 11 of the United States Bankruptcy Code
Bankruptcy Court
 
United States Bankruptcy Court for the Northern District of Illinois, Eastern Division
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 
CAA
 
Clean Air Act
CAISO
 
California Independent System Operator
CARB
 
California Air Resources Board
Competitive Businesses
 
businesses focused on providing energy services, including distributed generation and/or storage, to commercial and industrial customers; engaging in competitive transmission opportunities; and exploring distributed water treatment and recycling.
CPUC
 
California Public Utilities Commission
CRRs
 
congestion revenue rights
DOE
 
U.S. Department of Energy
Edison Energy
 
Edison Energy, LLC, a wholly-owned subsidiary of Edison Energy Group and one of the Competitive Businesses
Edison Energy Group
 
Edison Energy Group, Inc., the holding company for the Competitive Businesses
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
EPS
 
earnings per share
ERRA
 
energy resource recovery account
FERC
 
Federal Energy Regulatory Commission
Four Corners
 
coal fueled electric generating facility located in Farmington, New Mexico in
which SCE held a 48% ownership interest
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 to be filed with the SEC in connection with Edison International's and SCE's Annual Shareholders' Meeting to be held on April 28, 2016
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
Moody's
 
Moody's Investors Service
MW
 
megawatts
MWh
 
megawatt-hours
NAAQS
 
national ambient air quality standards
NEIL
 
Nuclear Electric Insurance Limited


v



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)
PG&E
 
Pacific Gas & Electric Company
QF(s)
 
qualifying facility(ies)
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 The Utility Reform Network, the CPUC's Office of Ratepayer Advocates, 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
TURN
 
The Utility Reform Network
US EPA
 
U.S. Environmental Protection Agency
VIE(s)
 
variable interest entity(ies)



vi



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 statement that does 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 of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact Edison International and SCE, include, but are not limited to the:
ability of SCE to recover its costs in a timely manner from its customers through regulated rates, including regulatory assets related to San Onofre;
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, and delays in regulatory actions;
ability of Edison International or SCE to borrow funds and access the capital markets on reasonable terms;
possible customer bypass or departure due to technological advancements in the generation, storage, transmission, distribution and use of electricity, and supported by public policy, government regulations and incentives;
risks inherent in the construction of transmission and distribution infrastructure replacement and expansion projects, 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;
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;
risks associated with the retirement and decommissioning of nuclear generating facilities;
physical security of SCE's critical assets and personnel and the cyber security of SCE's critical information technology systems for grid control, and business and customer data;
ability of Edison International to develop its Competitive Businesses, manage new business risks, and recover and earn a return on its investment in newly developed or acquired businesses;
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;
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;
changes in the fair value of investments and other assets;
changes in interest rates and rates of inflation, including escalation rates, which may be adjusted by public utility regulators;
governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market adopted by the CAISO, WECC, NERC, and adjoining regions;
availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;
cost and availability of labor, equipment and materials;
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;
potential for penalties or disallowance for non-compliance with applicable laws and regulations;

1



cost and availability 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; and
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. Additionally, 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.

2



MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MANAGEMENT OVERVIEW
Highlights of Operating Results
Edison International is the parent holding company of SCE. 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 subsidiaries that are engaged in competitive businesses focused on providing energy services to commercial and industrial customers, including distributed resources, engaging in transmission opportunities, and exploring distributed water treatment and recycling (the "Competitive Businesses"). 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.
(in millions)
2015
 
2014
 
2015 vs 2014 Change
 
2013
Net income (loss) attributable to Edison International
 
 
 
 
 
 
 
Continuing operations
 
 
 
 
 
 
 
SCE
$
998

 
$
1,453

 
$
(455
)
 
$
900

Edison International Parent and Other
(13
)
 
(26
)
 
13

 
(21
)
Discontinued operations
35

 
185

 
(150
)
 
36

Edison International
1,020

 
1,612

 
(592
)
 
915

Less: Non-core items
 
 
 
 
 
 
 
     SCE
 
 
 
 
 
 
 
Write-down, impairment and other charges
(382
)
 
(72
)
 
(310
)
 
(365
)
    NEIL insurance recoveries
12

 

 
12

 

     Edison International Parent and Other
 
 
 
 
 
 
 
Gain on sale of Beaver Valley lease interest

 

 

 
7

Edison Capital sale of affordable housing portfolio
10

 

 
10

 

Income from allocation of losses to tax equity investor
9

 
2

 
7

 

     Discontinued operations
35

 
185

 
(150
)
 
36

Total non-core items
(316
)
 
115

 
(431
)
 
(322
)
Core earnings (losses)
 
 
 
 
 
 
 
SCE
1,368

 
1,525

 
(157
)
 
1,265

Edison International Parent and Other
(32
)
 
(28
)
 
(4
)
 
(28
)
Edison International
$
1,336

 
$
1,497

 
$
(161
)
 
$
1,237

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 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 charges related to certain tax, regulatory or legal settlements or proceedings.
SCE's 2015 core earnings decreased $157 million for the year primarily from lower CPUC-related revenue which reflects the implementation of the 2015 CPUC General Rate Case decision partially offset by an increase in FERC-related revenue from rate base growth, lower operation and maintenance and earnings on funds used during construction.

3




In addition, income tax benefits were lower in 2015. During 2015, SCE recorded $100 million of income tax benefits from revisions to liabilities for uncertain tax positions for tax years 2010 through 2012. These benefits were partially offset by changes in estimated taxes related to net operating loss carrybacks, interest and state income taxes. During 2014, SCE recorded $133 million of income tax benefits from incremental repair deductions and $29 million of income tax benefits from revisions to liabilities for uncertain tax positions.
Consolidated non-core items for 2015 and 2014 for Edison International included:
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. For further information, see "—Regulatory Proceedings—2015 General Rate Case."
Income of $20 million ($12 million after-tax) in 2015 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. For further information, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—San Onofre Related Matters."
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 represents the exit from this business activity.
Impairment and other charges of $163 million ($72 million after-tax) in 2014 related to the San Onofre OII Settlement Agreement For further information, see "—Permanent Retirement of San Onofre and San Onofre OII Settlement" and "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Impairment of Long-Lived Assets."
Income of $9 million and $2 million for 2015 and 2014, respectively, related to losses allocated to tax equity investors under the HLBV accounting method. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies." Edison International reflected in core earnings the operating results of the solar rooftop projects and their related financings, including the priority returns to tax equity investors. The losses allocated to the tax equity investor under HLBV method results in income allocated to subsidiaries of Edison International, neither of which is due to the 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 the "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."
Income from discontinued operations, net of tax, was $35 million for 2015 primarily due to income tax benefits (from revised estimates based on filing of the 2014 tax returns) and 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. 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 2014 results to 2013.
Electricity Industry Trends
The electricity industry is undergoing change, including technological advancements such as customer-owned generation and energy storage that could alter the nature of energy generation and delivery. Recent trends in the electric industry include:
leveling of demand due to slower population growth, demand side management of energy and an increase in customer-owned generation;
public policy initiatives to reduce GHG emissions and encourage competition for the sale and delivery of electricity;
increased need for infrastructure replacement and grid development to accommodate new technologies; and
technological and financing innovation that facilitate conservation, distributed energy resources, such as customer-owned generation and energy storage, and changes in electricity generation, transmission and distribution.

4




SCE is investing in and strengthening its electric grid and driving operational and service excellence to improve system safety, reliability and service while controlling costs and rates.
The electric distribution grid is an important component of California's public policy goals to support a cleaner environment. These policy goals continue to advance as California moves forward in implementing Senate Bill 350. SB 350 requires retail sellers of electricity to procure 50% of their customers' electricity requirements from renewable resources by 2030.
California policy goals also promote an increase in electric vehicle usage and investment in charging infrastructure. These goals may create opportunities for the electric grid to enable GHG emission reductions by providing the supporting infrastructure to increase adoption of customer-owned generation, electric storage, and electric vehicles but they may increase customer rates and add technical complexity and risk to the safe and reliable operation of the electric grid.
In 2015, SCE filed a Distribution Resources Plan (“DRP”) with the CPUC as part of the CPUC's initiative to address, among other issues, the increased penetration of customer-owned generation and other distributed energy resources, such as rooftop solar. For more information, see "—Capital Program—Distribution Grid Development—Distribution Resources Plan" below.
Edison International is also investing in Competitive Businesses. These include small, targeted investments in energy service companies that utilize technologies and access markets to capitalize on the changes in the electric industry. Current areas of focus are providing energy services to commercial and industrial customers, including distributed resources, engaging in competitive transmission opportunities, and exploring distributed water treatment and recycling.
Capital Program
SCE forecasts capital expenditures for 2016 – 2017 in the range of $8.0 billion to $8.3 billion. The forecast includes the level of spending authorized in the 2015 GRC decision. The low end of the range reflects a 3% reduction from forecasted levels for FERC projects using management judgment based on historical experience. Total capital expenditures (including accruals), were $3.9 billion in 2015 and $4.0 billion in 2014. SCE's year-end rate base (excluding San Onofre) was $24.6 billion at December 31, 2015 compared to $23.3 billion at December 31, 2014.
SCE's 2015 actual capital expenditures (including accruals) and the 2016 – 2017 forecast for major capital expenditures are set forth in the table below:
(in millions)
 
2015
Actual
2016
2017
2016 – 2017 Total
Transmission
 
$
613

$
704

$
1,195

$
1,899

Distribution
 
3,028

3,113

2,831

5,944

Generation
 
226

250

173

423

Total estimated capital expenditures
 
$
3,867

$
4,067

$
4,199

$
8,266

Total estimated capital expenditures for 2016 – 2017 (using the range discussed above)
 
 
$
3,980

$
4,059

$
8,039

Capital expenditures for projects under CPUC jurisdiction are recovered through the authorized revenue requirement in SCE's GRCs or through other CPUC-authorized mechanisms. Recovery for 2016 – 2017 planned expenditures for projects under FERC jurisdiction will be pursued through FERC-authorized mechanisms. SCE is scheduled to file its 2018 GRC application in September 2016, which will include a capital expenditures forecast for 2018 – 2020.
The completion of projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, community requests or protests, weather and other unforeseen conditions.

5



At December 31, 2015, SCE’s rate base authorized in the 2015 GRC and recorded rate base for FERC jurisdictional assets determined in accordance with SCE’s FERC formula rate are summarized as follows:
(in millions)
Authorized Rate Base
Authorized CPUC rate base from 2015 GRC1
$
17,552

Legacy meters
147

Additional rate base from Pole Loading and Deteriorated Poles Balancing Account2
329

Reduction in rate base from extension of bonus depreciation
(12
)
Subtotal – CPUC rate base
$
18,016

FERC rate base2 
5,307

Total rate base
$
23,323

1
Excludes rate base adjustment of $324 million. See "—Regulatory Proceedings—2015 General Rate Case" for further discussion.
2
Includes $13 million and $6 million reduction from extension of bonus depreciation for pole loading and FERC, respectively.
SCE’s forecasted rate base for 2016 and 2017 is as follows:
(in millions)
2016
 
2017
Based on total estimated capital expenditures1
$
25,131

 
$
26,810

Based on total estimated capital expenditures for 2016 – 2017 (using the range discussed above)
25,045

 
26,583

1
Refer to footnote 1 in previous table.
The forecasted rate base for 2016 and 2017 includes the net impact of extension of bonus depreciation, which reduces average rate base by $298 million and $701 million, respectively.
Distribution Grid Development
Distribution Resources Plan
On July 1, 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 GHG reduction targets, modernize the electric distribution system to accommodate two-way flows of energy associated with distributed energy resources, 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. Subject to future CPUC guidance, SCE anticipates integrating authorization for revenue to support DRP operation and maintenance and capital spending into future general rate cases, beginning with its 2018 – 2020 GRC. Capital investments for 2016 – 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 distributed energy resource adoption, and other factors.
Charge Ready Program
In January 2016, the CPUC approved SCE's $22 million Charge Ready pilot program, which will allow SCE to install infrastructure supporting approximately 1,500 electric vehicle charging stations, provide rebates to offset the cost of qualified customer-owned charging stations, and implement a supporting market education effort. SCE will work with cities, employers, apartment owners, charging equipment manufacturers and others to deploy qualified charging stations at locations where cars may be parked for four hours or more. Under the 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. The results of this pilot will help shape Phase 2 of the program, which was proposed to cost an additional $333 million over four years. SCE will file an application to obtain CPUC approval for Phase 2 after at least one year and 1,000 charging stations have been deployed.


6




Edison International Dividend Policy
In December 2015, Edison International declared a 15% increase to the annual dividend rate from $1.67 per share to $1.92 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.
Regulatory Proceedings
2015 General Rate Case
On November 5, 2015, the CPUC approved a final decision in SCE's 2015 GRC. The decision authorized a revenue requirement of $5.182 billion for 2015. The final decision authorized a ratemaking methodology that escalates capital additions by 2% for both 2016 and 2017 and allows operation and maintenance expense to be escalated for 2016 and 2017 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology adopted in the decision results in a revenue requirement of $5.391 billion for 2016 and $5.663 billion for 2017. The final decision was retroactive to January 1, 2015 and includes provisions related to tax repair deductions and for revenue adjustments discussed below.
Tax Repair Deductions and Memorandum Account
Certain capital expenditures qualify as repairs for income tax purposes and are currently deductible. In each GRC, SCE forecasts its federal and state taxes, including expected deductions for tax repairs ("tax repair deductions"). Income tax benefits from tax repair deductions are flowed through to customers in establishing the authorized revenue requirement. The effect of flow-through treatment of income taxes is to lower current customer rates but increase future customer rates for recovery of deferred income taxes. Actual tax repair deductions exceeded forecasted tax repair deductions during 2012 – 2014. As part of the final decision in SCE's 2015 GRC, the CPUC adopted a rate base offset to reduce authorized revenue in 2015 and future rate cases for income tax benefits related to 2012 – 2014 tax repair deductions which were in excess of forecast and did not flow-through to customers. The final decision included $324 million of rate base offset to SCE’s CPUC jurisdictional rate base and directed the amount to be amortized over 27 years on a straight line basis.
Previously, SCE recognized earnings and a regulatory asset of $382 million for deferred income taxes related to 2012 – 2014 tax repair deductions. As a result of the CPUC’s rate base offset, SCE wrote down this regulatory asset in full. The after-tax charge was reflected in "Income tax expense" on the consolidated statements of income. The amount of tax repair deductions the CPUC used to establish the rate base offset was based on SCE’s forecast of 2012 – 2014 tax repair deductions from the Notice of Intent filed in the 2015 GRC. The amount of tax repair deductions included in the Notice of Intent was less than the actual tax repair deductions SCE reported on its 2012 through 2014 income tax returns. In February 2016, SCE made an advice filing with the CPUC to reduce SCE’s Base Revenue Requirement Balancing Account by $234 million during 2016 through 2020 subject to the outcome of audits that may be conducted by tax authorities. SCE does not expect to record a gain or loss from this advice filing. The advice filing is subject to review and revision by the CPUC.
The 2015 GRC also established a tax accounting memorandum account (referred to as “TAMA”), which provides that additional 2015 – 2017 tax benefits or costs associated with the following events be tracked: (1) tax accounting method changes, (2) changes in tax laws and regulations impacting depreciation or tax repair deductions, (3) forecasted and actual differences in tax repair deductions, and (4) the impact, if any, of a private letter ruling related to compliance with normalization regulations of the IRS. As a result of this memorandum account together with the balancing account discussed below, any differences between the forecasted tax repair deductions and actual tax repair deductions for 2015 – 2017 will be adjusted annually through customer rates. Tax repair deductions during 2015 exceeded the amounts forecasted in the 2015 GRC. As a result, SCE recorded a regulatory liability of $212 million at December 31, 2015, for refunds to customers.

7




Pole Loading and Deteriorated Poles Balancing Account (“PLDPBA”)    
The 2015 GRC established a balancing account for pole loading and deteriorated poles for 2015 – 2017. As a result of the balancing account, authorized GRC revenue for operation and maintenance expenses for the pole loading program and capital revenue requirement for both pole loading and deteriorated poles programs will be adjusted to recorded amounts subject to a maximum amount for the years 2016 and 2017 in the aggregate. SCE is authorized to recover the revenue requirement associated with up to 115% of the authorized spending (operation and maintenance expenses and capital expenditures) during 2016 and 2017 for the pole loading and deteriorated poles programs (there was no maximum amount applicable to 2015 or prior years). SCE would not be entitled to the capital revenues requirement for capital expenditures in excess of the maximum amounts.
Under PLDPBA, SCE earns a return on the rate base applicable to the pole loading and deteriorated pole programs. The rate base for these programs averaged $625 million during 2015, which exceeded the baseline included in the 2015 GRC of $296 million. As a result, SCE recorded additional income during 2015 of $26 million through the PLDPBA. This account also reflects the impact from the difference between recorded and authorized operation and maintenance expenses and repair and cost of removal tax deductions related to these programs. The regulatory liability recorded for refunds to customers under PLDPBA was $36 million at December 31, 2015.
Cost of Capital
On November 25, 2015, the Executive Director of the CPUC granted the joint request submitted by SCE, PG&E, SDG&E, and SoCalGas (collectively, the "Joint Investor-Owned Utilities") for a one-year extension of the due date for the Joint Investor-Owned Utilities to file their next cost of capital applications. As extended, the Joint Investor-Owned Utilities must file their next cost of capital applications by April 20, 2017 instead of April 20, 2016. SCE's authorized rate of return and capital structure for CPUC-related activities will remain unchanged through December 31, 2017.
The Executive Director noted that, in order to effectuate the Joint Investor-Owned Utilities' agreement that their cost of capital would not be adjusted for 2017, they would need to submit a petition to the CPUC requesting that it modify its existing decision establishing the automatic adjustment mechanism. The Joint Investor-Owned Utilities submitted their petition in December 2015. On February 12, 2016, the CPUC issued a proposed decision approving the Joint Investor-Owned Utilities' petition. A final decision is expected by the end of February 2016.
Energy Efficiency Incentive Mechanism
In 2015, the CPUC awarded SCE incentives of $29 million for the 2011 – 2014 energy efficiency program years.
In September 2015, the CPUC granted TURN and ORA petitions and requests for rehearing of prior CPUC decisions related to $74.5 million of incentive awards that SCE received for savings achieved by its 2006 – 2008 energy efficiency programs. The TURN and ORA petitions allege that ex parte communications between PG&E and the former president of the CPUC, which were disclosed in an October 2014 report filed by PG&E, taint the entire 2010 energy efficiency decision and that the decision should be vacated. SCE disputes the assertion that SCE should be at risk to repay previously awarded incentives. SCE cannot predict the outcome of these petitions.
FERC Formula Rates
In December 2015, SCE filed its 2016 annual update with the FERC with the rates effective from January 1, 2016 to December 31, 2016. The update provided support for an increase in SCE's transmission revenue requirement of $182 million or 20% over amounts currently authorized in rates. The increase is mainly due to the completion of several major transmission projects in 2014 and refunds from prior periods.
Permanent Retirement of San Onofre and San Onofre OII Settlement
In November 2014, the CPUC approved the San Onofre OII Settlement Agreement that SCE had entered into with TURN, ORA, SDG&E, the Coalition of California Utility Employees, and Friends of the Earth. The San Onofre OII Settlement Agreement resolved the CPUC's investigation regarding the Steam Generator Replacement Project at San Onofre and the related outages and subsequent shutdown of San Onofre. The San Onofre OII Settlement Agreement does not affect proceedings related to recoveries from third parties, but does describe how shareholders and customers will share any recoveries. For further discussion of third-party recoveries, including claims against MHI, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—San Onofre Related Matters."

8




Challenges related to San Onofre CPUC Proceedings
A federal lawsuit challenging the CPUC's authority to permit rate recovery of San Onofre costs and an application to the CPUC for rehearing of its decision approving the San Onofre OII Settlement Agreement were filed in November and December 2014, respectively. In April 2015, the federal lawsuit was dismissed with prejudice and the plaintiffs in that case appealed the dismissal to the Ninth Circuit in May 2015. Both the appeal and the application for rehearing remain pending.
Also in April 2015, the Alliance for Nuclear Responsibility ("A4NR") filed a petition to modify the CPUC's decision approving the San Onofre OII Settlement Agreement based on SCE's alleged failures to disclose communications between SCE and CPUC decision-makers pertaining to issues in the San Onofre OII. The petition seeks the reversal of the decision approving the San Onofre OII Settlement Agreement and reopening of the OII proceeding. Subsequently, TURN and ORA filed responses supporting A4NR's petition to reopen the San Onofre OII proceeding. In August 2015, ORA filed its own petition to modify the CPUC's decision approving the San Onofre OII Settlement Agreement seeking to set aside the settlement and reopen the San Onofre OII proceeding. SCE and SDG&E responded to this petition in September 2015. Both petitions remain pending before the CPUC.
In July 2015, a purported securities class action lawsuit was filed in federal court against Edison International, its Chief Executive Officer and Chief Financial Officer and was later amended to include SCE's former President as a defendant. The lawsuit alleges that the defendants violated the securities laws by failing to disclose that Edison International had ex parte contacts with CPUC decision-makers regarding the San Onofre OII that were either unreported or more extensive than initially reported. The complaint purports to be filed on behalf of a class of persons who acquired Edison International common stock between March 21, 2014 and June 24, 2015.
Subsequently and also in July 2015, a federal shareholder derivative lawsuit was filed against members of the Edison International Board of Directors for breach of fiduciary duty and other claims. The federal derivative lawsuit is based on similar allegations to the federal class action securities lawsuit and seeks monetary damages, including punitive damages, and various corporate governance reforms. An additional federal shareholder derivative lawsuit making essentially the same allegations was filed in August and was subsequently consolidated with the July 2015 federal derivative lawsuit.
In October 2015, a shareholder derivative lawsuit was filed in California state court against members of the Edison International Board of Directors for breach of fiduciary duty and other claims, making similar allegations to those in the federal derivative lawsuits discussed above.
In November 2015, a purported securities class action lawsuit was filed in federal court against Edison International, its Chief Executive Officer and Treasurer by an Edison International employee, alleging claims under the Employee Retirement Income Security Act ("ERISA"). The complaint purports to be filed on behalf of a class of Edison International employees who were participants in the Edison 401(k) Savings Plan and invested in the Edison International Stock Fund between March 27, 2014 and June 24, 2015. The complaint alleges that defendants breached their fiduciary duties because they knew or should have known that investment in the Edison International Stock Fund was imprudent because the price of Edison International common stock was artificially inflated due to Edison International's alleged failure to disclose certain ex parte communications with CPUC decision-makers related to the San Onofre OII.
SCE has produced documents and is otherwise cooperating with criminal investigations being conducted by the California Attorney General and the U.S. Department of Justice. While the full scope of the investigations is not known to SCE, SCE's document production and cooperation have included information relating to the settlement of the San Onofre OII and interactions between SCE executives and CPUC decision-makers.
Edison International and SCE cannot predict the outcome of these proceedings.
Ex Parte Communications
In February 2015, SCE filed in the San Onofre OII proceeding a Late-Filed Notice of Ex Parte Communication regarding a meeting in March 2013 between an SCE senior executive and the president of the CPUC, both of whom have since retired from their respective positions. In August 2015, the OII Administrative Law Judge issued a ruling that nine additional communications should have been reported in addition to a March 2013 communication that SCE had reported in February 2015. In December 2015, the CPUC issued a final decision that imposed a penalty of $16.74 million in connection with eight communications that the decision finds should have been reported and two violations of a CPUC ethical rule.

9




RESULTS OF OPERATIONS
SCE
SCE's results of operations are derived mainly through two sources:
Utility 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 utility earnings activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances.
Utility 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. Utility 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.
Revenue Impact of 2015 GRC Decision
As indicated in the table below, revenue in the 2015 GRC decision is lower than the amount authorized in 2014 due to lower operation and maintenance costs and income taxes. Accordingly, SCE will refund $451 million to customers beginning in January 2016.
The following table summarizes the 2015 GRC decision compared to the amounts of revenue currently authorized:
(in millions)
2014 Authorized Revenue
 
Exclude
San Onofre Authorized Revenue
 
2014 Authorized Revenue
less San Onofre
 
2015 GRC Final Decision Authorized Revenue
 
(Decrease)
Increase
 
Authorized revenue
$
6,149

 
$
(516
)
 
$
5,633

 
$
5,182

 
$
(451
)
 
Cost of service:
 
 
 
 
 
 
 
 
 
 
  Operation and maintenance
2,354

 
(352
)
 
2,002

 
1,837

 
(165
)
1 
  Depreciation
1,587

 
(91
)
 
1,496

 
1,532

 
36

 
  Property and payroll taxes
273

 
(13
)
 
260

 
246

 
(14
)
 
  Income taxes
494

 
(13
)
 
481

 
197

 
(284
)
2 
Authorized return
1,441

 
(47
)
 
1,394

 
1,370

 
(24
)
 
 
$
6,149

 
$
(516
)
 
$
5,633

 
$
5,182

 
$
(451
)
 
1     Authorized revenue for operation and maintenance costs decreased due to:
$72 million reduction in cost-recovery activities, which does not impact earnings, primarily for pension, postretirement benefits other than pensions (PBOP), medical and results sharing costs. These cost-recovery activities are recorded through balancing accounts, which allow for recovery of these specific projects or program costs, subject to reasonableness review.
$93 million reduction for utility earning activities primarily from SCE's initiatives to improve operational efficiency which has resulted in lower forecasted operation and maintenance costs than included in the 2014 authorized amounts.
2 
Authorized revenue for income taxes decreased due to flow-through items for income tax benefits primarily repair and cost of removal deductions (see "Notes to Consolidated Financial Statements—Note 7. Income Taxes" for a discussion on flow-through regulatory accounting). Forecasted flow-through items increased in the 2015 GRC from the amounts reflected in 2014 authorized revenue which is reflected as lower revenue requirement.

10





The following table is a summary of SCE's results of operations for the periods indicated.
 
2015
2014
2013
(in millions)
Utility
Earning
Activities
Utility
Cost-
Recovery
Activities
Total
Consolidated
Utility Earning Activities
Utility Cost-Recovery Activities
Total Consolidated
Utility
Earning
Activities
Utility
Cost-
Recovery
Activities
Total Consolidated
Operating revenue
$
6,305

$
5,180

$
11,485

$
6,831

$
6,549

$
13,380

$
6,602

$
5,960

$
12,562

Purchased power and fuel

4,266

4,266


5,593

5,593


4,891

4,891

Operation and maintenance
1,977

913

2,890

2,106

951

3,057

2,348

1,068

3,416

Depreciation, decommissioning and amortization
1,915


1,915

1,720


1,720

1,622


1,622

Property and other taxes
334


334

318


318

307


307

Impairment and other charges



163


163

575


575

Total operating expenses
4,226

5,179

9,405

4,307

6,544

10,851

4,852

5,959

10,811

Operating income
2,079

1

2,080

2,524

5

2,529

1,750

1

1,751

Interest expense
(525
)
(1
)
(526
)
(528
)
(5
)
(533
)
(519
)
(1
)
(520
)
Other income and expenses
64


64

43


43

48


48

Income before income taxes
1,618


1,618

2,039


2,039

1,279


1,279

Income tax expense
507


507

474


474

279


279

Net income
1,111


1,111

1,565


1,565

1,000


1,000

Preferred and preference stock dividend requirements
113


113

112


112

100


100

Net income available for common stock
$
998

$

$
998

$
1,453

$

$
1,453

$
900

$

$
900

Core earnings1
 
 
1,368

 
 
1,525

 
 
$
1,265

Non-core earnings
 
 
 
 
 
 
 
 
 
Impairment and other charges
 
 
(382
)
 
 
(72
)
 
 
(365
)
NEIL insurance recoveries
 
 
12

 
 

 
 

Total SCE GAAP earnings
 
 
$
998

 
 
$
1,453

 
 
$
900

1 
See use of non-GAAP financial measures in "Management Overview—Highlights of Operating Results."
Utility Earning Activities
2015 vs 2014
Utility earning activities were primarily affected by the following:
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.

11




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—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—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 $16.74 million related to ex parte communications (See "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies" for further information).
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 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. For further information, see "Management Overview—Regulatory Proceedings—2015 General Rate Case."
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.

12




2014 vs 2013
Utility earning activities were primarily affected by the following:
Higher operating revenue of $229 million due to:
An increase in CPUC-related revenue of $370 million primarily related to the increase in authorized revenue to support rate base growth, including $30 million of additional revenue from revisions to its 2012 – 2014 GRC revenue requirement related to deferred income taxes.
An increase in FERC-related revenue of $130 million primarily related to rate base growth and higher operating costs, including $19 million of additional revenue from a change in estimate under the FERC formula rate mechanism.
Energy efficiency incentive awards were $22 million in 2014 compared to $14 million in 2013.
Generator settlements of $15 million. See "Notes to Consolidated Financial Statements—Note 10. Regulatory Assets and Liabilities—Regulatory Balancing Accounts."
A decrease in San Onofre-related estimated revenue of $188 million, as discussed below.
A decrease in Four Corners-related revenue of $105 million due to the sale of SCE's ownership interest in the Four Corners Generating Station in December 2013 (primarily offset in operation and maintenance and depreciation expense as indicated below).
Lower operation and maintenance expense of $242 million primarily due to:
A decrease in San Onofre-related expense of $179 million as discussed below and a decrease in Four Corners-related expense of $60 million due to the sale in December 2013.
A decrease in severance costs of $34 million (excluding San Onofre). In 2014 and 2013, SCE commenced multiple efforts to reduce its workforce in order to reflect SCE's strategic direction to optimize its cost structure, moderate customer rate increases and align its cost structure with its peers. Severance costs related to workforce reductions (excluding severance related to the permanent retirement of San Onofre Units 2 and 3 recovered in the San Onofre OII Settlement Agreement) were $4 million in 2014 and $38 million in 2013 (See "Notes to Consolidated Financial Statements—Note 8. Compensation and Benefit Plans—Workforce Reductions"). SCE is continuing its efforts to improve operational efficiency. These efforts may lead to additional severance or other charges which cannot be estimated at this time.
A decrease of $30 million primarily related to lower customer service and outside service costs, as well as $20 million of planned outage costs at Mountainview in 2013.
An increase of $85 million of higher operating costs primarily related to transmission and distribution, information technology, legal, safety and insurance costs.
Higher depreciation, decommissioning and amortization expense of $98 million due to a $155 million increase in depreciation mainly related to transmission and distribution investments, partially offset by a decrease in San Onofre-related expense of $14 million discussed below and lower Four Corners-related expense of $45 million due to the sale in December 2013.
Impairment charge of $163 million ($72 million after-tax) in 2014 related to the San Onofre OII Settlement Agreement, as discussed below.
Higher interest expense of $9 million primarily due to lower capitalized interest (AFUDC debt) and higher long-term debt balances to support rate base growth.
Lower other income and expenses of $5 million primarily due to lower AFUDC equity income related to lower AFUDC rates and lower construction work in progress balances in 2014, lower interest income and higher other expenses, offset by $7 million in sales tax refund related to San Onofre discussed below and lower penalties. In 2014 and 2013, SCE incurred penalties of $15 million and $20 million, respectively, resulting from the San Bernardino and San Gabriel settlements in 2014 and Malibu Fire Order Instituting Investigation settlement in 2013. See "Notes to Consolidated Financial Statements—Note 14. Interest and Other Income and Other Expenses."


13




Higher income taxes of $195 million primarily due to higher pre-tax income. See "—Income Taxes" below for more information.
Higher preferred and preference stock dividends of $12 million related to a new issuance in 2014.
On June 6, 2013, SCE decided to permanently retire San Onofre Units 2 and 3. During 2014, SCE entered into the San Onofre OII Settlement Agreement to resolve CPUC regulatory issues associated with San Onofre. See "Management Overview—Permanent Retirement of San Onofre and San Onofre OII Settlement" above for more information. The following table summarizes the results of operations attributable to the San Onofre plant for the years ended December 31, 2014 and 2013, respectively, and is included in Utility Earnings above:
 
Years ended December 31,
 
(in millions)
2014
 
2013
 
Revenue
$
166

1 
$
354

 
Operating expenses
 
 
 
 
Operation and maintenance
93

 
272

5 

Depreciation and amortization
44

2 
58

 
Property and other taxes
16

3 
23

 
Impairment and other charges
163

4 
575

 
AFUDC

 
(6
)
 
Total operating expenses
316

 
922

 
Loss before taxes
$
(150
)
 
$
(568
)
 
1 
Includes a 2014 revenue adjustment of $11 million related to a CPUC decision to refund Unit 1 decommissioning costs to the Nuclear Decommissioning Trusts.
2 
Represents amortization of the San Onofre regulatory asset beginning October 1, 2014.
3 
Includes property and sales tax refunds of $5 million and $7 million related to replacement steam generators for the year ended December 31, 2014. The sales tax refund is included in "Interest and other income" on the consolidated statements of income.
4 
During the fourth quarter of 2014, SCE revised its estimated impact of the San Onofre OII Settlement by $68 million ($24 million after-tax) consistent with advice filing for reimbursement of recorded costs.
5 
Includes severance costs of $63 million for the year ended December 31, 2013.
Utility Cost-Recovery Activities
2015 vs 2014
Utility cost-recovery activities were primarily affected by the following:
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.

14




2014 vs 2013
Utility cost-recovery activities were primarily affected by the following:
Higher purchased power and fuel expense of $702 million was primarily driven by an increased load related to warmer weather and higher power and gas prices experienced in 2014 relative to 2013, partially offset by lower fuel expense in 2014 due to the sale of Four Corners in December 2013 and generator settlements refunded to customers (see "Notes to Consolidated Financial Statements—Note 10. Regulatory Assets and Liabilities" for more information). In addition, in 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. Fuel costs were $256 million in 2014 and $324 million in 2013.
Lower operation and maintenance expense of $117 million primarily due to the CAISO refund of $106 million mentioned above, a decrease in pension and postretirement benefit expenses and lower costs for the GHG cap-and-trade program related to utility owned generation, partially offset by higher spending on various public purpose programs and higher transmission access charges. See "Notes to Consolidated Financial Statements—Note 8. Compensation and Benefit Plans" for more information.
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $12.2 billion for both 2015 and 2014 and $11.6 billion for 2013.
The 2015 revenue reflects:
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.
The 2014 revenue reflects:
An increase of $428 million primarily due to the implementation of the 2014 ERRA rate increase in June 2014 and the increase in GRC authorized revenue, partially offset by the greenhouse gas auction revenue refunded to customers in April and October 2014, and
A sales volume increase of $226 million due to higher load requirements related to warmer weather experienced in 2014 compared to 2013.
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 increased by $33 million in 2015 compared to 2014. The effective tax rates were 31.3% and 23.2% for 2015 and 2014, respectively. The effective tax rate increase in 2015 was primarily due to the $382 million write-down in 2015 of regulatory assets (discussed in "Management Overview—Regulatory Proceedings—2015 General Rate Case") and income tax benefits in 2014 related to the 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.
SCE's income tax provision increased by $195 million in 2014 compared to 2013. The effective tax rates were 23.2% and 21.8% for 2014 and 2013, respectively. The effective tax rate increase in 2014 was primarily due to higher state income taxes.
The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences, which reverse over time. 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.

15




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 and San Onofre OII Settlement" 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)
2015
 
2014
 
2013
Edison Energy Group and subsidiaries
$
(6
)
 
$
(5
)
 
$
(3
)
Edison Mission Group and subsidiaries
32

 
36

 
24

Corporate expenses and other1
(39
)
 
(57
)
 
(42
)
Total Edison International Parent and Other
$
(13
)
 
$
(26
)
 
$
(21
)
 
Includes interest expense (pre-tax) of $31 million, $25 million and $23 million in 2015, 2014, and 2013, respectively.
The loss from continuing operations of Edison International Parent and Other decreased $13 million in 2015 compared to 2014 primarily due to:
A decrease in the loss of Corporate expenses and other primarily due to income tax benefits and lower corporate expenses during 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. Earnings from Edison Capital were $30 million and $34 million for 2015 and 2014, respectively.
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 ($9 million and $2 million after-tax for 2015 and 2014, respectively). For further information, see "Management Overview—Highlights of Operating Results."
The loss from continuing operations of Edison International Parent and other increased $5 million in 2014 compared to 2013 primarily due to:
An increase in the loss of Corporate expenses and other primarily due to higher corporate expense.
An increase in income from EMG and subsidiaries of $12 million primarily due to higher income from affordable housing projects, including asset sales and income tax benefits. Earnings from Edison Capital were $34 million in 2014 and $24 million in 2013.
Income from Discontinued Operations (Net of Tax)
Income from discontinued operations, net of tax, was $35 million, $185 million and $36 million for the years ended December 31, 2015, 2014 and 2013, respectively. The 2015 income was primarily due to income tax benefits (from revised estimates based on filing of the 2014 tax returns) and 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. The 2013 income was from income tax benefits of $36 million from revised estimates of the tax impact of a tax deconsolidation of EME from Edison International as originally contemplated prior to the EME Settlement.

16




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 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.
SCE expects to fund its 2016 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.
Bonus Depreciation
The Protecting Americans from Tax Hikes ("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. This extension is expected to provide a cash flow benefit in 2015 for SCE as additional bonus depreciation deductions will reduce tax liabilities.
Available Liquidity
At December 31, 2015, SCE had $2.58 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, 2015, SCE's debt to total capitalization ratio was 0.44 to 1.
Capital Investment Plan Major Transmission Projects
A summary of SCE's large transmission and substation projects during the next two years is presented below:
Project Name
Project Lifecycle Phase
Scheduled in Service Date
Direct Expenditures1(in millions)
2016 – 2017 Forecast (in millions)
Tehachapi 4-11
In construction
2016 – 2017
$
2,479

$
278

West of Devers
In licensing
2021
1,075

308

Mesa Substation
In licensing
2020
608

234

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 2016 – 2017.
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. Portions of segments 4-11 were placed in service in 2013 with the remaining portions expected to be in service in 2016 and 2017.
The maximum cost estimate used by the CPUC to determine public need for segments 4-11 was established in 2009 at $1.5 billion in 2009 dollars, which was lower than SCE’s requested cost estimate of $1.7 billion (cost estimates made in Tehachapi regulatory filings are in constant dollars in the year of the filing and include direct expenditures and corporate overhead costs). Subsequently, the estimated costs of the project increased due to a number of factors, including engineering scope/design changes, licensing delays, added environmental mitigation and compliance costs, and added construction costs. In addition, the CPUC ordered SCE to underground a 3.5-mile portion of the line that traverses Chino Hills; setting a maximum cost estimate in 2013 of $224 million for the underground portion. The cost estimate that SCE had proposed in 2013 for the underground portion of the Tehachapi Project was $372 million. Separately, during 2013, the CPUC ordered

17




SCE to implement FAA-related scope changes, such as aviation marking and lighting. Including the underground portion of the line, the CPUC has acknowledged a cost estimate to determine public need in 2013 of as much as $2.2 billion to $2.3 billion. SCE has not yet filed a petition for modification with the CPUC for the current 2015 cost estimate of approximately $2.75 billion. Opposition in other communities affected by the project could potentially cause further delays and additional costs. Cost recovery for the project is subject to FERC review and approval.
West of Devers
The West of Devers Project upgrades SCE's existing West of Devers transmission line system by replacing a portion of the existing 220 kV transmission lines and associated structures with higher-capacity transmission lines and structures. The West of Devers Project is intended to facilitate the delivery of electricity produced by new electric generation resources that are being developed or planned in eastern Riverside County. The CPUC has issued a final environmental impact report that identifies an alternate project with a modified scope as an environmentally superior alternative, however a determination of the scope of the project has not yet been finalized. If the CPUC ultimately adopts and approves the alternate project identified in the environmental impact report, the schedule for commencing and completing the project will be delayed by as much as two years. Morongo Transmission LLC holds an option to invest up to $400 million or half of the estimated cost of the project at the commercial operation date in exchange for a 30-year lease right in the transfer capability of the project. If Morongo Transmission LLC exercises its option, SCE’s rate base for this project would exclude the amount funded by Morongo Transmission LLC.
Mesa Substation
The Mesa Substation Project consists of demolishing the existing 220 kV Mesa Substation and constructing a new 500 kV substation. The Mesa 500 kV 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. SCE has filed its permit to construct the project with the CPUC and the project is included in the current 2016 – 2017 capital investment plan. SCE expects approval on the permit to construct by the fourth quarter of 2016.
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. In June 2013, SCE began the initial activity phase of radiological decommissioning by filing with the NRC a certification of permanent cessation of power operations at San Onofre. Notifications of permanent removal of fuel from the reactor vessels were provided in June and July 2013 for Units 3 and 2, respectively. In August 2015, the NRC accepted SCE's Post-Shutdown Decommissioning Activities Report ("PSDAR"), approved SCE's Irradiated Fuel Management Plan and found SCE's Decommissioning Cost Estimate for San Onofre, Units 2 and 3 to be reasonable. SCE is currently permitted to start major radiological decommissioning activities pursuant to NRC regulations, provided SCE obtains all necessary environmental permits for decommissioning. 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—Asset Retirement Obligation."
SCE has nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $2.9 billion as of December 31, 2015. 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.
The CPUC will conduct a reasonableness review for 2014 costs and years going forward. On July 23, 2015, the CPUC approved SCE's request for access to the nuclear decommissioning trusts for reimbursement of 2013 and 2014 Units 2 and 3 decommissioning costs. Under the San Onofre OII Settlement Agreement, any recoveries from the nuclear decommissioning trusts of 2013 and 2014 decommissioning costs funded through GRC revenue must be refunded to customers. In 2015, SCE received $329 million of decommissioning funds and refunded this amount back to customers primarily through ERRA.

18




In 2015, SCE funded decommissioning costs (recorded as a reduction of SCE's asset retirement obligation) until the CPUC approved SCE's request to access the trust funds for 2015 costs in November 2015. SCE's share of the decommissioning costs recorded during 2015 were $216 million and are subject to reasonableness review by the CPUC.
SCE Dividends
SCE made $758 million and $378 million in dividend payments to its parent, Edison International, in 2015 and 2014, respectively. The 2015 increase was due in part to a payment of $147 million in 2015 for outstanding dividends at the end of 2014. Future dividend amounts and timing of distributions 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, 2015, 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, 2015.
(in millions)
 
 
Collateral posted as of December 31, 20151
 
$
173

Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade
 
31

Incremental collateral requirements for power procurement contracts resulting from adverse market price movement2
 
30

Posted and potential collateral requirements
 
$
234

1 
Net collateral provided to counterparties and other brokers consisted of $15 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $31 million of cash reflected in "Other current assets" on the consolidated balance sheets and $127 million in letters of credit and surety bonds.
2 
Incremental collateral requirements were based on potential changes in SCE's forward positions as of December 31, 2015 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, 2015, SCE had regulatory balancing account net overcollections of $2.0 billion, primarily consisting of overcollections related to the base rate revenue account, energy resource recovery 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 2016. Overcollections related to the energy resource recovery account are expected to decrease as a result of the implementation of an ERRA rate change, effective January 1, 2016. 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.

19




Edison International Parent and Other
Edison International Parent and Other's liquidity and its ability to pay operating expenses, make investments and pay dividends to common shareholders are dependent on dividends from SCE and access to bank and capital markets. At December 31, 2015, Edison International had $604 million available under its $1.25 billion credit facility. For further details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Edison International may finance working capital requirements to support operations and capital expenditures with commercial paper or other borrowings, subject to availability in the capital markets. The debt covenant in Edison International's credit facility requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1 as defined in the credit agreement. The Edison International's consolidated debt to total capitalization ratio was 0.47 to 1 at December 31, 2015.
EME Settlement Agreement
In August 2014, Edison International entered into an amendment of the EME Settlement Agreement that finalized the remaining matters related to the EME Settlement. Edison International made a payment of $204 million on September 30, 2015 and is scheduled to make a final payment of $214 million on September 30, 2016.
Edison International intends to make the remaining payment from realization of state tax benefits or issuance of commercial paper or other borrowings. Edison International has $1.0 billion of net operating loss and tax credit carryforwards at December 31, 2015 retained by EME which are available to offset future consolidated taxable income or tax liabilities. 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 EME retained tax benefits has been deferred (currently forecasted through 2022). The timing of realization of these tax benefits may be further delayed in the event of future extensions of bonus depreciation, and the value of the net operating loss carryforwards could be permanently reduced if that tax reform decreased the current corporate tax rate.
Edison Energy Group Capital Expenditures
Forecasted capital expenditures for Edison Energy Group’s commercial solar activities are estimated to be $134 million in 2016. Edison Energy Group expects to finance these expenditures primarily with new project and tax equity financings and an existing debt financing to support equity contributions similar to the existing financings arrangement used to fund 2015 capital expenditures. For further information, see "Notes to Consolidated Financial Statements—Note 9. Investments."
Historical Cash Flows
SCE
(in millions)
2015
 
2014
 
2013
Net cash provided by operating activities
$
4,624

 
$
3,660

 
$
3,048

Net cash (used in) provided by financing activities
(812
)
 
181

 
508

Net cash used by investing activities
(3,824
)
 
(3,857
)
 
(3,547
)
Net (decrease) increase in cash and cash equivalents
$
(12
)
 
$
(16
)
 
$
9


20




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 2015, 2014 and 2013.
 
Years ended December 31,
 
Change in cash flows
(in millions)
2015
2014
2013
 
2015/2014
2014/2013
Net income
$
1,111

$
1,565

$
1,000

 

 
Non cash items1
2,231

2,381

2,631

 
 
 
    Subtotal
$
3,342

$
3,946

$
3,631

 
$
(604
)
$
315

Changes in cash flow resulting from working capital2
16

79

(182
)
 
(63
)
261

Derivative assets and liabilities, net
45

(40
)
(30
)
 
85

(10
)
Regulatory assets and liabilities, net
1,729

(358
)
(322
)
 
2,087

(36
)
Other noncurrent assets and liabilities, net3
(508
)
33

(49
)
 
(541
)
82

Net cash provided by operating activities
$
4,624

$
3,660

$
3,048

 
$
964

$
612

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 decommissioning expenditures funded through the nuclear decommissioning trusts.
Net income and noncash items decreased in 2015 by $604 million from 2014 and increased in 2014 by $315 million from 2013. The decrease in 2015 was primarily due to the implementation of the 2015 GRC decision. The increase in 2014 was primarily due to rate base growth. The factors that impacted these items are discussed under "Results of Operations—SCE—Utility Earning Activities."
Changes in cash flows related to working capital items decreased in 2015 by $63 million from 2014 and increased in 2014 by $261 million from 2013. In 2015, SCE had net tax payments of approximately $144 million, compared to net tax refunds of $88 million in 2014 and net tax payments of $28 million in 2013. The refunds in 2014 were due to net operating loss carrybacks to periods that SCE previously had taxable income. In 2015, 2014 and 2013, SCE had severance payments of $39 million, $22 million and $151 million, respectively, related to the workforce reductions. In addition, the cash outflow in 2015 was due to the timing of receipts from customers and timing of disbursements.
Net cash provided by operating activities was also impacted by changes in regulatory assets and liabilities, including changes in over (under) collections of balancing accounts. SCE has a number of balancing accounts under CPUC decisions, which impact cash flows based on differences between timing of collection of amounts through rates and accrual expenditures. While some balancing accounts are discrete, other balancing accounts are ongoing with changes generally collected in the following year. The impact on cash flow from the following balancing accounts are:
ERRA overcollections for fuel and purchased power for 2015 were $439 million due to lower than forecasted power and gas prices experienced in 2015, refund related to the 2013 and 2014 nuclear decommissioning costs (see "—Decommissioning of San Onofre" above) and the NEIL settlement proceeds from insurance claims arising out of the failures of the San Onofre replacement steam generators. See "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—San Onofre Related Matters" for further discussion. In January 2015, SCE reclassified the regulatory liability for generator settlements to ERRA to refund customers as required by the CPUC.
ERRA undercollections for fuel and power procurement-related costs for 2014 and 2013 were $1.03 billion and $1.0 billion, respectively, due to the amount and price of power and fuel being higher than forecasted. In December 2014, SCE reclassified $540 million 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.
The base rate revenue account ("BRRBA") tracks differences between amounts authorized by the CPUC in the GRC proceedings and amounts billed to customers. SCE had BRRBA overcollections of $319 million, $5 million and $247 million in 2015, 2014 and 2013, respectively. During 2015, the BBRBA account increased primarily due to revenue previously collected from customers that is expected to be refunded as part of the 2015 GRC decision. The

21




overcollections were partially offset by lower electricity sales than forecasted in rates as a result of cooler weather experienced in 2015.
During 2014, the BRRBA account decreased by $242 million due primarily to refunds to customers of approximately $150 million, related to the sale of Four Corners in December 2013. During 2013, the BRRBA account impacted cash flows by $752 million primarily due to the implementation of the 2012 GRC decision which resulted in a rate increase in January 2013 to collect both the 2012 and 2013 rate increases. See "Results of Operations" for further discussion.
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 decreased for these programs by $191 million and $278 million in 2015 and 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 2015 and 2014.
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). See "Management Overview—Regulatory Proceedings—2015 General Rate Case—Tax Repair Deductions and Memorandum Account" for further discussion.
Cash flows (used) provided by other noncurrent assets and liabilities were $(508) million, $33 million and $(49) million in 2015, 2014 and 2013, respectively. Major factors affecting cash flow related to non-current assets and liabilities were activities related to SCE's nuclear decommissioning trusts (principally related to the payment of decommissioning costs).
Net Cash (Used in) Provided by Financing Activities
The following table summarizes cash provided by financing activities for 2015, 2014 and 2013. 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)
2015
 
2014
 
2013
Issuances of first and refunding mortgage bonds, net
$
1,287

 
$
498

 
$
2,168

Issuances of pollution control bonds, net and other
126

 

 

Long-term debt matured or repurchased
(761
)
 
(607
)
 
(1,016
)
Short-term debt financing, net
(619
)
 
490

 
(1
)
Issuances of preference stock, net
319

 
269

 
387

Payments of common stock dividends to Edison International
(758
)
 
(378
)
 
(486
)
Redemptions of preference stock
(325
)
 

 
(400
)
Payments of preferred and preference stock dividends
(116
)
 
(111
)
 
(101
)
Other
35

 
20

 
(43
)
Net cash (used in) provided by financing activities
$
(812
)
 
$
181

 
$
508

Net Cash Used by Investing Activities
Cash flows used in investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $4.2 billion for 2015, $3.9 billion for 2014 and $3.6 billion for 2013, primarily related to transmission, distribution and generation investments. Net proceeds (purchases) of nuclear decommissioning trust investments were $374 million, $(44) million and $(98) million for 2015, 2014 and 2013, respectively. See "Nuclear Decommissioning Trusts" below for further discussion. The 2015 net proceeds from sale of nuclear decommissioning trust investments was used to pay 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 December 2013, SCE completed the sale of its ownership interest in Units 4 and 5 of the Four Corners Generating Station which resulted in $181 million of proceeds.

22




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)
2015
2014
2013
Net cash (used in) provided by operating activities:
   Nuclear decommissioning trusts
$
(428
)
$
39

$
76

Net cash flow from investing activities:
   Proceeds from sale of investments
3,506

2,617

1,204

   Purchases of investments
(3,132
)
(2,661
)
(1,302
)
Net cash impact
$
(54
)
$
(5
)
$
(22
)
Net cash (used in) 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. Such amounts will continue to be reflected as a decrease in SCE net cash provided by operating activities and will be funded from sales of investments of the nuclear decommissioning trusts once approved by the CPUC. Decommissioning costs incurred prior to CPUC approval will be funded by SCE and are reflected as cash flow used by operating activities. 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)
2015
 
2014
 
2013
Net cash used in operating activities
$
(115
)
 
$
(412
)
 
$
(81
)
Net cash provided by financing activities
224

 
464

 
73

Net cash used in investing activities
(68
)
 
(50
)
 
(25
)
Net increase (decrease) in cash and cash equivalents
$
41

 
$
2

 
$
(33
)
Net Cash Used by Operating Activities
Net cash used by operating activities decreased in 2015 by $297 million from 2014 and increased in 2014 by $331 million from 2013 due to:
$204 million and $225 million of cash payments made to the Reorganization Trust in September 2015 and April 2014 related to the EME Settlement Agreement, respectively, 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.
$54 million cash outflow from operating activities in 2015, compared to $2 million cash inflow in 2014 and $81 million cash outflow in 2013, due to the timing of payments and receipts relating to interest and operating costs.

23




Net Cash Provided by Financing Activities
Net cash provided by financing activities were as follows:
(in millions)
 
2015
 
2014
 
2013
Dividends paid to Edison International common shareholders
 
$
(544
)
 
$
(463
)
 
$
(440
)
Dividends received from SCE
 
758

 
378

 
486

Payment for stock-based compensation
 
(119
)
 
(106
)
 
(25
)
Receipt from stock option exercises
 
67

 
66

 
16

Debt financing, net1
 
47

 
589

 
33

Other
 
15

 

 
3

Net cash provided by financing activities
 
$
224

 
$
464

 
$
73

1  
Includes $20 million debt financing for Edison Energy Group, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings."
Net Cash Used by Investing Activities
Net cash used by investing activities during 2015 primarily relates to approximately $100 million in acquisitions of three companies that support Edison Energy Group's commercial and industrial services growth strategy and $15 million related to Edison Energy Group's capital expenditures for commercial solar installations. See "Notes to Consolidated Financial Statements—Note 9. Investments" for further information.
Net cash used by investing activities during 2014 relate to Edison Energy Group's capital expenditures of $49 million for commercial solar installations.
Contractual Obligations and Contingencies
Contractual Obligations
Edison International Parent and Other and SCE's contractual obligations as of December 31, 2015, for the years 2016 through 2020 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
 
$
19,511

 
$
546

 
$
1,813

 
$
869

 
$
16,283

Power purchase agreements:2
 
 
 
 
 
 
 
 
 
 
Renewable energy contracts
 
28,729

 
1,234

 
2,889

 
3,167

 
21,439

Qualifying facility contracts
 
756

 
223

 
338

 
126

 
69

Other power purchase agreements
 
4,072

 
741

 
1,347

 
962

 
1,022

Other operating lease obligations3
 
497

 
68

 
96

 
62

 
271

Purchase obligations:4
 
 
 
 
 
 
 
 
 
 
Other contractual obligations
 
1,084

 
181

 
241

 
115

 
547

Total SCE5,6,7
 
54,649

 
2,993

 
6,724

 
5,301

 
39,631

Edison International Parent and Other:
 
 
 
 
 
 
 
 
 
 
Long-term debt maturities and interest1
 
465

 
18

 
417

 
4

 
26

EME settlement payments
 
214

 
214

 

 

 

Total Edison International Parent and Other5
 
679

 
232

 
417

 
4

 
26

Total Edison International6,7
 
$
55,328

 
$
3,225

 
$
7,141

 
$
5,305

 
$
39,657

1 
For additional details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Amount includes interest payments totaling $8.86 billion and $34 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, capital or financing leases. For further discussion, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies."
3 
At December 31, 2015, 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."
4 
For additional details, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies." At December 31, 2015, other commitments were primarily related to maintaining reliability and expanding SCE's transmission and distribution system, nuclear storage space and capacity reduction contracts.
5 
At December 31, 2015, Edison International Parent and Other and SCE had estimated contributions to the pension and PBOP plans. SCE estimated contributions are $127 million, $128 million in 2016 and 2017, respectively. Edison International Parent and Other estimated contributions are $30 million and $23 million for the same respective periods. The estimated contributions are not available beyond 2017. 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.
6 
At December 31, 2015, Edison International and SCE had a total net liability recorded for uncertain tax positions of $529 million and $353 million, respectively, which is excluded from the table. Edison International and SCE cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the tax authorities.
7 
The contractual obligations table does not include derivative obligations and asset retirement obligations, which are discussed in "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments," and "—Note 1. Summary of Significant Accounting Policies," respectively.
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
SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operation and maintenance, monitoring and site closure. Unless there is a single probable amount, SCE records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
As of December 31, 2015, SCE had identified 19 material sites for remediation and recorded an estimated minimum liability of $131 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies" for further discussion.
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 and Trust IV 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% and $325 million (aggregate liquidation preference) of 5.375%, 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."

25




MARKET RISK EXPOSURES
Edison International 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, to fund business operations and to fund 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—CPUC" 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, 2015, 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
$
11,259

 
$
12,252

 
$
11,754

 
$
12,789

SCE
10,616

 
11,592

 
11,095

 
12,128

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 StatementsNote 4. Fair Value Measurements."
The fair value of outstanding derivative instruments used to mitigate exposure to commodity price risk was a net liability of $1.2 billion and $927 million at December 31, 2015 and 2014, 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, 2015, if the electricity prices or gas prices were changed while leaving all other assumptions constant:
(in millions)
December 31, 2015

Increase in electricity prices by 10%
$
147

Decrease in electricity prices by 10%
(123
)
Increase in gas prices by 10%
(43
)
Decrease in gas prices by 10%
49


26




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 published credit 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, 2015, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:
 
December 31, 2015
(in millions)
Exposure2
 
Collateral
 
Net Exposure
S&P Credit Rating1
 
 
 
 
 
A or higher
$
153

 
$

 
$
153

Not rated
12

 
(5
)
 
7

Total
$
165

 
$
(5
)
 
$
160

1 
SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.
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.
As discussed in "Management Overview—Regulatory Proceedings—2015 GRC," 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.

27




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.
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, 2015, the consolidated balance sheets included regulatory assets of $8.07 billion and regulatory liabilities of $6.8 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 2010 for Palo Verde and San Onofre Unit 1 and a 2014 updated decommissioning cost estimate for the retirement of San Onofre Units 2 and 3. See "Management Overview—Permanent Retirement of San Onofre and San Onofre OII Settlement" for further discussion of the plans for decommissioning of San Onofre. SCE currently estimates that it will spend approximately $7.2 billion through 2075 to decommission its nuclear facilities. Decommissioning cost estimates are updated in each Nuclear Decommissioning Triennial Proceeding. The current ARO estimates for San Onofre and Palo Verde are based on the assumptions from these decommissioning studies:
Decommissioning Costs. The estimated costs for labor, dismantling and disposal costs, site remediation, energy and miscellaneous costs.
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, energy and low level radioactive waste burial costs. SCE's current estimate is based on SCE's decommissioning cost

28




methodology used for ratemaking purposes, escalated at rates ranging from 1.4% to 7.3% (depending on the cost element) annually.
Timing. Cost estimates for Palo Verde are based on an assumption that decommissioning will commence promptly after the current NRC operating licenses expire. The Palo Verde 1, 2, 3 operating licenses currently expire in 2045, 2046 and 2047 respectively. Cost estimates for San Onofre are based on an assumption that decommissioning commenced in 2013. For further information, see "Management Overview—Permanent Retirement of San Onofre and San Onofre OII Settlement."
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 2055 and 2075, respectively. Costs for spent fuel monitoring are included until 2055 and 2075, respectively.
Changes in Decommissioning Technology, Regulation, and Economics. The current cost studies assume the use of current technologies under current regulations and at current cost levels.
Effect if Different Assumptions Used.   The ARO for decommissioning SCE's nuclear facilities was $2.7 billion as of December 31, 2015, based on decommissioning studies performed in 2010 for Palo Verde, in 2011 for San Onofre Unit 1 and in 2014 for San Onofre Unit 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. SCE has issued a request for proposal to engage a general contractor to undertake a significant scope of decommissioning activities for Units 2 and 3 at San Onofre and expects to make a selection during 2016. The ARO for decommissioning these units is expected to be updated subsequent to the selection of a general contractor based, in part, on the results of the competitive selection process.
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, 2015
Uniform increase in escalation rate of 100 basis points
$
574

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, 2015, Edison International's and SCE's pension plans had a $4.4 billion and $3.9 billion benefit obligation, respectively, and total 2015 expense for these plans was $118 million and $111 million, respectively. As of December 31, 2015, the benefit obligation for both Edison International's and SCE's PBOP plans was $2.4 billion and $2.3 billion, respectively, and total 2015 expense for Edison International's and SCE's plans was $24 million and $23 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.

29




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, 2015, this cumulative difference amounted to a regulatory asset of $176 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 2015:
(in millions)
Pension
Plans
Postretirement
Benefits Other
than Pensions
Discount rate1
3.85
%
4.16
%
Expected long-term return on plan assets2
7.00
%
5.50
%
Assumed health care cost trend rates3
*

7.75
%
* 
Not applicable to pension plans.
1 
The discount rate enables Edison International and SCE to state expected future cash flows at a present value on the measurement date. Edison International and SCE select its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. The AON-Hewitt yield curve is considered in determining the discount rate.
2 
To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns on plan assets. A portion of PBOP trusts asset returns are subject to taxation, so the 5.5% 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 1.1%, 8.4% and 6.5% for the one-year, five-year and ten-year periods ended December 31, 2015, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 0.3%, 8.3% and 5.7% over these same periods. Accounting principles provide that differences between expected and actual returns are recognized over the average future service of employees.
3 
The health care cost trend rate gradually declines to 5.0% for 2021 and beyond.
As of December 31, 2015, Edison International and SCE had unrecognized pension costs of $771 million and $702 million, and unrecognized PBOP costs of $178 million and $174 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, $675 million of SCE's pension costs and $174 million of SCE's PBOP costs are recorded as regulatory assets, and will be amortized to expense over the average expected future service of employees.
Edison International's and SCE's pension and PBOP plans are subject to limits established for federal tax deductibility. SCE funds its pension and PBOP plans in accordance with amounts allowed by the CPUC. Executive pension plans have no plan assets.
Effect if Different Assumptions Used.    Changes in the estimated costs or timing of pension and other postretirement benefit obligations, or the assumptions and judgments used by management underlying these estimates, could have a material effect on the recorded expenses and liabilities.
The following table summarizes the increase or (decrease) to projected benefit obligation for pension and the accumulated benefit obligation for PBOP if the discount rate were changed while leaving all other assumptions constant:
 
Edison International
 
SCE
(in millions)
Increase in discount rate by 1%
 
Decrease in discount rate by 1%
 
Increase in discount rate by 1%
 
Decrease in discount rate by 1%
Change to projected benefit obligation for pension
$
(468
)
 
$
530

 
$
(410
)
 
$
459

Change to accumulated benefit obligation for PBOP
(321
)
 
372

 
(320
)
 
371


30




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 $33 million and $31 million, respectively, and a one percentage point increase in the expected rate of return on PBOP plan assets would decrease both Edison International's and SCE's current year expense by $21 million.
The following table summarizes the increase or (decrease) to accumulated benefit obligation and annual aggregate service and interest costs for PBOP if the health care cost trend rate was changed while leaving all other assumptions constant:
 
Edison International
 
SCE
(in millions)
Increase in health care cost trend rate by 1%
 
Decrease in health care cost trend rate by 1%
 
Increase in health care cost trend rate by 1%
 
Decrease in health care cost trend rate by 1%
Change to accumulated benefit obligation for PBOP
$
251

 
$
(206
)
 
$
250

 
$
(205
)
Change to annual aggregate service and interest costs
12

 
(9
)
 
12

 
(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, 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 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. The EME Settlement Agreement requires Edison International to make fixed payments to a newly formed trust under the control of EME's creditors (the "Reorganization Trust"). Edison International plans to use its credit facilities or incur new debt to fund a portion of the Reorganization Trust payments due to delays in monetizing tax benefits

31




retained by EME as a result of the recent extension of bonus depreciation. Realization of such tax benefits may be further delayed or permanently reduced by future tax legislation that extends bonus depreciation or reduces the current corporate tax rate. 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.
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 is developing Competitive Businesses that may diversify geographically beyond California, these businesses are not yet material. As a result, Edison International's future performance may be affected by events and economic performance concentrated in California or by regional regulation or legislation.
Edison International is developing Competitive Businesses that may not be successful.
Edison International is developing Competitive Businesses to capitalize on changes in the electricity industry. Edison International intends to invest in companies to develop the capabilities of its Competitive Businesses but there can be no assurance that Edison International will be successful in developing profitable Competitive Businesses.
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.
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 concerted community opposition and such delay or defeat could have a material effect on SCE's business.
The CPUC is considering rulemaking to govern 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 from its customers in a timely manner its costs, 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 CPUC approves the recovery of such costs. For example, the recovery of the Tehachapi transmission project costs are subject to FERC approval and the

32




public need for the project is reviewed by the CPUC. SCE has not yet filed a petition for modification with the CPUC to reconfirm public need at an increased cost, estimated to be approximately $2.75 billion (2015 cost estimate). Including the underground portion of the line, the CPUC has previously acknowledged a cost estimate to determine public need in 2013 of as much as $2.2 billion to $2.3 billion. For more information, see "Liquidity—Capital Investment Plan Major Transmission Projects" 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 material amounts of 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 Matters—2015 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 may increase due to the leak at the Southern California Gas Company ("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, its 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.
The electricity industry is undergoing change, including technological advancements such as energy storage, greater deployment of distributed energy resources, such as customer-owned generation, and expansion of electric vehicles requiring increased utility distribution infrastructure and modifications in customer electric load requirements that could alter the nature of energy generation and delivery. In addition, there has been public discussion regarding the possibility of future changes in the electric utility business model as a result of these developments. In October 2013, the CPUC held an open hearing to receive views from various sources on whether the current California utility business model should be revised. It is possible that revisions to the traditional utility business model could materially affect SCE's business model and its financial condition and results of operations.

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Demand for electricity from utilities has been leveling, while growth in customer-owned generation has increased. At the same time, significant investment is needed to replace aging infrastructure and convert the electric distribution grid to support two-way flows of electricity.
Customer-owned generation itself reduces the amount of electricity those customers purchase from utilities and has the effect of increasing utility rates unless retail rates are designed to allocate the costs of the distribution grid across all customers that benefit from their 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 results in increased utility rates for those customers who do not own their generation. Such increases foster the public discussion regarding future changes in the electric utility business model.
In addition, the FERC has adopted changes that have 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 the operational risks and the need for superior execution in its 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. The CPUC has increased its focus on public safety issues 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.

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There are inherent risks associated with owning and decommissioning nuclear power generating facilities and obtaining cost reimbursement, including, among other things, 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. The costs of decommissioning Unit 2 and Unit 3 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.
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 $13.5 billion. SCE and other owners of the San Onofre and Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance available of $375 million per site. If nuclear incident liability claims were to exceed $375 million, the remaining amount would be made up from contributions of approximately $13.1 billion made by all of the nuclear facility owners in the U.S., up to an aggregate total of $13.5 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 $375 million. If this public liability limit of $13.5 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. In addition, the insurance that has been obtained for wildfire liabilities may not be sufficient. 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. Furthermore, insurance for wildfire liabilities may not continue to be available at all or at rates or on terms similar to those presently available to Edison International. For more information on wildfire insurance risk, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—Wildfire Insurance."
Cybersecurity 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.

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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 and frequently changing 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. However, the current trend is toward more stringent standards, stricter regulation, 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 purchased power costs. 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. Other environmental laws, particularly with respect to air emissions, disposal of ash, wastewater discharge and cooling water systems, are also generally becoming more stringent. The operation of SCE facilities under such laws and regulations may require substantial capital expenditures for environmental controls or cessation of operations. Current and future state laws and regulations in California also could increase the required amount of energy that must be procured from renewable resources. Environmental regulations and permitting requirements also affect the cost and timing of transmission and distribution projects. 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

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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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules 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, 2015, 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 23, 2016


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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 at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule 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 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 23, 2016

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Consolidated Statements of Income
Edison International
 


 
 
 
Years ended December 31,
(in millions, except per-share amounts)
2015
 
2014
 
2013
Total operating revenue
$
11,524

 
$
13,413

 
$
12,581

Purchased power and fuel
4,266

 
5,593

 
4,891

Operation and maintenance
2,990

 
3,149

 
3,473

Depreciation, decommissioning and amortization
1,919

 
1,720

 
1,622

Property and other taxes
336

 
322

 
309

Impairment and other charges
5

 
157

 
571

Total operating expenses
9,516

 
10,941

 
10,866

Operating income
2,008

 
2,472

 
1,715

Interest and other income
174

 
147

 
124

Interest expense
(555