EIX-SCE 2014 10K



 
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, 2014
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, 2014, the last business day of the most recently completed second fiscal quarter:
Edison International    Approximately $15.7 billion    Southern California Edison Company    Wholly owned by Edison International
Common Stock outstanding as of February 20, 2015:
 
 
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 2015 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



 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear Decommissioning – Asset Retirement Obligation
 
 
 
 
 
 
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
CAA
 
Clean Air Act
CAISO
 
California Independent System Operator
CARB
 
California Air Resources Board
Competitive Businesses
 
competitive businesses related to the generation or use of electricity
CPUC
 
California Public Utilities Commission
CRRs
 
congestion revenue rights
DOE
 
U.S. Department of Energy
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
ISO
 
Independent System Operator
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
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
 
large pressurized water 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)


v



PG&E
 
Pacific Gas & Electric Company
PSD
 
Prevention of Significant Deterioration
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
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;
decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities and delays in regulatory actions, including potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;
ability of Edison International or SCE to borrow funds and access the capital markets on reasonable terms;
extent of technological change in the generation, storage, transmission, distribution and use of electricity;
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 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 are delays in the construction of transmission that impact the ability to accept power delivery), and governmental approvals;
physical security of SCE's critical assets and personnel and the cyber security of SCE's critical industrial control systems for the operation of the electric grid and other assets and information technology systems for business and customer data;
risks associated with the retirement and decommissioning of nuclear generating facilities;
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 and other public policy 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 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 and price mitigation strategies adopted by the California Independent System Operator, Regional Transmission Organizations, 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 or disruptions from labor disputes;
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;
effects of legal proceedings, changes in or interpretations of tax laws, rates or policies;
cost and availability of fuel for generating facilities and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;

1



cost and availability of emission credits or allowances for emission credits;
increasing competition in building new transmission systems in SCE's service territory due to FERC Order 1000 that may result in a decrease in new transmission investments by SCE; 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 the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International's and SCE's businesses. Forward-looking statements speak only as of the date they are made and neither Edison International nor SCE are obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International and SCE with the SEC.
Except when otherwise stated, references to each of Edison International, SCE, Edison Energy, EMG, 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 non-utility 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 related to the generation or use of electricity (the "Competitive Businesses"). Such competitive 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)
2014
 
2013
 
2014 vs 2013 Change
 
2012
Net income (loss) attributable to Edison International
 
 
 
 
 
 
 
Continuing operations
 
 
 
 
 
 
 
SCE
$
1,453

 
$
900

 
$
553

 
$
1,569

Edison International Parent and Other
(26
)
 
(21
)
 
(5
)
 
(66
)
Discontinued operations
185

 
36

 
149

 
(1,686
)
Edison International
1,612

 
915

 
697

 
(183
)
Less: Non-core items
 
 
 
 
 
 
 
     SCE
 
 
 
 
 
 
 
Impairment and other charges
(72
)
 
(365
)
 
293

 

2012 General Rate Case – repair deductions (2009 – 2011)

 

 

 
231

     Edison International Parent and Other
 
 
 
 
 
 
 
Consolidated state deferred tax impacts related to EME

 

 

 
(37
)
Gain on sale of Beaver Valley lease interest

 
7

 
(7
)
 
31

Income from allocation of losses to tax equity investor
2

 

 
2

 

     Discontinued operations
185

 
36

 
149

 
(1,686
)
Total non-core items
115

 
(322
)
 
437

 
(1,461
)
Core earnings (losses)
 
 
 
 
 
 
 
SCE
1,525

 
1,265

 
260

 
1,338

Edison International Parent and Other
(28
)
 
(28
)
 

 
(60
)
Edison International
$
1,497

 
$
1,237

 
$
260

 
$
1,278

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; asset impairments and certain tax, regulatory or legal settlements or proceedings.
SCE's 2014 core earnings increased $260 million for the year primarily due to higher authorized revenues from rate base growth, higher income tax benefits and lower severance costs. In the fourth quarter of 2014, the CPUC authorized an increase in SCE's revenue of $30 million ($18 million after-tax) due to a revised determination of rate base for deferred income taxes. Included in 2014 results is $19 million ($11 million after-tax) from a change in estimate of revenue under its FERC formula rate and $15 million ($9 million after-tax) of benefits related to generator settlements. See "Notes to Consolidated Financial

3




Statements—Note 14. Interest and Other Income and Other Expenses." SCE incurred severance costs (after-tax) related to workforce reductions of $2 million and $31 million in 2014 and 2013, respectively.
Edison International Parent and Other's core losses for 2014 included higher corporate and new business expenses, offset by higher income from Edison Capital's investments in affordable housing projects.
Consolidated non-core items for 2014 and 2013 for Edison International included:
Impairment and other charges of $163 million ($72 million after-tax) in 2014 related to the San Onofre OII Settlement Agreement (as discussed below) and $575 million ($365 million after-tax) in 2013 related to the permanent retirement of San Onofre Units 2 and 3. 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 the advice filing for reimbursement of recorded costs. The total 2014 and 2013 charges resulting from the San Onofre issues and settlement were $738 million ($437 million after-tax). Such amounts do not reflect any recoveries from third parties by SCE. 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 from discontinued operations, net of tax, included:
Income of $168 million in 2014 related to the impact of completing the transactions called for in the EME Settlement Agreement (as defined below).
Income tax benefits of $39 million during the fourth quarter of 2014 from resolution of uncertain tax positions from settlement of 2003 – 2006 tax years with the IRS and other tax impacts related to EME. See "Notes to Consolidated Financial Statements—Note 7. Income Taxes" for further information.
Income tax loss of $22 million in 2014 compared to a benefit of $36 million in 2013 from revised estimates of the tax impact of a tax deconsolidation of EME from Edison International as originally contemplated prior to the EME Settlement. For further information, see "—Resolution of Uncertainty Related to EME in Bankruptcy."
An income tax benefit of $7 million in the first quarter of 2013 from reduction in state income taxes related to the sale of Edison Capital's interest in Unit No. 2 of the Beaver Valley Power plant. The sale of Edison Capital's lease interest was completed in 2012. However, the final determination of state income taxes paid was not completed until the first quarter of 2013 which resulted in a change in the estimate of state income taxes due.
Income of $2 million 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, related financings and the priority return to tax equity investor. 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.
See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations, including a comparison of 2013 results to 2012.
Electricity Industry Trends
The electricity industry is undergoing extensive change, including technological advancements such as customer-owned generation, energy storage and customer-owned generation that may change 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 such as reducing GHG emissions and encouraging 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 and customer-owned generation and changes in electricity generation, transmission and distribution.

4




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 AB 32, the California Global Warming Solutions Act of 2006. AB 32 established a comprehensive program to reduce GHG emissions and required regulations that would reduce California's GHG emissions to 1990 levels by 2020. California law currently requires retail sellers of electricity to procure 33% of their customers' electricity requirements from renewable resources. The Governor of California has proposed the next set of objectives for 2030 and beyond, which include increasing from 33% to 50% the electricity derived from renewable resources. Also included is a targeted 50% reduction of petroleum use in mobile vehicles, which may result in growth in electric vehicles and investment in charging infrastructure. California’s policy goals in these areas 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.
Having considered these trends, 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. Edison International is investing, at much more modest levels, in Competitive Businesses to largely evaluate the attractiveness of new business models and potential competitive threats to the traditional utility business model.
Distribution Grid Development
The distribution grid needs investment to support two-way flows of electricity created by customer-owned generation as well as new technologies such as electric vehicles and energy storage and is critical to implementing California's public policy goals, including those to reduce GHG emissions. SCE is engaged in initiatives that are not currently addressed in the GRC, including preparing a Distribution Resources Plan and participating in the Charge Ready Program.
Distribution Resources Plan
AB 327 requires SCE and other California investor-owned utilities to submit a proposed Distribution Resources Plan by July 1, 2015. The goal of the Distribution Resources Plan is to facilitate the integration of distributed energy resources at optimal locations in a manner that minimizes overall system costs and maximizes customer benefits from these investments, while at the same time maintaining system safety and reliability. To accomplish this, the plan must evaluate locational benefits and costs of distributed resources located on the distribution system based upon reductions or increases in local generation capacity needs, avoided or increased investments in distribution infrastructure, safety benefits, reliability benefits, and any other savings distributed resources provide to the electric grid or costs to customers.
Charge Ready Program
SCE proposes to increase the availability of electric vehicle charging stations through its Charge Ready program. SCE proposes to work with cities, employers, apartment owners, charging equipment manufacturers and others to deploy up to 30,000 qualified charging stations at locations where cars may be parked for four hours or more. Under the proposal, SCE would build, own and maintain the electric infrastructure needed to serve the qualified charging stations at participating customer locations. Participating customers would install, own, maintain, and operate the charging stations.
The program proposes to begin with a $22 million pilot for installation of up to 1,500 chargers as well as a supporting market education effort. The results of this first phase will help shape Phase 2 of the program, which is expected to cost an additional $333 million over the next five years. SCE requested CPUC approval for its pilot by June 2015, and for Phase 2 by June 2016.
The CPUC issued a decision in December 2014 that reversed a prior prohibition on utility ownership of electric vehicle infrastructure and implemented a case-by-case evaluation requirement for proposed utility investments in electric vehicle infrastructure.
Capital Program
Total capital expenditures (including accruals) were $4.0 billion in 2014 and $3.5 billion in 2013. SCE's year-end rate base (excluding San Onofre) was $23.3 billion at December 31, 2014 compared to $21.1 billion at December 31, 2013.
SCE forecasts capital expenditures in the range of $11.8 billion to $13.4 billion for 2015 – 2017. Actual capital spending will be affected by: changes in regulatory, environmental and engineering design requirements; permitting and project delays; cost and availability of labor, equipment and materials; and other factors. These factors as well as major projects are discussed further under "—Liquidity and Capital Resources—SCE—Capital Investment Plan."

5



Regulatory Matters
2015 General Rate Case
In January 2015, SCE updated its forecasted 2015 base rate revenue requirement request to $5.713 billion, which would be an $80 million increase over currently authorized base rate revenue. The updated base rate revenue requirement request also proposed post-test year increases in 2016 and 2017 of $286 million and $315 million, respectively. The original request, filed in November 2013, included a 2015 base rate revenue requirement request of $6.462 billion, which was subsequently reduced to remove costs related to Four Corners and San Onofre, as directed by the ALJs assigned to the GRC and reflect changes after SCE's rebuttal testimony.
The ORA, recommended that SCE's originally requested 2015 base rate revenue requirement be decreased by approximately $607 million, comprised of approximately $302 million in operations and maintenance expense reductions and approximately $305 million in capital-related revenue requirement reductions. TURN recommended that SCE's originally requested 2015 base rate revenue requirements be decreased by approximately $412 million, comprised of approximately $131 million in operations and maintenance expense reductions and approximately $281 million in capital-related revenue requirement reductions. TURN's recommendation also included a reduction in revenue requirement related to income tax repair deductions that originated during the period 2012 – 2014.
A final 2015 GRC decision is not expected until later in 2015. SCE expects to recognize revenue based on the 2014 authorized revenue requirement until a GRC decision is issued. The CPUC has approved the establishment of a GRC memorandum account, which will make the 2015 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2015. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or provide assurance on the timing of a final decision.
Cost of Capital
In December 2014, the CPUC granted a one-year extension of the date to April 2016 when SCE must file the next cost of capital mechanism application, due to the stability of interest rates since the last cost of capital filing in 2012. As a result, SCE's current authorized cost of capital mechanism is extended through 2016, subject to the trigger mechanism.
The cost of capital trigger mechanism provides for an automatic annual adjustment to SCE's authorized cost of capital in September if the utility bond index changes beyond certain thresholds. The adjustment would apply to the following calendar year. The return on common equity will remain at 10.45% for 2015 and 2016, subject to any index changes that exceed the thresholds for 2016.
Edison International Dividend Policy
In December 2014, Edison International declared a 17.6% increase to the annual dividend rate from $1.42 per share to $1.67 per share. Edison International plans to increase its dividends to common shareholders to its target payout ratio of approximately 45% to 55% of SCE earnings in steps over time.
Permanent Retirement of San Onofre and San Onofre OII Settlement
Replacement steam generators were installed at San Onofre in 2010 and 2011. On January 31, 2012, a leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. The Unit was safely taken off-line and subsequent inspections revealed excessive tube wear. Unit 2 was off-line for a planned outage when areas of unexpected tube wear were also discovered. On June 6, 2013, SCE decided to permanently retire and decommission Units 2 and 3.
Settlement of San Onofre CPUC Proceedings
In October 2012, the CPUC issued an OII that consolidated all San Onofre issues in related CPUC regulatory proceedings to consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, substitute market power costs, capital expenditures, and operation and maintenance costs.
On November 20, 2014, the CPUC approved the Amended and Restated Settlement Agreement (the "San Onofre OII Settlement Agreement") that SCE had entered into with TURN, the ORA, SDG&E, the Coalition of California Utility Employees, and Friends of the Earth (together, the "Settling Parties"). The San Onofre OII Settlement Agreement resolved the CPUC's OII and related proceedings regarding the Steam Generator Replacement Project at San Onofre and the related outage and subsequent shutdown of San Onofre. The San Onofre OII Settlement Agreement does not affect proceedings related to recoveries from third parties described below, but does describe how shareholders and customers will share any

6




potential recoveries. SCE has recorded the effects of the San Onofre OII Settlement Agreement. Such amounts do not reflect any recoveries from third parties by SCE.
A lawsuit challenging the CPUC's authority to permit rate recovery of San Onofre costs and an application for rehearing of the CPUC’s decision approving the San Onofre OII Settlement Agreement were filed in November and December 2014, respectively. On February 9, 2015, SCE filed in the 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 response, the Alliance for Nuclear Responsibility, one of the intervenors in the OII, filed an application requesting that the CPUC institute an investigation into whether sanctions should be imposed on SCE in connection with the ex parte communication. The application requests that the CPUC order SCE to produce all ex parte communications between SCE and the CPUC or its staff since January 31, 2012 and all internal SCE unprivileged communications that discuss such ex parte communications.
Third-Party Recoveries
San Onofre carries accidental property damage and carried accidental outage insurance issued by NEIL and has placed NEIL on notice of claims under both policies. For further discussion of potential NEIL insurance recoveries and how they would be shared with customers and SCE, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—San Onofre Related Matters."
SCE is also pursuing claims against MHI, which designed and supplied the RSGs. In October 2013, SCE sent MHI a formal request for binding arbitration under the auspices of the International Chamber of Commerce in accordance with the purchase contract seeking damages for all losses. In the request for arbitration, SCE alleges contract and tort claims and seeks at least $4 billion in damages on behalf of itself and its customers and in its capacity as Operating Agent for San Onofre. MHI has denied any liability and has asserted counterclaims for $41 million, for which SCE has denied any liability. The other
co-owners (SDG&E and Riverside) have been added as additional claimants in the arbitration, with party status. For further discussion of potential recoveries from MHI and how they would be shared with customers, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—San Onofre Related Matters."
Rate Impacts
Due to the implementation of the settlement as of December 31, 2014, including the refund of revenue related to the Steam Generator Replacement Project, the refund of the difference between authorized and recorded operation and maintenance expenses for 2013 and 2014, the refund from the reduction of returns on the balance of its San Onofre investment and the other elements of the settlement will result in a refund to customers of approximately $540 million. Such refunds under the San Onofre OII Settlement Agreement were effectuated through a reduction in SCE's ERRA undercollection. At December 31, 2014, SCE's ERRA undercollection was $1.03 billion. The ERRA undercollection is expected to continue to decrease during 2015 assuming:
approval of SCE's request to classify the majority of costs incurred at San Onofre since June 7, 2013 as decommissioning costs and provide reimbursement from SCE's nuclear decommissioning trust; and
approval of SCE's 2015 ERRA forecast application, with implementation of revised rates occurring during the first quarter of 2015.
These decreases will be impacted by over/undercollection of purchased power and fuel costs during 2015, including changes in natural gas and power prices.
SCE may finance unrecovered power procurement-related costs with commercial paper or other borrowing, subject to availability in the capital markets. Delays in approval of rate increases to recover undercollection of fuel and purchase power costs would adversely impact SCE's liquidity. For further information on 2015 ERRA forecast application, see "Liquidity—Regulatory Proceedings—ERRA Forecast Filing – 2015."

7




NRC Proceedings
For information on the NRC proceedings, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—San Onofre Related Matters."
Decommissioning
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. On September 23, 2014, SCE submitted its Post-Shutdown Decommissioning Activities Report ("PSDAR"), Irradiated Fuel Management Plan and Decommissioning Cost Estimate for San Onofre, Units 2 and 3 to the NRC. These submittals were subject to a ninety-day period for NRC review and acceptance, which expired on December 27, 2014. SCE is now 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 – $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 estimates including the cost of burial 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. SCE's share of the present value of decommissioning costs using current discount rates was $3.0 billion at December 31, 2014. 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 $3.4 billion as of December 31, 2014. 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 must issue an order granting prior approval for withdrawal of decommissioning trust funds. SCE has filed a request with the CPUC to authorize release of trust funds for costs up to a specified cost cap of $214 million to cover SCE's share of 2013 decommissioning costs. The request also seeks CPUC approval for a process by which SCE will be able to seek the release of trust funds to cover decommissioning costs incurred in 2014 and future periods until the CPUC approves a permanent San Onofre decommissioning plan and cost recovery mechanism.
Depending on the ultimate interpretation of IRS regulations, which address the taxation of a qualified nuclear decommissioning trust, SCE may be restricted from withdrawing amounts from the qualified decommissioning trusts to pay for independent spent fuel storage installation ("ISFSI") where SCE is seeking, or plans to seek, recovery of the ISFSI costs in litigation against the DOE. For further information, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—Spent Nuclear Fuel." SCE intends to participate as part of an industry coalition in working with the IRS and the Department of Treasury to pursue an interpretation of the IRS regulations that is consistent with Congress’ intent when this tax provision was enacted by Congress in 1984. If SCE is unable to obtain timely reimbursement of such costs, it may delay decommissioning activities. Furthermore, expenditures incurred are expected to be funded by SCE until such time as a favorable determination is made or the DOE litigation for such period is resolved. For further information, see "Risk Factors—Risk Factors Relating to SCE—Operating Risks."
Decommissioning costs incurred in 2013 and 2014 have been recorded as operations and maintenance expenses pending the CPUC decision on access to the trusts for reimbursement. Accordingly, such costs have been recovered through GRC revenues. Costs incurred for 2013 have been found reasonable under the San Onofre OII. The CPUC will conduct a reasonableness review for 2014 costs and years going forward. Beginning in 2015, SCE must fund decommissioning costs until the CPUC approves SCE's request to access the trust funds. Currently, SCE expects that the CPUC would approve access to the trust in 2015. SCE's share of the estimated decommissioning costs to be incurred in 2015, subject to change, are approximately $200 million.

8




Resolution of Uncertainty Related to EME in Bankruptcy
In February 2014, Edison International, EME and the Consenting Noteholders entered into a settlement agreement (the "EME Settlement Agreement") pursuant to which EME amended its Plan of Reorganization to incorporate the terms of the EME Settlement Agreement, including extinguishing all existing claims between EME and Edison International. The Amended Plan of Reorganization, including the EME Settlement Agreement, was completed on April 1, 2014.
Under the EME Settlement Agreement, Edison International made the first of three cash payments to the Reorganization Trust of $225 million in April 2014. In August 2014, Edison International entered into an amendment of the Settlement Agreement that finalized the remaining matters related to the EME Settlement including setting the amount of the two remaining installment payments, including interest, at $204 million due on September 30, 2015 and $214 million due on September 30, 2016. As a result of the EME Settlement Agreement, Edison International recorded, as part of discontinued operations, income of $168 million during the year ended December 31, 2014 related to changes in estimates of the net impact of retaining income tax attributes less the above payment obligations and assumed liabilities. See "Notes to Consolidated Financial Statements—Note 15. Discontinued Operations." As part of the settlement, Edison International retained ownership interest of EME and tax attributes of approximately $1.2 billion. Edison International expects to realize the tax attributes over time, depending upon the tax position of Edison International.

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.
The following table is a summary of SCE's results of operations for the periods indicated.
 
2014
2013
2012
(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
$
6,831

$
6,549

$
13,380

$
6,602

$
5,960

$
12,562

$
6,682

$
5,169

$
11,851

Purchased power and fuel

5,593

5,593


4,891

4,891


4,139

4,139

Operation and maintenance
2,106

951

3,057

2,348

1,068

3,416

2,518

1,026

3,544

Depreciation, decommissioning and amortization
1,720


1,720

1,622


1,622

1,562


1,562

Property and other taxes
318


318

307


307

296

(1
)
295

Impairment and other charges
163


163

575


575

32


32

Total operating expenses
4,307

6,544

10,851

4,852

5,959

10,811

4,408

5,164

9,572

Operating income
2,524

5

2,529

1,750

1

1,751

2,274

5

2,279

Interest expense
(528
)
(5
)
(533
)
(519
)
(1
)
(520
)
(494
)
(5
)
(499
)
Other income and expenses
43


43

48


48

94


94

Income before income taxes
2,039


2,039

1,279


1,279

1,874


1,874

Income tax expense
474


474

279


279

214


214

Net income
1,565


1,565

1,000


1,000

1,660


1,660

Preferred and preference stock dividend requirements
112


112

100


100

91


91

Net income available for common stock
$
1,453

$

$
1,453

$
900

$

$
900

$
1,569

$

$
1,569

Core earnings1
 
 
$
1,525

 
 
$
1,265

 
 
$
1,338

Non-core earnings
 
 


 
 


 
 


Impairment and other charges
 
 
(72
)
 
 
(365
)
 
 

2012 General Rate Case – repair deductions (2009 – 2011)
 
 

 
 

 
 
231

Total SCE GAAP earnings


 
$
1,453

 
 
$
900

 
 
$
1,569

1 
See use of non-GAAP financial measures in "Management Overview—Highlights of Operating Results."

10




Utility Earning Activities
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 Unit 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."

11




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 income statements.
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.
2013 vs 2012
Utility earning activities were primarily affected by the following:
Lower operating revenue of $80 million was primarily due to the following:
A decrease in San Onofre-related estimated revenue of $303 million primarily due to lower operating costs, no longer recognizing the return on San Onofre rate base and ceasing depreciation, beginning in June 2013.
An increase in CPUC-related revenue of $60 million primarily related to the increase in authorized revenue to support rate base growth and operating expenses which was partially offset by the lower CPUC-adopted 2013 return on common equity and Edison SmartConnect® revenue, resulting from the full deployment of the program in 2012.
An increase in FERC-related revenue of $170 million primarily related to rate base growth and higher operating costs.
Energy efficiency earnings were $14 million in 2013 compared to $15 million in 2012.

12




Lower operation and maintenance expense of $170 million was primarily due to the following:
A decrease in San Onofre-related expense of $170 million primarily due to lower operating costs of $109 million resulting from the early retirement of Units 2 and 3 in June 2013 and $35 million in 2012 related to the scheduled outage at Unit 2. In addition, SCE had lower incremental inspection and repair costs of $53 million (net of SCE's share of payments received from MHI in 2012), which were not offset in revenue above. These factors were partially offset by additional severance costs of $27 million ($63 million and $36 million in 2013 and 2012, respectively).
A decrease of $95 million in expense in 2013 due to the full deployment of the Edison SmartConnect® program in 2012.
A decrease in severance costs of $40 million due to the reductions in workforce (excluding San Onofre) that commenced in 2012.
An increase of $85 million of higher operating costs primarily related to information technology, safety, legal and insurance costs.
$45 million of planned outage costs at Mountainview, repair costs at Four Corners, and higher operating costs on CPUC- and FERC-related projects.
Higher depreciation, decommissioning and amortization expense of $60 million was primarily related to increased transmission and distribution investments, including capitalized software costs, offset by the impact of $67 million from ceasing depreciation on the San Onofre assets, beginning in June 2013.
$575 million impairment charge ($365 million after-tax) in 2013 related to the permanent retirement of San Onofre Units 2 and 3.
Lower interest income and other of $46 million primarily due to lower AFUDC equity related to lower rates and construction work in progress balances in 2013. In addition, SCE had higher other expenses due to a $20 million penalty that resulted from the Malibu Fire Order Instituting Investigation settlement that was imposed by the CPUC in 2013. See "Notes to Consolidated Financial Statements—Note 14. Interest and Other Income and Other Expenses."
Higher interest expense of $25 million primarily due to higher balances on long-term debt to support rate base growth and lower AFUDC debt due to lower rates and construction work in progress balances in 2013.
Higher income taxes of $65 million primarily due to lower income tax benefits, including lower repair deductions (as determined for income tax purposes). See "—Income Taxes" below for more information.
Utility Cost-Recovery Activities
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.

13




2013 vs 2012
Utility cost-recovery activities were primarily affected by the following:
Higher purchased power and fuel expense of $752 million was primarily driven by higher power and gas prices in 2013, partially offset by lower realized losses on economic hedging activities ($56 million in 2013 compared to $227 million in 2012) and by a $43 million credit received from the ISO for SCE’s share of a settlement between the FERC and an ISO participant. Fuel costs were $324 million in 2013 and $308 million in 2012.
Higher operation and maintenance expense of $42 million primarily due to costs for the GHG cap-and-trade program related to utility owned generation, higher costs related to transmission and distribution expenses, higher pension expenses, partially offset by lower spending on various public purpose programs.
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $12.2 billion for 2014, $11.6 billion for 2013 and $11.2 billion for 2012.
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.
The 2013 revenue reflects:
An increase of $435 million and a sales volume decrease of $29 million. The increase is primarily due to the implementation of the 2012 GRC decision.
The 2012 revenue reflects:
A sales volume increase of $1.4 billion, primarily due to SCE providing power that was previously provided by California Department of Water Resources (CDWR) contracts partially offset by:
A decrease of $344 million, resulting from rate adjustments in June 2011 and August 2012, primarily reflecting lower natural gas prices and refunds to customers of overcollected fuel and power procurement-related costs recorded through the ERRA balancing account.
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 $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.
SCE’s income tax provision increased by $65 million in 2013 compared to 2012. The effective tax rates were 21.8% and 11.4% for 2013 and 2012, respectively. The effective tax rate increase in 2013 was primarily due to lower tax benefits associated with repair deductions as discussed below.
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.
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.

14




Earnings Benefit from Repair Deductions
Edison International made a voluntary election in 2009 to change its tax-accounting method for certain repair costs incurred on SCE's transmission, distribution and generation assets. Regulatory treatment for the incremental deductions taken after the 2009 election to change SCE's tax accounting method for certain repair costs was included as part of SCE's 2012 GRC. The 2012 GRC decision retained flow-through treatment of repair deductions for regulatory purposes, which resulted in SCE recognizing an earnings benefit of $231 million from these incremental deductions taken in 2009, 2010 and 2011. Incremental repair deductions represent amounts recognized for regulatory accounting purposes in excess of amounts included in the authorized revenue requirements through the general rate case proceedings. The earnings benefit results from recognition of a regulatory asset for recovery of deferred income taxes in future periods. Incremental repair deductions for the years 2012 – 2014 resulted in additional income tax benefits of $133 million in 2014, $89 million in 2013 and $115 million in 2012.
For a discussion of the status of Edison International's income tax audits, see "Notes to Consolidated Financial Statements—Note 7. Income Taxes."
Edison International Parent and Other
Results of operations for Edison International Parent and Other includes amounts from other nonutility 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)
2014
 
2013
 
2012
Edison Energy and subsidiaries
$
(5
)
 
$
(3
)
 
$

Edison Mission Group and subsidiaries
36

 
24

 
19

Corporate expenses and Other
(57
)
 
(42
)
 
(85
)
Total Edison International Parent and Other
$
(26
)
 
$
(21
)
 
$
(66
)
The loss from continuing operations of Edison International Parent and Other increased $5 million in 2014 due to:
An increase in the loss of Edison International Parent and Other primarily due to higher corporate expenses.
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. EMG’s subsidiary, Edison Capital, continues to wind down its remaining affordable housing investments. Earnings from Edison Capital were $34 million in 2014 and $24 million in 2013.
A slight increase in losses of Edison Energy. Edison Energy and subsidiaries' 2014 operating activities primarily relate to construction of 26 megawatts of solar rooftop projects, including projects that will sell their output to third parties under long-term power sales agreements.
The loss from continuing operations of Edison International Parent and Other decreased $45 million in 2013 due to:
Higher losses in 2012 due to a $37 million charge resulting from Edison International's update to its estimated long-term California apportionment rate applicable to deferred income taxes as a result of changes related to EME.
The results for EMG include earnings from Edison Capital of $24 million in 2013 and $22 million in 2012. Edison Capital's 2013 results included income from the wind down of its asset portfolio while Edison Capital's 2012 results included higher income taxes. In addition, during 2012, Edison Capital sold its lease interest in Unit No. 2 of the Beaver Valley Nuclear Plant resulting in a $31 million benefit in 2012 and an additional income tax benefit of $7 million in 2013 from a revised estimate of state income taxes related to the sale. The results for EMG in 2012 also include a write-down of an investment.

15




Income (Loss) from Discontinued Operations (Net of Tax)
Income (loss) from discontinued operations, net of tax, was $185 million, $36 million and $(1.69) billion for the years ended December 31, 2014, 2013 and 2012, respectively. The 2014 income reflects earnings of $168 million due to the completion of the Amended Plan of Reorganization, including transactions recorded in 2014 associated with the sale of substantially all of EME's assets to NRG Energy, Inc. and other transactions called for in the EME Settlement Agreement. The 2014 income also includes income tax benefits of $39 million from resolution of uncertain tax positions from settlement of 2003 – 2006 tax years with the IRS and other impacts related to EME. In addition, discontinued operations reflect an income tax loss of $22 million in 2014 compared to a benefit of $36 million in 2013 from revised estimates of the tax impact of a tax deconsolidation of EME from Edison International as originally contemplated prior to the EME Settlement.
The 2012 loss reflects an earnings charge of $1.3 billion due to the full impairment of the investment in EME during the fourth quarter of 2012 as a result of the deconsolidation of EME, recognition of losses previously deferred in accumulated other comprehensive income, a provision for losses from the EME bankruptcy and estimated tax impacts related to the tax deconsolidation and separation of EME from Edison International. The 2012 loss also reflects a $53 million earnings charge associated with the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. For additional information, see "Notes to Consolidated Financial Statements—Note 15. Discontinued Operations."
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 2015 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 requirements.
The Tax Increase Prevention Act of 2014 extended 50% bonus depreciation for qualifying property retroactive to January 1, 2014 and through 2015 for certain long production period property. This extension is expected to benefit cash flow in 2015 as SCE utilizes net operating losses to reduce tax liabilities. The impact on cash flow represents an acceleration of tax benefits that would have otherwise been deductible over the life of the qualifying assets.
Available Liquidity
At December 31, 2014, SCE had $2.27 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 unrecovered power procurement-related costs as well as other 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.
In January 2015, SCE issued $550 million of 1.845% amortizing first and refunding mortgage bonds due in 2022, $325 million of 2.40% first and refunding mortgage bonds due in 2022, $425 million of 3.6% first and refunding mortgage bonds due in 2045. The amortizing first and refunding mortgage bonds have been designated as a financing of the San Onofre regulatory asset. The proceeds were used to repay outstanding debt and for general corporate purposes.
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, 2014, SCE's debt to total capitalization ratio was 0.44 to 1.

16




Capital Investment Plan
SCE forecasts capital expenditures for 2015 – 2017 in the range of $11.8 billion to $13.4 billion. The high end of the range reflects the requested level of spending in the GRC and other CPUC proceedings. The low end of the range reflects a 12% reduction from requested levels using management judgment based on historical experience. 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.
SCE's 2014 actual capital expenditures (including accruals) and the 2015 – 2017 forecast for major capital expenditures are set forth in the table below:
(in millions)
 
2014
Actual
2015
2016
2017
2015 – 2017 Total
Transmission
 
$
888

$
785

$
1,323

$
1,238

$
3,346

Distribution
 
2,871

3,095

3,217

3,085

9,397

Generation
 
208

215

226

202

643

Total estimated capital expenditures1
 
$
3,967

$
4,095

$
4,766

$
4,525

$
13,386

Total estimated capital expenditures for 2015 – 2017 (using the range discussed above)
 
 
$
3,604

$
4,194

$
3,981

$
11,779

1 
Included in SCE's capital expenditures plan are projected environmental capital expenditures of approximately 15% for each year presented. The projected environmental capital expenditures are to comply with laws, regulations, and other nondiscretionary requirements.
Capital expenditures for projects under CPUC jurisdiction are recovered through the authorized revenue requirement in SCE's general rate cases or through other CPUC-authorized mechanisms. Recovery of planned capital expenditures for projects under CPUC jurisdiction for 2015 through 2017 are subject to the outcome of the 2015 GRC or other CPUC approvals. Recovery for 2015 – 2017 planned expenditures for projects under FERC jurisdiction will be pursued through FERC-authorized mechanisms.
Transmission Projects
A summary of SCE's large transmission and substation projects during the next three years is presented below:
Project Name
Project Lifecycle Phase
Scheduled in Service Date
Direct Expenditures1(in millions)
2015 – 2017 Forecast (in millions)
Tehachapi 4-11
In construction
2016 – 2017
$
2,430

$
500

West of Devers
In licensing
2019 – 2020
1,034

542

Coolwater-Lugo
In licensing
2018
740

602

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 2015 – 2017.
Tehachapi Project
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 2015 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

17




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 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 total maximum cost estimate to determine public need in 2013 of as much as $2.2 billion to $2.3 billion. Because SCE has not completed final engineering on all aspects of segments 4-11, SCE has not yet filed a petition for modification with the CPUC for the current 2014 cost estimate of $2.7 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 Project
West of Devers Project will upgrade 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.
Coolwater-Lugo Transmission Project
The Coolwater-Lugo Project will provide additional 220 kV transmission capacity needed in the Kramer Junction and Lucerne Valley areas of San Bernardino County to alleviate an existing bottleneck in order to facilitate interconnection of current and future renewable generation projects. The Coolwater-Lugo scope primarily consists of installing new transmission lines and new substation facilities. The operator of the Coolwater Generating Station has informed the CPUC of its intent to permanently retire the station. Under the CAISO's tariff, the operator will retain deliverability priority to the existing line for a period of at least three years, absent the commitment by the operator not to repower or restart the station. SCE believes it would be premature to delay licensing. However should the operator commit to not repower or restart the station, the capacity on the lines would become available to other generators. In addition, the upcoming CAISO deliverability reassessment study could affect the need for this project. SCE has obtained FERC approval for abandoned plant cost recovery in the event the project is not completed.
Competitive Transmission Projects
SCE no longer has a federally-based right to construct certain of the new transmission facilities in its service territory and must competitively bid on such projects. In January 2015, the CAISO reported that SCE was one of six bidders that it will consider to build and own the Delaney Colorado River transmission project. The CAISO estimated that the project will cost approximately $300 million, which is not included in the table above. SCE expects a CAISO decision on the project award in the second half of 2015. For more information on transmission infrastructure competition, see "Business—SCE—Competition."
Distribution Projects
Distribution expenditures include projects and programs to meet reliability, infrastructure replacement (including replacement of poles to meet current compliance and safety standards), customer load growth requirements, information and other technology and related facility requirements (sometimes referred to as "general plant").
Generation Projects
Generation expenditures include maintenance-related capital expenditures associated with Palo Verde and SCE's hydroelectric and gas-fired generation infrastructure and renewal of FERC operating licenses. Infrastructure expenditures include dam improvements, flowline and substation refurbishments, and powerline replacements. Equipment replacement expenditures include transformers, automation, switchgear, hydro turbine repowers, generator rewinds, and small generator replacements.
Regulatory Proceedings
Energy Efficiency Incentive Mechanism
In December 2014, the CPUC awarded SCE an incentive of $22 million for the 2012 and 2013 energy efficiency program years. The CPUC has not completed its assessment of energy efficiency fixed price contract cost accounting practices which could result in additional earnings of $6.2 million for the 2011 and 2012 program years. There is no assurance that the CPUC will make an award for any given year.

18




In November 2014, TURN and the ORA filed separate petitions with the CPUC asking for the rescission of the CPUC's December 2010 energy efficiency decision that awarded the California investor-owned utilities incentive awards, including a final, trued up incentive payment of $24.1 million to SCE for savings achieved by its 2006 – 2008 energy efficiency programs. Prior CPUC decisions had awarded SCE $50.4 million 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. It is currently uncertain how these petitions will be considered by the CPUC.
FERC Formula Rates
In November 2014, SCE filed its 2015 annual update with the FERC with the rates effective from January 1, 2015 to December 31, 2015. The update provided support for an increase in SCE's transmission revenue requirement of $89 million or 10.8% over amounts currently authorized in rates. The primary reason for the increase is the inclusion of costs associated with several large transmission projects that were completed in 2013, including Devers-Colorado River, Eldorado-Ivanpah, and the Red Bluff substation.
ERRA Forecast Filing 2015
Rates related to fuel and purchased power are set annually based on a forecast of the costs SCE expects to incur in the following year. Actual fuel and power costs that are either greater or less than the forecast are tracked in the ERRA balancing account and collected from or refunded to customers in subsequent periods depending upon whether the balancing account is under collected or over collected. In December 2014, the CPUC issued a proposed decision on SCE's 2015 ERRA forecast application adopting an annual revenue requirement of $5.59 billion, an increase of approximately $437 million over the 2014 revenue requirement. SCE expects to implement this requirement in rates in the first half of 2015.
Energy Storage Requirements
In October 2013, the CPUC issued a decision adopting policies and targets for energy storage procurement. Under the Energy Storage Procurement Framework and Design Program, SCE is required to procure a total of 580 MW (of the 1,325 total MW for the three California investor-owned utilities) of energy storage by 2020 and to install and deliver the storage to the electric grid by the end of 2024. SCE may request deferment of up to 80% of its procurement targets if it can show unreasonableness of cost or lack of an operationally viable number of bids in the solicitations. SCE is required to launch competitive solicitations in 2014, 2016, 2018, and 2020. SCE is also required to file an application for procuring the specified energy storage resources before each procurement cycle and solicitation. SCE's first Energy Storage Procurement Application was filed on March 1, 2014 and its first energy storage solicitation was launched on December 1, 2014. In October 2014, the CPUC issued a decision allowing the overall energy storage procurement target to be reduced by energy storage that is procured in other solicitations or developed by the utilities. The decision reduced SCE's original target for the 2014 energy storage solicitation from a 90 MW minimum to 16.3 MW, by crediting SCE for 50 MW of transmission-interconnected, 13.68 MW of distribution-interconnected, and 10 MW of customer-side energy storage capacity.
SCE Dividends
During 2014, SCE made $378 million in dividend payments to its parent, Edison International. 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, 2014, 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.

19




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, 2014.
(in millions)
 
 
Collateral posted as of December 31, 20141
 
$
208

Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade
 
112

Posted and potential collateral requirements2
 
$
320

1 
Net collateral provided to counterparties and other brokers consisted of $61 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $36 million of cash reflected in "Other current assets" on the consolidated balance sheets and $111 million in letters of credit and surety bonds.
2 
SCE's total posted and potential collateral requirements may increase by $41 million based on SCE's forward positions as of December 31, 2014 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, 2014, SCE had regulatory balancing account net over-collections of $331 million, primarily consisting of $1.36 billion of overcollections related to public purpose-related and energy efficiency program costs, GHG auction revenue and generator settlements. Over-collections for public purpose-related programs are expected to decrease as costs are incurred to fund programs established by the CPUC. Generator settlements over-collections are expected to be refunded through a rate adjustment in 2015. The overcollections were partially offset by under-collections of $1.03 billion related to fuel and power procurement-related costs. See "Management Overview—Permanent Retirement of San Onofre and San Onofre OII Settlement" for a discussion of the ERRA undercollection. See "Notes to Consolidated Financial Statements—Note 10. Regulatory Assets and Liabilities" for further information.
Edison International Parent and Other
Edison International Parent and Other's liquidity and its ability to pay operating expenses and dividends to common shareholders are dependent on dividends from SCE and access to bank and capital markets. At December 31, 2014, Edison International had $631 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 0.48 to 1 at December 31, 2014.
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 is obligated to make payments of $204 million on September 30, 2015 and $214 million on September 30, 2016. Edison International intends to make these payments from realization of state tax benefits or issuance of commercial paper or other borrowings. Edison International has $1.1 billion of net operating loss and tax credit carryforwards at December 31, 2014 retained by EME which are available to offset future consolidated taxable income or tax liabilities. As a result of the extension of 50% bonus depreciation for qualifying property under the Tax Increase Prevention Act of 2014, realization of these tax benefits has been deferred (currently forecasted through 2018). 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 in the event that tax reform decreased the current corporate tax rate.

20




Edison Energy Subsidiary Financings
During the third quarter of 2014, indirect subsidiaries of Edison Energy entered into three non-recourse debt and tax equity financings designed to fund a portion of their capital requirements for approximately 35 megawatts of solar rooftop projects. The projects are expected to sell their output to third parties under long-term power purchase agreements with terms ranging from 15 to 20 years. Completion of the construction phase of these projects is expected by mid-2015, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
Historical Cash Flows
SCE
(in millions)
2014
 
2013
 
2012
Net cash provided by operating activities
$
3,660

 
$
3,048

 
$
4,086

Net cash provided by financing activities
181

 
508

 
256

Net cash used by investing activities
(3,857
)
 
(3,547
)
 
(4,354
)
Net increase (decrease) in cash and cash equivalents
$
(16
)
 
$
9

 
$
(12
)
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 2014, 2013 and 2012.
 
Years ended December 31,
 
Change in cash flows
(in millions)
2014
2013
2012
 
2014/2013
2013/2012
Net income
$
1,565

$
1,000

$
1,660

 

 
Non cash items1
2,381

2,631

1,911

 
 
 
    Subtotal
$
3,946

$
3,631

$
3,571

 
$
315

$
60

Changes in cash flow resulting from working capital2
79

(182
)
346

 
261

(528
)
Derivative assets and liabilities, net
(40
)
(30
)
(86
)
 
(10
)
56

Regulatory assets and liabilities, net
(358
)
(322
)
34

 
(36
)
(356
)
Other noncurrent assets and liabilities, net
33

(49
)
221

 
82

(270
)
Net cash provided by operating activities
$
3,660

$
3,048

$
4,086

 
$
612

$
(1,038
)
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.
Net income and non cash items increased in 2014 by $315 million from 2013 and increased in 2013 by $60 million from 2012. The increase in both periods was primarily due to rate base growth. The factors that impacted these items are discussed under "Results of Operations—SCE—Utility Earning Activities." In 2012, SCE recognized $231 million of additional tax benefits related to repair deductions resulting from the 2012 GRC which are reflected in net income and an increase in regulatory assets.
Changes in cash flows related to working capital items increased in 2014 by $261 million and decreased by $528 million from 2012. In 2014, SCE had net tax refunds of approximately $88 million, compared to net tax payments of $28 million in 2013 and net tax refunds of $279 million in 2012. The refunds in 2014 and 2012 were due to net operating loss carrybacks to periods that SCE previously had taxable income. In 2014 and 2013, SCE had severance payments of $22 million and $151 million, respectively, related to the workforce reductions. During 2012, SCE had proceeds of $68 million from U.S. Treasury grants.
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.

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While some balancing accounts are discrete, (for example, the Four Corners memorandum account related to the sale of SCE's interest or the generator settlements), other balancing accounts are ongoing with changes generally collected in the following year. During 2014 and 2013, cash flows were lower, whereas in 2012 cash flows were higher due to the impact of regulatory assets and liabilities. The impact on cash flow from the two principal balancing accounts are:
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 (see "—Regulatory Proceedings—ERRA Forecast Filing – 2015" above). In 2012, SCE had ERRA overcollections of $135 million. 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 $5 million and $247 million in 2014 and 2013, respectively, and undercollections of $505 million in 2012. 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. During 2012, the BRRBA account decreased cash flows by $267 million primarily due to the delay in the 2012 GRC decision which was not received until November 2012.
Cash flows provided (used) by other noncurrent assets and liabilities were $33 million, $(49) million and $221 million in 2014, 2013 and 2012, respectively. Major factors affecting cash flow related to non-current assets and liabilities were activities related to SCE's nuclear decommissioning trusts and settlements relating to injuries and damages.
Net Cash Provided by Financing Activities
The following table summarizes cash provided by financing activities for 2014, 2013 and 2012. 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)
2014
 
2013
 
2012
Issuances of first and refunding mortgage bonds, net
$
498

 
$
1,973

 
$
391

Payments of senior notes
(600
)
 
(820
)
 
(6
)
Net increases (decreases) in short-term borrowings, net
490

 
(1
)
 
(250
)
Issuances of preference stock, net
269

 
387

 
804

Payments of common stock dividends to Edison International
(378
)
 
(486
)
 
(469
)
Redemptions of preference stock

 
(400
)
 
(75
)
Bonds remarketed, net

 
195

 

Bonds purchased

 
(196
)
 

Payments of preferred and preference stock dividends
(111
)
 
(101
)
 
(82
)
Settlement of stock-based awards (facilitated by a third party)
(188
)
 
(137
)
 
(103
)
Other
201

 
94

 
46

Net cash provided by financing activities
$
181

 
$
508

 
$
256

Net Cash Used by Investing Activities
Cash flows from investing activities are primarily due to capital expenditures and investing activities of the nuclear decommissioning trusts. Amounts paid for capital expenditures were $3.9 billion for 2014, $3.6 billion for 2013 and $4.1 billion for 2012, primarily related to transmission, distribution and generation facilities. Net purchases of nuclear decommissioning trusts' investments were $44 million, $98 million and $215 million for 2014, 2013 and 2012, respectively. See "Nuclear Decommissioning Trusts" below for further discussion. 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 received.

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)

2014
2013
2012
Net cash provided by operating activities:
   Nuclear decommissioning trusts
$
39

$
76

$
192

Net cash flow from investing activities:
   Proceeds from sale of investments
10,079

5,617

2,122

   Purchases of investments
(10,123
)
(5,715
)
(2,337
)
Net cash impact
$
(5
)
$
(22
)
$
(23
)
Net cash provided by operating activities of the nuclear decommissioning trusts relate to interest and dividends less administrative expenses, taxes and decommissioning costs. Such activities represent the source (use) of the funds for investing activities. The net cash impact represents the contributions made by SCE, as collected through rates, to the nuclear decommissioning trusts. In future periods, SCE expects decommissioning costs of San Onofre to increase significantly. Such amounts will 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. Other Investments" for further information.
Edison International Parent and Other
The table below sets forth condensed historical cash flow from continuing operations for Edison International Parent and Other.
(in millions)
2014
 
2013
 
2012
Net cash used by operating activities
$
(412
)
 
$
(81
)
 
$
(115
)
Net cash provided by financing activities
464

 
73

 
20

Net cash provided (used) by investing activities
(50
)
 
(25
)
 
108

Net increase (decrease) in cash and cash equivalents
$
2

 
$
(33
)
 
$
13

Net Cash Used by Continuing Operating Activities
Net cash from continuing operating activities decreased $331 million in 2014 compared to 2013 due to:
$225 million initial cash payment to the Reorganization Trust in April 2014 related to the EME Settlement Agreement, see "Management Overview—Resolution of Uncertainty Related to EME in Bankruptcy" for further information;
Net payments of $120 million to the IRS, which included a $189 million deposit related to open tax years 2003 through 2006; and
The timing of payments and receipts relating to interest and operating costs.
Net cash from continuing operating activities increased $34 million in 2013 compared to 2012 primarily due to the timing of payments and receipts relating to interest, operating costs and income taxes.
Net Cash Provided by Continuing Financing Activities
Net cash provided by continuing financing activities were as follows:
(in millions)
 
2014
 
2013
 
2012
Dividends paid to Edison International common shareholders
 
$
(463
)
 
$
(440
)
 
$
(424
)
Dividends received from SCE
 
378

 
486

 
469

Debt financing, net1
 
589

 
33

 
(15
)
1  
Includes $5.1 million debt financing for Edison Energy, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Project Financings."

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Net Cash Provided (Used) by Continuing Investing Activities
Net cash used by continuing investing activities during 2014 relate to Edison Energy's capital expenditures of $49 million.
Net cash provided by continuing investing activities during 2013 relate to Edison International's investment of $25 million in equity interests of competitive energy-related businesses, including the acquisition of SoCore Energy LLC, a distributed solar developer focused on commercial rooftop installations.
Contractual Obligations and Contingencies
Contractual Obligations
Edison International Parent and Other and SCE's contractual obligations as of December 31, 2014, for the years 2015 through 2019 and thereafter are estimated below.
(in millions)
 
Total
 
Less than
1 year
 
1 to 3 years
 
3 to 5 years
 
More than
5 years
SCE:
 
 
 
 
 
 
 
 
 
 
Long-term debt maturities and interest1
 
$
18,714

 
$
757

 
$
1,764

 
$
1,225

 
$
14,968

Power purchase agreements:2
 
 
 
 
 
 
 
 
 
 
Renewable energy contracts
 
23,399

 
1,009

 
2,277

 
2,373

 
17,740

Qualifying facility contracts
 
969

 
254

 
408

 
238

 
69

Other power purchase agreements
 
4,875

 
830

 
1,453

 
1,088

 
1,504

Other operating lease obligations3
 
623

 
102

 
206

 
114

 
201

Purchase obligations:4
 
 
 
 
 
 
 
 
 
 
Other contractual obligations
 
1,010

 
86

 
221

 
131

 
572

Total SCE5,6
 
49,590

 
3,038

 
6,329

 
5,169

 
35,054

Edison International Parent and Other:
 
 
 
 
 
 
 
 
 
 
Long-term debt maturities and interest1
 
437

 
12

 
425

 

 

EME settlement payments7
 
418

 
204

 
214

 

 

Total Edison International Parent and Other5
 
855

 
216

 
639

 

 

Total Edison International6,8
 
$
50,445

 
$
3,254

 
$
6,968

 
$
5,169

 
$
35,054

1 
For additional details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Amount includes interest payments totaling $8.75 billion and $36 million over applicable period of the debt for SCE and Edison International Parent and Other, respectively.
2 
Certain power purchase agreements entered into with independent power producers are treated as operating or capital leases. For further discussion, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies."
3 
At December 31, 2014, SCE's minimum other operating lease payments were primarily related to vehicles, office space, nuclear fuel storage 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, 2014, other commitments were primarily related to maintaining reliability and expanding SCE's transmission and distribution system.
5 
At December 31, 2014, Edison International Parent and Other and SCE had estimated contributions to the pension and PBOP plans. SCE estimated contributions are $151 million, $156 million and $166 million in 2015, 2016 and 2017, respectively. Edison International Parent and Other estimated contributions are $27 million, $26 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, 2014, Edison International and SCE had a total net liability recorded for uncertain tax positions of $576 million and $441 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 IRS.

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7 
In August 2014, Edison International entered into an amendment of the Settlement Agreement to finalize the remaining matters related to the EME Settlement including setting the amount of the 2 installment payments, see "Notes to Consolidated Financial Statements—Note 15. Discontinued Operations."
8 
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, Four Corners Environmental Matters, 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, operations and maintenance, monitoring and site closure. Unless there is a probable amount, SCE records the lower end of this reasonably likely range of costs (classified as "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
As of December 31, 2014, SCE had identified 20 material sites for remediation and recorded an estimated minimum liability of $108 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
EME has one leveraged lease investment and Edison Capital has investments in affordable housing projects that apply the equity method of accounting. These off-balance sheet transactions are not material to Edison International's consolidated financial statements. SCE has variable interests in power purchase contracts with variable interest entities and a variable interest in unconsolidated Trust I, Trust II and Trust III that issued $475 million (aggregate liquidation preference) of 5.625%, $400 million (aggregate liquidation preference) of 5.10% and $275 million (aggregate liquidation preference) of 5.75%, trust securities, respectively, to the public, see "Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities."
Environmental Developments
For a discussion of environmental developments, see "Business—Environmental Regulation of Edison International and Subsidiaries."
MARKET RISK EXPOSURES
Edison International 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."

25




Interest Rate Risk
Edison International and SCE are exposed to changes in interest rates primarily as a result of its financing and short-term 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 2015, 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, 2014, 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
$
10,738

 
$
12,319

 
$
11,846

 
$
12,828

SCE
9,924

 
11,479

 
11,008

 
11,986

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. SCE's hedging program reduces customer exposure to variability in market prices. 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 $927 million and $821 million at December 31, 2014 and 2013, 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, 2014, if the electricity prices or gas prices were changed while leaving all other assumptions constant:
(in millions)
December 31, 2014
Increase in electricity prices by 10%
$
242

Decrease in electricity prices by 10%
(198
)
Increase in gas prices by 10%
(68
)
Decrease in gas prices by 10%
69

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

26




including master netting agreements. As of December 31, 2014, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:
 
December 31, 2014
(in millions)
Exposure2
 
Collateral
 
Net Exposure
S&P Credit Rating1
 
 
 
 
 
A or higher
$
317

 
$

 
$
317

Not rated3
5

 
(5
)
 

Total
$
322

 
$
(5
)
 
$
317

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.
3 
The exposure in this category relates to long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment.
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.
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, 2014, the consolidated balance sheets included regulatory assets of $8.87 billion and regulatory liabilities of $6.29 billion. If different judgments were reached on recovery of costs and timing of income recognition, SCE's earnings may vary from the amounts reported.

27




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.
A portion of SCE's uncertain tax positions relate to tax deductions that are classified as flow-through items for regulatory purposes, including repair deductions that have increased significantly as a result of changes in guidance from the IRS. Flow-through items reduce current authorized revenue requirements in SCE's rate cases which also results in recording regulatory assets for future recovery of the related deferred tax expense. The difference between forecasted amounts in SCE's rate cases and actual repair deductions also result in increases or decreases in regulatory assets and a corresponding impact on earnings. SCE estimates the amount of unrecognized tax benefits for flow-through tax items using the same accounting guidance for uncertain tax positions. Accordingly, a change in the amount of flow-through tax items from a tax authority audit impacts the amount of regulatory tax benefits recognized by SCE. It is reasonably possible that within the next 12 months unrecognized tax benefits may decrease by approximately $96 million due to a change in estimate of a tax position subject to flow through regulatory treatment.
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 $7.4 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 methodology used for ratemaking purposes, escalated at rates ranging from 1.0% to 7.3% (depending on the cost element) annually.

28




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 2049 and 2075, respectively. Costs for spent fuel monitoring are included until 2049 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 at December 31, 2014. Changes in the estimated costs or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission these facilities which could have a material effect on the recorded liability.
The 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, 2014
Uniform increase in escalation rate of 100 basis points
$
550

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.
Edison International and SCE have adopted new mortality tables that the Society of Actuaries released in October 2014 that reflect an increase in life expectancy. At December 31, 2014, this adoption resulted in an increase in Edison International's pension plans' projected benefit obligation of $214 million, including $199 million for SCE, and an increase in Edison International's PBOP plans' accumulated projected benefit obligation of $308 million, including $307 million for SCE.
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 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, rates of retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.
As of December 31, 2014, Edison International's and SCE's pension plans had a $4.5 billion and $4.0 billion benefit obligation, respectively, and total 2014 expense for these plans was $151 million and $141 million, respectively. As of December 31, 2014, the benefit obligation for both Edison International's and SCE's PBOP plans was $2.8 billion and total 2014 expense for Edison International's and SCE's plans was both $22 million. Annual contributions made to most of SCE's pension plans are currently recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the related annual expense.

29




Edison International and SCE used the following critical assumptions to determine expense for pension and other postretirement benefit for 2014:
(in millions)
Pension
Plans
Postretirement
Benefits Other
than Pensions
Discount rate1
4.50
%
5.00
%
Expected long-term return on plan assets2
7.0
%
5.5
%
Assumed health care cost trend rates3
*

7.8
%
* 
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 8.1%, 11.3% and 7.4% for the one-year, five-year and ten-year periods ended December 31, 2014, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 8.7%, 10.8% and 6.3% 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.
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, 2014, this cumulative difference amounted to a regulatory asset of $171 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.
As of December 31, 2014, Edison International and SCE had unrecognized pension costs of $762 million and $691 million, and unrecognized PBOP costs of $562 million and $558 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, $660 million of SCE's pension costs and $558 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.

30




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
$
(441
)
 
$
493

 
$
(378
)
 
$
417

Change to accumulated benefit obligation for PBOP
(388
)
 
471

 
(387
)
 
469

A one percentage point increase in the expected rate of return on pension plan assets would decrease both Edison International's and SCE's current year expense by $30 million and a one percentage point increase in the expected rate of return on PBOP plan assets would decrease both Edison International's and SCE's current year expense by $20 million.
The following table summarizes the increase or (decrease) to accumulated benefit obligation and annual aggregate service and interest costs for PBOP if the health care cost trend rate was changed while leaving all other assumptions constant:
 
Edison International
 
SCE
(in millions)
Increase in health care cost trend rate by 1%
 
Decrease in health care cost trend rate by 1%
 
Increase in health care cost trend rate by 1%
 
Decrease in health care cost trend rate by 1%
Change to accumulated benefit obligation for PBOP
$
335

 
$
(271
)
 
$
334

 
$
(270
)
Change to annual aggregate service and interest costs
15

 
(12
)
 
15

 
(12
)
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."

31




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 and monetization of tax benefits retained by EME.
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 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 retained by EME as a result of the recent extension of bonus depreciation. Realization of such tax benefits may be furthered 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 activities are concentrated in one industry and in one region.
Edison International does not have diversified sources of revenue or regulatory oversight. SCE comprises substantially all of Edison International's business, and Edison International's business is expected to remain concentrated in the electricity industry. Furthermore, Edison International's current business is concentrated almost entirely in southern California. As a result, Edison International's future performance may be affected by events and economic performance concentrated in southern California or by regional regulation or legislation.
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 following investigations of violations by PG&E of the ex parte rules on communications with CPUC officials and staff. 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.

32




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, SCE has requested approval from the CPUC to reimburse decommissioning costs related to San Onofre Units 2 and 3 from the nuclear decommissioning trust, which is pending. For more information, see "Management Overview—Permanent Retirement of San Onofre and San Onofre OII Settlement—Decommissioning" 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, 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 "Liquidity and Capital Resources—SCE—Regulatory Proceedings—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. In addition, SCE is 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 extensive changes, including increased competition, technological advancements, and political and regulatory developments.
The electricity industry is undergoing extensive change, including technological advancements such as energy storage and customer-owned generation that may change 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

33




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.
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 purchased from utilities and has the effect of increasing utility rates unless retail rates are designed to share 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 most 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.
SCE's operations may be affected if negotiations for new collective bargaining agreements are unsuccessful or relations with unionized employees deteriorate.
Approximately 30% of SCE's employees are covered by collective bargaining agreements with the International Brotherhood of Electrical Workers ("IBEW"). The IBEW collective bargaining agreements expired on December 31, 2014, but SCE and IBEW have agreed to allow the expired agreements to remain in force during ongoing negotiations for new agreements, subject to either party's right to terminate the agreements on 120 days written notice. If the current agreements are terminated, the negotiations are unsuccessful, or labor relations otherwise deteriorate, represented employees could strike, participate in work stoppages, slowdowns or other forms of labor disruption. These activities could delay projects, negatively impact capital expenditures and employee safety, and otherwise have an adverse effect on SCE's operations.
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 be presented. 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

34




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.
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. 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, which carry a fine of $50,000 per violation per day, to electric utilities subject to its jurisdiction for violations of safety rules found in statutes, regulations, and the General Orders of the CPUC. Such penalties and liabilities could be significant and materially affect SCE's liquidity and results of operations.
There are inherent risks associated with owning and decommissioning nuclear power generating facilities, including, among other things, potential harmful effects on the environment and human health and the danger of storage, handling and disposal of radioactive materials.
The cost of decommissioning Unit 2 and Unit 3 of San Onofre may not be recoverable through regulatory processes or otherwise. Inability to gain timely access to the nuclear decommissioning trust funds could negatively affect SCE's cash flows. Interpretations of tax regulations may further delay access to nuclear decommissioning trust funds for the purpose of building spent nuclear fuel storage.
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.
SCE expects to fund decommissioning costs with assets that are currently held in nuclear decommissioning trusts. SCE is required to request access to these trust funds from the CPUC and requests submitted in 2014 are pending. SCE is also required to proceed with the decommissioning of Units 2 and 3 and beginning in 2015, SCE must fund decommissioning costs until the CPUC approves SCE's request to access the trust. Based on the current estimate, SCE forecasts 2015 decommissioning costs of approximately $200 million. Decommissioning activities could be delayed and SCE's cash flows could be negatively impacted if timely access to the nuclear decommissioning trust funds is not obtained.
Depending on how the IRS or the Department of Treasury ultimately interpret IRS regulations addressing the taxation of a qualified nuclear decommissioning trust, SCE may be restricted from withdrawing amounts from its qualified decommissioning trust to pay for independent spent fuel storage installations ("ISFSI") where SCE is seeking, or plans to seek, recovery of the ISFSI costs in litigation against the DOE. Until the DOE litigation is resolved, SCE expects to pay for such ISFSI costs unless and until the IRS or the Department of Treasury issue guidance directed to either SCE or to all taxpayers, which provides that such ISFSI costs can be funded by qualified nuclear decommissioning trusts. If SCE is unable to obtain timely reimbursement of such costs, it may delay decommissioning activities and negatively impact SCE's cash flows. For more information on the spent fuel litigation, see "Notes to Consolidated Financial Statements—Note 11. Commitments and Contingencies—Contingencies—Spent Nuclear Fuel."
Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.
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 $13.6 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

35




incident liability claims were to exceed $375 million, the remaining amount would be made up from contributions of approximately $12.2 billion made by all of the nuclear facility owners in the U.S., up to an aggregate total of $13.6 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 $13.6 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."
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. 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


36




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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, 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 24, 2015


37




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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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 24, 2015

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39




Consolidated Statements of Income
Edison International
 


 
 
 
Years ended December 31,
(in millions, except per-share amounts)
2014
 
2013
 
2012
Total operating revenue
$
13,413

 
$
12,581

 
$
11,862

Purchased power and fuel
5,593

 
4,891

 
4,139

Operation and maintenance
3,149

 
3,473

 
3,608

Depreciation, decommissioning and amortization
1,720

 
1,622

 
1,562

Property and other taxes
322

 
309

 
296

Impairment and other charges
157

 
571

 
(28
)
Total operating expenses
10,941

 
10,866

 
9,577

Operating income
2,472

 
1,715

 
2,285

Interest and other income
147

 
124

 
149

Interest expense
(560
)
 
(544
)
 
(521
)
Other expenses
(80
)
 
(74
)
 
(52
)
Income from continuing operations before income taxes
1,979

 
1,221

 
1,861

Income tax expense
443

 
242

 
267

Income from continuing operations
1,536

 
979

 
1,594

Income (loss) from discontinued operations, net of tax
185

 
36

 
(1,686
)
Net income (loss)
1,721

 
1,015

 
(92
)
Preferred and preference stock dividend requirements of utility
112

 
100

 
91

Other noncontrolling interests
(3
)
 

 

Net income (loss) attributable to Edison International common shareholders
$
1,612

 
$
915

 
$
(183
)
Amounts attributable to Edison International common shareholders:
 
 
 
 
 
Income from continuing operations, net of tax
$
1,427

 
$
879

 
$
1,503

Income (loss) from discontinued operations, net of tax
185

 
36

 
(1,686
)
Net income (loss) attributable to Edison International common shareholders
$
1,612

 
$
915

 
$
(183
)
Basic earnings (loss) per common share attributable to Edison International common shareholders:
 
 
 
 
 
Weighted-average shares of common stock outstanding
326

 
326

 
326

Continuing operations
$
4.38

 
$
2.70

 
$
4.61

Discontinued operations
0.57

 
0.11

 
(5.17
)
Total
$
4.95

 
$
2.81

 
$
(0.56
)
Diluted earnings (loss) per common share attributable to Edison International common shareholders:
 
 
 
 
 
Weighted-average shares of common stock outstanding, including effect of dilutive securities
329

 
329

 
330

Continuing operations
$
4.33

 
$
2.67

 
$
4.55

Discontinued operations
0.56

 
0.11

 
(5.11
)
Total
$
4.89

 
$
2.78