2244 WALNUT GROVE AVENUE

ROSEMEAD, CA 91770

www.edison.com

ES01AR2012
FINANCIAL HIGHLIGHTS

Dollar amounts in millions, except per share data

Year ended December 31, 2011 2010 2009

Operating revenues $12,760 $12,409 $12,361 

Core earnings(1) $1,048 $1,140 $1,064

Non-core items:

Asset impairments and other charges, net $(1,082) $(24) —

Global settlement and lease terminations — $175 $(254)

Regulatory — — $46

Health care legislation — $(39) — 

Discontinued operations $(3) $4 $(7)

Net income (loss) attributable to Edison International common shareholders $(37) $1,256 $849

Basic earnings (loss) per common share attributable to Edison International 

common shareholders $(0.11) $3.84 $2.59

Dividends paid per common share $1.28 $1.26 $1.24

Total assets at December 31 $48,039 $45,530 $41,444

Total employees – Edison International and subsidiaries 19,930 20,117 19,244

BUSINESS HIGHLIGHTS

Southern California Edison

System rate base(2) $18,793 $16,811 $15,020

Capital expenditures $4,122 $3,780 $2,999

Peak demand (megawatts) 22,443 22,771 22,112

Total system sales (kilowatt-hours, in millions) 87,338 87,651 91,730

Renewable energy procured (as a percent of total portfolio) 21.1% 19.3% 16.8%

Edison Mission Group

Generation capacity at December 31 (megawatts) 10,379 9,852 10,072

Wind generation capacity (megawatts)

(in operation and under construction) 1,981 1,815 1,575

Power delivered(3) (kilowatt hours, in millions) 43,137 44,472 44,837

(1) Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States.

Management uses core earnings internally for financial planning and for analysis of performance. Core earnings are also used when

communicating with analysts and investors regarding our earnings results to facilitate comparisons of the Company's performance from

period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings

are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income

or loss from significant discrete items that management does not consider representative of ongoing earnings. 

(2) Rate base includes capital expenditures related to certain FERC-approved projects during the construction phase, as of year-end. 

(3) Excluding gas partnerships generation.
EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 1

Core earnings per share were $3.22 in 2011, 

substantially above the guidance range we provided

investors at the beginning of the year. Core earnings

is a non-GAAP measure that excludes discrete

charges and discontinued operations. GAAP earnings

per share in 2011 showed a loss of 11 cents. The

difference from core earnings was $3.33 per share,

primarily due to impairment and other charges

recorded at year-end at Edison Mission Group (EMG).

(See opposite page for a reconciliation of core and

GAAP earnings.)

Edison International’s stock appreciated 7 percent 

in 2011. This was better than the performance of the

S&P 500 Index, a measure of the overall stock market,

which was flat for the year. However, it was less than

the 14 percent gain of the Philadelphia Utilities Index,

a measure of utility industry performance. Combining

our dividend rate with our stock price appreciation

produced an 11 percent total shareholder return for

2011. And in December we increased our dividend

for the eighth consecutive year to an annual rate of

$1.30 per share. 

PRIORITIES FOR 2012

Looking forward to 2012, our primary focus will be

on our cost structure and the affordability of customer

rates at our Southern California Edison (SCE) utility,

and stabilizing our competitive power generation

business at EMG in a challenging environment of 

low power prices.

At SCE, we believe closer attention must be paid to

customer rates to address concerns about affordability

and fairness. Customer rates have been trending

higher over the last several years because the costs

of delivering electric service have grown, while total

kilowatt-hour sales have been essentially flat, due

mostly to energy conservation and loss of industrial

load. When costs rise faster than sales, rates must

rise to recover those costs. 

Several public policies initiated over the last decade

designed primarily to improve environmental quality

will also have the effect of significantly increasing

electricity rates in the years to come. The economic

pressures facing our customers and slower economic

growth lead us to conclude that SCE and public policy

makers must do everything they can to maintain a

balance between affordability and policy goals.

In addition to the rising cost of providing power, the

current structure of electricity rates in California is

creating some inequities that should be addressed.

Our rates include many state and federally mandated

subsidies for renewable power and self-generation.

Some of these subsidies are funded by taxpayers

and others through increased electric rates levied

mostly on “high-use” customers. In the last few years,

bills for these heavy electric users have become so

large that those with the financial resources to do so

are beginning to find it attractive to generate their own

power. They continue to use our system for backup

power and reliability, but without paying their fair

share of the cost for it. Meanwhile, those without the

Letter to Shareholders

In previous letters, I have spoken of the transformative change I believe our industry 

is facing. Today, this transformation seems even more certain. This change presents 

challenges, of course, but it also offers opportunities to better serve our customers and

create value for our shareholders. To that end, in 2011 we made progress on several 

important initiatives at Edison International, while providing our equity investors with 

an 11 percent total shareholder return.
means to self-generate are left to bear an ever 

larger share of the utility’s costs. This customer rate

design causes a misallocation of resources and 

customer inequities.

SCE will continue to work with public policy makers

to control rate increases and balance the goals of 

affordability and competitiveness with environmental

stewardship, while promoting rates that fairly reflect

the real costs of providing electric service to different

categories of customers. But there is also much we

can do ourselves to maintain and improve safety 

and reliability through continued investment while

minimizing the upward pressure on rates. We will 

reduce our operating costs and overhead, as well 

as improve operating efficiency so that we can

stretch our investment dollars and get more electric

infrastructure built to improve reliability.

At EMG, 2012 will be a pivotal year as we work to

stabilize a business that continues to be pressured

by low power prices. EMG has taken important steps

to enhance liquidity by securing additional project-financing and equity capital for its renewable generation

portfolio. Additionally, it obtained permits and began

construction on its Walnut Creek gas-fired generating

station in California. At the same time, EMG completed

installation of selective non-catalytic reduction for

nitrogen oxide emissions and received permits to

construct innovative sulfur dioxide removal equipment

at the Midwest Generation coal fleet.

For EMG’s fleet of coal-fired generating stations, we

made some hard decisions in the interest of financial

discipline. Last month we announced that we would

not invest additional capital in retrofits at the Homer

City power plant in Pennsylvania, and took a 

$623 million after-tax impairment charge against

2011 earnings, reflecting our assessment that we 

intend to transition control of this investment to the

owner-lessors.

We also took a $386 million after-tax charge against

2011 earnings on three of our Midwest Generation

plants in Illinois: Fisk, Crawford, and Waukegan. 

In addition, we reached the conclusion that it is not

economic to continue operating Fisk beyond 2012 

or Crawford beyond 2014. We retain flexibility on 

the decision whether to retrofit Waukegan to meet

emission regulations.

The main task for EMG in 2012 will be creating a

credible path for how it will satisfy environmental

retrofit requirements while ultimately reducing about

$1 billion in debt and becoming sufficiently credit

worthy to refinance the debt coming due in 2017

and beyond. We expect that most of the environmental

rules affecting EMG’s operations will be sufficiently

settled in 2012 to allow final decisions regarding

retrofit investments.

LONGER-TERM INITIATIVES

At Edison International, our goal is to position the

company to thrive even as our industry faces sweeping

change. Looking beyond 2012, we have initiated

three central efforts to help prepare our company. 

First, we are an operations-intensive company at our

core. We simply cannot deliver on our primary mission

of providing our customers with safe, reliable and 

affordable power without operational and service 

excellence being our top priority. Many specific 

initiatives are part of this broad effort. One of the more

comprehensive is intended to significantly improve

field crew productivity at SCE. In another, we 

are applying state-of-the-art project management

techniques to ensure that our massive capital 

investments in transmission are executed well. 

EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 2
At EMG, we are applying Electric Power Research 

Institute best practices for boiler maintenance to

drive reliable coal plant operations.

A second key effort is seeking new business 

opportunities in the electric sector. Some of these 

opportunities may come from our regulated utility

business, others will be better suited for our 

competitive business. We are exploring several ways

for increasing the use of electricity while also helping

meet broader public policy objectives of energy 

security and environmental stewardship.

One example is electrification of transportation,

which includes not only plug-in electric vehicles but

also the movement of goods from ports to their final

destination, as well as mass transit. A major advantage

of using electricity to power transportation compared

to petroleum-based fuel is that electricity is cheaper,

cleaner and nearly 100 percent domestically produced.

Other opportunities we are exploring include water

quality projects, distributed generation, developing

new gas plants and competitive transmission projects.

Success in all of these future initiatives requires 

leadership, which brings us to our third major effort –

developing our human capital and talent pool. The

transformative changes in our industry will place 

different demands on our people. We expect the pace

of change to accelerate and our business to become

more technologically intensive and customer focused.

This will require our employees to be more responsive,

adaptable and adept at managing change. We 

have recently invested significant time and effort on

programs aimed at building the capacity of our 

management, from front line supervisors to executives,

as well as the technological capabilities of our workers.

The importance of people to our organization became

especially apparent a few months ago when we 

experienced a terrible tragedy at Edison. Three of our

employees lost their lives and two others were wounded

in an office shooting incident. It was a sad and painful

event, but I was immensely proud of how our Edison

family pulled together and supported each other,

showing the resiliency, strength and courage that

characterize our company. 

I have benefited greatly from the advice and guidance

of our board of directors. I want to especially thank

retiring director Dr. James Rosser for his service to

the company, his unique sensitivity and perceptiveness

regarding our workforce, and for his support. It 

is also with great pleasure that I welcome our new 

director, Peter Taylor.

Speaking for all of us at Edison International, I can

say we are truly excited about the opportunity to

serve our customers and communities, and build a

company of value for our shareholders that is ready

for the future.

THEODORE F. CRAVER, JR.

Chairman, President and Chief Executive Officer

March 2, 2012

EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 3 
EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 4

CLEAN-BURNING NATURAL GAS IS A KEY COMPONENT OF EDISON INTERNATIONAL’S STRATEGIC GENERATION PORTFOLIO.

With natural gas prices expected to remain relatively low for the near term, natural gas-fired generation offers a

growth opportunity for Edison and a way to provide reliable and low-emission energy for customers. In a significant

milestone for our company, construction began in June on Walnut Creek Energy Park, Edison Mission Group’s

new natural gas-fired generating station in City of Industry, Calif. Power from the 479-megawatt plant, scheduled

to go into service in 2013, will be purchased by Southern California Edison under a 10-year contract approved

by the California Public Utilities Commission after a competitive bidding process. Walnut Creek is a “peaker”

plant that will typically operate when demand for electricity is at its peak, such as when air conditioning usage

soars on hot days. New natural gas-fired power plants such as Walnut Creek are crucial for meeting the energy

needs of Southern California and can serve as backup for the growing portfolio of intermittent renewable energy

sources such as wind and solar. 

Natural Gas Generation

EMG’s Walnut Creek Energy Park will 

provide needed backup generating capacity

for Southern California

THE NATURAL GAS-FIRED WALNUT CREEK PLANT IS CURRENTLY

UNDER CONSTRUCTION ON A PREVIOUSLY UNUSED STRIP OF LAND IN

AN INDUSTRIAL AREA OF LOS ANGELES COUNTY. 

Walnut Creek construction manager Kevin

Fullerton: “On the hottest days of the year,

Walnut Creek will generate enough power 

for 165,000 residential customers.”
EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 5

THE ELECTRIC POWER INDUSTRY IS UNDERGOING TRANSFORMATIVE CHANGE DRIVEN BY TECHNOLOGY AND PUBLIC POLICY.

As a result, our business is becoming more technologically intensive and customer focused. This is creating 

different requirements of our employees, who must become more responsive, adaptable and adept at managing

change. To develop our human capital and talent pool, we are launching several programs aimed at building

the capability of our management, from front line supervisors to executives, as well as the technological capabilities

of our workers. One example is Edison’s Executive Edge and Leadership Edge programs, designed to prepare

the next generation of executives by equipping them with the abilities needed to lead a more agile business.

Designed for high potential leaders across Edison International, the program’s participants in each class spend

several months in accelerated learning and development experiences. This includes working in teams on projects

of operational and strategic importance to the company.

Investing in people is the 

key to preparing Edison to meet the

transformative changes ahead.

Developing Tomorrow’s Leaders

EDISON INTERNATIONAL EXECUTIVES WORK

THROUGH A STRATEGIC PLANNING EXERCISE 

DURING AN EXECUTIVE EDGE SESSION.
EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 6

EDISON MISSION GROUP IS ONE OF THE NATION’S LEADING DEVELOPERS OF WIND ENERGY, with a current portfolio of

31 projects in operation or under construction in 11 states with a total generating capacity of nearly 2,000

megawatts. In 2011, EMG added five new projects to its portfolio, including the 240-megawatt Big Sky project

in Illinois, the 80-megawatt Laredo Ridge project in Nebraska, the 130-megawatt Taloga project in Oklahoma,

the 30-megawatt Community Wind North project in Minnesota and the 55-megawatt Pinnacle Wind Farm at

NewPage near the Maryland-West Virginia border. In addition, construction began on the 80-megawatt Broken

Bow and the 40-megawatt Crofton Bluffs projects in Nebraska, which are expected to go into service in late

2012. To support continued growth of wind energy projects, EMG has entered into a partnership with investment

groups TIAA-CREF and Cook Inlet Region Inc. The partnership, Capistrano Wind Partners LLC, will invest 

in a high-quality, diversified portfolio of U.S. wind projects, each of which will be acquired from EMG. EMG will

operate the projects and retain an equity interest in the portfolio. 

EMG adds to its wind energy portfolio

and partners with investors

to continue developing new projects

Investing in Wind Energy

Edison Mission Operations and Maintenance 

employee Carmen Carrizales at Cedro Hill, Texas.

BIG SKY IN ILLINOIS IS EDISON MISSION GROUP’S LARGEST WIND

ENERGY PROJECT TO DATE, WITH 240 MEGAWATTS OF CAPACITY.
EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 7

OVER THE NEXT THREE YEARS, SCE PLANS MORE THAN $11 BILLION IN CAPITAL EXPENDITURES to expand and upgrade

its electric system infrastructure. More than half of that – about $2 billion each year – is allocated to improving

the local distribution network, the part of the grid that delivers power to customers. SCE’s distribution system

includes approximately 1.5 million poles, 104,000 miles of circuits and more than 700 substations. These reliability

investments in the distribution network include annually replacing more than 8,000 poles that are reaching the

end of their expected life spans, several hundred miles of primary underground cables and a number of substation

transformers, while building additional distribution circuits and expanding the capacity of several substations.

In the process, SCE is creating one of the nation’s most advanced grids, including upgrading computer systems

that dispatch repair crews and restore service more efficiently, installing pioneering technology to enable enhanced,

automated monitoring of grid conditions – thereby minimizing the number of customers affected by power 

failures and limiting damage to grid components – and exploring emerging technologies that promise greater

reliability, longer life and reduced customer costs.

A SOUTHERN CALIFORNIA EDISON LINE CREW 

REPLACES A DISTRIBUTION POLE.

Ensuring System Reliability

SCE undertakes massive replacement and 

upgrades of its local distribution system

SCE employees stage equipment prior to installation.
EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 8

THE ELECTRICITY GRID IS A VITAL PART OF OUR NATION’S CRITICAL INFRASTRUCTURE. Without electricity, modern life

would not be possible. Edison International is dedicated to protecting its part of the grid and ensuring that electric

service can survive natural disasters or cyberattacks. To better respond to natural disasters, Edison has instituted

a Business Resiliency initiative, which includes adoption of the Incident Command System, the standard for

emergency management across the country, and establishment of an Emergency Operations Center. In addition,

Southern California Edison has a Mobile Command Center – a 40-foot, self-contained vehicle that gives SCE a

presence in the areas hardest hit by natural disasters and catastrophic events. For cybersecurity, Edison relies

on a defense-in-depth strategy, which involves multiple levels of redundant safeguards built into its facilities

and computer systems. The company also conducts continuous risk assessment to anticipate cyberattackers. 

CYBERSECURITY THREATS AGAINST COMPANY COMPUTER 

NETWORKS ARE MONITORED 24 HOURS A DAY BY DATA SECURITY

SPECIALISTS SUCH AS KYLE TROMBLEE.

Protecting Critical Infrastructure

 SCE deploys business resiliency and cybersecurity measures

to ensure the availability of electric service

Service Center manager Jim Ward takes a 

shift at the Mobile Command Center during 

a windstorm recovery effort. 
EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 9

SOUTHERN CALIFORNIA EDISON LINE CREW WORKS TO REPLACE A 

BADLY DAMAGED DISTRIBUTION POLE AFTER A MAJOR WIND STORM HIT 

THE SAN GABRIEL VALLEY IN NOVEMBER. 

AT EDISON INTERNATIONAL AND ITS OPERATING COMPANIES, SAFETY IS OUR PREREQUISITE GOAL. Nothing else matters

if our colleagues are not going home safely to their families at the end of each day. This dedication extends to

the safety of the public, as well. The safety of the public and our employees and contractors is a crucial component

of operational excellence, and at Edison International we are striving to create an injury-free environment. 

Electricity can be hazardous, especially when it involves downed power lines. To remind the public about safety

around electricity, Southern California Edison uses television and radio spots, social media and a website,

www.sce.com/staysafe. And during a major wind storm late last year, our focus on safety allowed our SCE crews

to restore power to 440,000 customers amid thousands of downed trees and power lines without a single

major injury to an employee, contractor or member of the public. We also continue to focus on safety at our 

San Onofre Nuclear Generating Station. In the wake of last year’s earthquake, tsunami and nuclear crisis in Japan,

we are undertaking additional seismic studies of San Onofre’s surrounding area and are honing our emergency 

preparedness capabilities in cooperation with federal, state and local agencies.

Keeping Electricity Safe

Edison International is taking extra steps to ensure

the safety of employees and the public

SCE aired television and radio spots urging the

public to stay away from downed power lines.
EDISON INTERNATIONAL 2011 ANNUAL REPORT PAGE 10

Our Vision

Leading the Way in Electricity SM

OUR VALUES

n Integrity 

n Excellence

n Respect

n Continuous Improvement

n Teamwork

OUR SHARED ENTERPRISE

n Together we provide an indispensable 

service that powers society. 

n We are a single enterprise that is stronger 

than the sum of its parts.

OUR OPERATING PRIORITIES 

n We operate safely

n We meet customer needs

n We value diversity

n We build productive partnerships

n We protect the environment

n We learn from experience and improve

n We grow the value of our business
UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________

FORM 10-K ________________________

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

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 1-9936

_________________________

EDISON INTERNATIONAL

(Exact name of registrant as specified in its charter)

__________________________

California

(State or other jurisdiction of

incorporation or organization)

2244 Walnut Grove Avenue

(P.O. Box 976)

Rosemead, California

(Address of principal executive offices)

(626) 302-2222

(Registrant's telephone number, including area code)

95-4137452

(I.R.S. Employer

Identification No.)

91770

(Zip Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Common Stock, no par value

Name of each exchange

on which registered

NYSE

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. Yes No 

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. Yes No 

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. Yes No 

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). Yes No 

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. 

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 "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check One):

Large Accelerated Filer Accelerated Filer Non-accelerated Filer Smaller Reporting Company 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No 

The aggregate market value of registrant's voting stock held by non-affiliates was approximately $12.6 billion on or about June 30, 2011, based upon prices 

reported on the New York Stock Exchange. As of February 27, 2012, there were 325,811,206 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the following documents listed below have been incorporated by reference into the parts of this report so indicated.

(1) Designated portions of the Proxy Statement relating to registrant's 2012 Annual Meeting of Shareholders Part III

i

TABLE OF CONTENTS

GLOSSARY..............................................................................................................................................................

FORWARD-LOOKING STATEMENTS ..............................................................................................................

PART I

ITEM 1. BUSINESS ................................................................................................................................................

INTRODUCTION

EDISON MISSION GROUP INC.

ENVIRONMENTAL REGULATION OF EDISON INTERNATIONAL AND SUBSIDIARIES

ITEM 1A. RISK FACTORS ...................................................................................................................................

RISKS RELATING TO EDISON INTERNATIONAL

RISK RELATING TO SCE

RISK RELATING TO EMG

ITEM 1B. UNRESOLVED STAFF COMMENTS................................................................................................

ITEM 2. PROPERTIES ..........................................................................................................................................

ITEM 3. LEGAL PROCEEDINGS........................................................................................................................

Subsidiaries of Edison International..............................................................................................................

Regulation of Edison International and Subsidiaries...................................................................................

SOUTHERN CALIFORNIA EDISON COMPANY

Regulation.........................................................................................................................................................

Overview of Ratemaking Process...................................................................................................................

Purchased Power and Fuel Supply.................................................................................................................

Competition ......................................................................................................................................................

Properties..........................................................................................................................................................

Seasonality ........................................................................................................................................................

Overview...........................................................................................................................................................

Regulation.........................................................................................................................................................

Markets for Generation...................................................................................................................................

Wholesale Markets...........................................................................................................................................

Fuel Supply.......................................................................................................................................................

Competition ......................................................................................................................................................

Properties..........................................................................................................................................................

Significant Customers......................................................................................................................................

Asset Management and Trading Activities....................................................................................................

Energy and Infrastructure Investments ........................................................................................................

Seasonality ........................................................................................................................................................

Air Quality........................................................................................................................................................

Water Quality...................................................................................................................................................

Coal Combustion Wastes.................................................................................................................................

Greenhouse Gas Regulation............................................................................................................................

Regulatory Risks..............................................................................................................................................

Operating Risks................................................................................................................................................

Financing Risks................................................................................................................................................

Liquidity Risks.................................................................................................................................................

Regulatory and Environmental Risks............................................................................................................

Market Risks ....................................................................................................................................................

Operating Risks................................................................................................................................................

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EXECUTIVE OFFICERS OF THE REGISTRANT ...........................................................................................

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER 

MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES..............................................................

ITEM 6. SELECTED FINANCIAL DATA............................................................................................................

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 

RESULTS OF OPERATIONS................................................................................................................................

EDISON INTERNATIONAL OVERVIEW

RESULTS OF OPERATIONS................................................................................................................................

LIQUIDITY AND CAPITAL RESOURCES ........................................................................................................

MARKET RISK EXPOSURES..............................................................................................................................

EDISON MISSION GROUP

RESULTS OF OPERATIONS................................................................................................................................

LIQUIDITY AND CAPITAL RESOURCES ........................................................................................................

Issuer Purchases of Securities.........................................................................................................................

Comparison of Five-Year Cumulative Total Return.....................................................................................

Highlights of Operating Results .....................................................................................................................

Management Overview of SCE.......................................................................................................................

Management Overview of EMG.....................................................................................................................

Environmental Developments.........................................................................................................................

Supplemental Operating Revenue Information............................................................................................

Income Taxes....................................................................................................................................................

Available Liquidity...........................................................................................................................................

Capital Investment Plan..................................................................................................................................

Regulatory Proceedings...................................................................................................................................

Dividend Restrictions.......................................................................................................................................

Margin and Collateral Deposits......................................................................................................................

Workers Compensation Self-Insurance Fund...............................................................................................

Regulatory Balancing Accounts......................................................................................................................

Historical Segment Cash Flows ......................................................................................................................

Contractual Obligations and Contingencies..................................................................................................

Interest Rate Risk ............................................................................................................................................

Commodity Price Risk.....................................................................................................................................

Credit Risk........................................................................................................................................................

Results of Continuing Operations..................................................................................................................

Results of Discontinued Operations...............................................................................................................

Related Party Transactions.............................................................................................................................

Available Liquidity...........................................................................................................................................

2012 CPUC General Rate Case ................................................................................................................

FERC Formula Rates...............................................................................................................................

Capital Program........................................................................................................................................

Midwest Generation Environmental Compliance Plans and Costs........................................................

Homer City Lease......................................................................................................................................

EMG's Renewable Energy Activities........................................................................................................

Utility Earning Activities...........................................................................................................................

Utility Cost-Recovery Activities.................................................................................................................

SOUTHERN CALIFORNIA EDISON COMPANY

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MARKET RISK EXPOSURES..............................................................................................................................

EDISON INTERNATIONAL PARENT AND OTHER

RESULTS OF OPERATIONS................................................................................................................................

LIQUIDITY AND CAPITAL RESOURCES ........................................................................................................

MARKET RISK EXPOSURES..............................................................................................................................

EDISON INTERNATIONAL (CONSOLIDATED)

LIQUIDITY AND CAPITAL RESOURCES ........................................................................................................

NEW ACCOUNTING GUIDANCE.......................................................................................................................

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..................

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA........................................................

CONSOLIDATED FINANCIAL STATEMENTS................................................................................................

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM...........................................

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS...........................................................................

Capital Investment Plan..................................................................................................................................

Historical Segment Cash Flows ......................................................................................................................

Credit Ratings ..................................................................................................................................................

Margin, Collateral Deposits and Other Credit Support for Energy Contracts.........................................

Intercompany Tax-Allocation Agreement......................................................................................................

Debt Covenants and Dividend Restrictions...................................................................................................

Contractual Obligations, Commercial Commitments and Contingencies .................................................

Off-Balance Sheet Transactions......................................................................................................................

Introduction......................................................................................................................................................

Derivative Instruments....................................................................................................................................

Commodity Price Risk.....................................................................................................................................

Credit Risk........................................................................................................................................................

Interest Rate Risk ............................................................................................................................................

Historical Cash Flows......................................................................................................................................

Contractual Obligations..................................................................................................................................

Interest Rate Risk ............................................................................................................................................

Contractual Obligations..................................................................................................................................

Critical Accounting Estimates and Policies...................................................................................................

Consolidated Statements of Income ...............................................................................................................

Consolidated Statements of Comprehensive Income....................................................................................

Consolidated Balance Sheets...........................................................................................................................

Consolidated Statements of Cash Flows........................................................................................................

Consolidated Statements of Changes in Equity ............................................................................................

Note 1. Summary of Significant Accounting Policies....................................................................................

Note 2. Property, Plant and Equipment.........................................................................................................

Note 3. Variable Interest Entities....................................................................................................................

Rate Regulated Enterprises ......................................................................................................................

Impairment of Long-Lived Assets ............................................................................................................

Derivatives.................................................................................................................................................

Nuclear Decommissioning – ARO............................................................................................................

Pensions and Postretirement Benefits Other than Pensions...................................................................

Income Taxes.............................................................................................................................................

Accounting for Contingencies, Guarantees and Indemnities.................................................................

62

63

64

64

64

64

66

67

67

67

67

68

73

74

75

75

75

75

76

76

76

77

77

77

78

78

78

80

81

82

84

84

85

85

85

85

87

88

89

90

92

94

95

95

104

105
iv

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 

FINANCIAL DISCLOSURE..................................................................................................................................

ITEM 9A. CONTROLS AND PROCEDURES ....................................................................................................

ITEM 9B. OTHER INFORMATION ....................................................................................................................

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE..........................

ITEM 11. EXECUTIVE COMPENSATION ........................................................................................................

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 

AND RELATED STOCKHOLDER MATTERS..................................................................................................

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR 

INDEPENDENCE ...................................................................................................................................................

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES......................................................................

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES...........................................................

SIGNATURES

EXHIBIT INDEX

Note 4. Fair Value Measurements...................................................................................................................

Note 5. Debt and Credit Agreements..............................................................................................................

Note 6. Derivative Instruments and Hedging Activities...............................................................................

Note 7. Income Taxes.......................................................................................................................................

Note 8. Compensation and Benefit Plans.......................................................................................................

Note 9. Commitments and Contingencies......................................................................................................

Note 10. Environmental Developments..........................................................................................................

Note 11. Accumulated Other Comprehensive Loss.......................................................................................

Note 12. Supplemental Cash Flows Information ..........................................................................................

Note 13. Preferred and Preference Stock of Utility ......................................................................................

Note 14. Regulatory Assets and Liabilities ....................................................................................................

Note 15. Other Investments.............................................................................................................................

Note 16. Asset Impairments, Lease Terminations and Other ......................................................................

Note 17. Other Income and Expenses ............................................................................................................

Note 18. Business Segments.............................................................................................................................

Note 19. Quarterly Financial Data (Unaudited)............................................................................................

109

115

116

123

126

142

151

153

154

154

155

157

158

160

161

162

163

163

163

163

164

164

165

165

165

171

173
v

GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2011 Form 10-K ................

2010 Tax Relief Act...........

AFUDC..............................

Ambit project.....................

AOI....................................

APS....................................

ARO(s) ..............................

BACT.................................

BART.................................

Bcf .....................................

Big 4 ..................................

Btu .....................................

CAA...................................

CAIR..................................

CAISO ...............................

CAMR ...............................

CARB ................................

CDWR ...............................

CEC ...................................

coal plants..........................

Commonwealth Edison .....

CPS....................................

CPUC.................................

CSAPR ..............................

CRRs..................................

DOE...................................

EME...................................

EMG ..................................

EMMT ...............................

EPS ....................................

ERRA.................................

Exelon Generation.............

FASB .................................

FERC .................................

FGIC..................................

FIP(s) .................................

Four Corners......................

GAAP ................................

GHG ..................................

Global Settlement ..............

Edison International's Annual Report on Form 10-K for the year-ended December 31, 2011

Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010

allowance for funds used during construction

American Bituminous Power Partners, L.P.

Adjusted Operating Income (Loss)

Arizona Public Service Company

asset retirement obligation(s)

best available control technology

best available retrofit technology

billion cubic feet

Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects

British thermal units

Clean Air Act

Clean Air Interstate Rule

California Independent System Operator

Clean Air Mercury Rule

California Air Resources Board

California Department of Water Resources

California Energy Commission

Midwest Generation coal plants and Homer City plant

Commonwealth Edison Company

Combined Pollutant Standard

California Public Utilities Commission

Cross-State Air Pollution Rule

congestion revenue rights

U.S. Department of Energy

Edison Mission Energy

Edison Mission Group Inc.

Edison Mission Marketing & Trading, Inc.

earnings per share

energy resource recovery account

Exelon Generation Company LLC

Financial Accounting Standards Board

Federal Energy Regulatory Commission

Financial Guarantee Insurance Company

federal implementation plan(s)

coal fueled electric generating facility located in Farmington, New Mexico in

which SCE holds a 48% ownership interest

generally accepted accounting principles

greenhouse gas

A settlement between Edison International and the IRS that resolved federal tax disputes

related to Edison Capital's cross-border, leveraged leases through 2009, and all other

outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002 and

related matters with state tax authorities.
vi

GRC...................................

GWh ..................................

Homer City ........................

Illinois EPA........................

IRS.....................................

ISO.....................................

kWh(s) ...............................

LIBOR ...............................

MATS................................

MD&A...............................

Midwest Generation ..........

Midwest Generation plants

MMBtu ..............................

Mohave..............................

Moody's .............................

MRTU................................

MW....................................

MWh..................................

NAAQS .............................

NAPP.................................

NERC ................................

Ninth Circuit......................

NOV...................................

NOx.............................................

NRC...................................

NSR ...................................

NYISO...............................

PADEP...............................

Palo Verde..........................

PBOP(s).............................

PBR....................................

PG&E ................................

PJM....................................

PRB....................................

PSD....................................

QF(s)..................................

ROE ...................................

RPM...................................

RTO(s)...............................

S&P....................................

San Onofre.........................

general rate case

gigawatt-hours

EME Homer City Generation L.P., a Pennsylvania limited partnership that leases and

operates three coal-fired electric generating units and related facilities located in Indiana

County, Pennsylvania

Illinois Environmental Protection Agency

Internal Revenue Service

Independent System Operator

kilowatt-hour(s)

London Interbank Offered Rate

Mercury and Air Toxics Standards

Management's Discussion and Analysis of Financial Condition and Results

of Operations in this report

Midwest Generation, LLC, a Delaware limited liability company that owns and/or leases,

and that operates, the Midwest Generation plants

Midwest Generation's power plants (fossil fuel) located in Illinois

million British thermal units

two coal fueled electric generating facilities that no longer operate located

in Clark County, Nevada in which SCE holds a 56% ownership interest

Moody's Investors Service

Market Redesign and Technology Upgrade

megawatts

megawatt-hours

national ambient air quality standards

Northern Appalachian

North American Electric Reliability Corporation

U.S. Court of Appeals for the Ninth Circuit

notice of violation

nitrogen oxide

Nuclear Regulatory Commission

New Source Review

New York Independent System Operator

Pennsylvania Department of Environmental Protection

large pressurized water nuclear electric generating facility located near

Phoenix, Arizona in which SCE holds a 15.8% ownership interest

postretirement benefits other than pension(s)

performance-based ratemaking

Pacific Gas & Electric Company

PJM Interconnection, LLC

Powder River Basin

Prevention of Significant Deterioration

qualifying facility(ies)

return on equity

Reliability Pricing Model

Regional Transmission Organization(s)

Standard & Poor's Ratings Services

large pressurized water nuclear electric generating facility located in south

San Clemente, California in which SCE holds a 78.21% ownership interest
vii

SCE....................................

SNCR.................................

SDG&E..............................

SEC....................................

SIP(s) .................................

SO2 ..............................................

US EPA..............................

VIE(s) ................................

Southern California Edison Company

selective non-catalytic reduction

San Diego Gas & Electric

U.S. Securities and Exchange Commission

state implementation plan(s)

sulfur dioxide

U.S. Environmental Protection Agency

variable interest entity(ies)
(This page has been left blank intentionally.)
1

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 current expectations and 

projections about future events based on Edison International'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 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, include, but are not limited to:

• cost of capital and the ability of Edison International or its subsidiaries to borrow funds and access the capital 

markets on reasonable terms;

• environmental laws and regulations, at both 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, including 

compliance with CPS at Midwest Generation and the CSAPR and the MATS rule at Midwest Generation and Homer 

City;

• 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 and other regulatory authorities and delays in regulatory 

actions;

• possible customer bypass or departure due to technological advancements or cumulative rate impacts that make selfgeneration or use of alternative energy sources economically viable;

• risks associated with the operation of transmission and distribution assets and nuclear and other power generating 

facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of 

repairs and retrofits of equipment and availability and cost of spare parts;

• cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer 

needs in the event of significant counterparty defaults under power-purchase agreements;

• changes in the fair value of investments and other assets;

• changes in interest rates and rates of inflation, including those 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 

Independent System Operators and Regional Transmission Organizations;

• availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel 

markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their 

obligations;

• cost and availability of labor, equipment and materials;

• ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related 

liability, and to recover the costs of such insurance;

• ability to recover uninsured losses in connection with wildfire-related liability;

• effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting 

standards;

• potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;

• cost and availability of coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not 

recovered through regulated rate cost escalation provisions or balancing accounts;
2

• cost and availability of emission credits or allowances for emission credits;

• transmission congestion in and to each market area and the resulting differences in prices between delivery points;

• ability to provide sufficient collateral in support of hedging activities and power and fuel purchased;

• risks inherent in the development of generation projects and transmission and distribution infrastructure replacement 

and expansion projects, including those related to project site identification, public opposition, environmental 

mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there 

is insufficient transmission to enable the acceptance of power delivery), and governmental approvals;

• risks that competing transmission systems will be built by merchant transmission providers in SCE's service area; 

and

• weather conditions and natural disasters.

See "Risk Factors" in Part I, Item 1A of 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 or its 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 business. Forwardlooking statements speak only as of the date they are made and Edison International is not obligated to publicly update or 

revise forward-looking statements. Readers should review future reports filed by Edison International with the U.S. Securities 

and Exchange Commission.

Except when otherwise stated, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each 

such company with its subsidiaries on a consolidated basis. References to "Edison International (parent)" or "parent 

company" mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.
3

PART I

ITEM 1. BUSINESS

INTRODUCTION

Edison International was incorporated on April 20, 1987, under the laws of the State of California for the purpose of 

becoming the parent holding company of Southern California Edison Company ("SCE"), a California public utility 

corporation and Edison Mission Group Inc. ("EMG"), a competitive power generation company. As a holding company, 

Edison International's progress and outlook are dependent on developments at its operating subsidiaries.

At December 31, 2011, Edison International and its subsidiaries had an aggregate of 19,930 full-time employees. The 

principal executive offices of Edison International are located at 2244 Walnut Grove Avenue, P.O. Box 976, Rosemead, 

California 91770, and the telephone number is (626) 302-2222.

Edison International makes available on its investor website, www.edisoninvestor.com, its Annual Report on Form 10-K, 

Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement and amendments to those reports filed or 

furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, as soon as reasonably practicable after Edison 

International electronically files such material with, or furnishes it to, the SEC. Such reports are also available on the SEC's 

internet website at www.sec.gov. The information contained on, or connected to, the Edison investor website is not 

incorporated by reference into this report.

Subsidiaries of Edison International

Edison International has two business segments for financial reporting purposes: an electric utility segment (SCE) and a 

competitive power generation segment (EMG). 

SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000 

square-mile area of southern California. The SCE service territory contains a population of nearly 14 million people. In 2011, 

SCE's total operating revenue was derived as follows: 41.6% commercial customers, 40.2% residential customers, 5.7% 

industrial customers, 0.7% resale sales, 5.5% public authorities, and 6.3% agricultural and other customers. SCE had 18,069 

full-time employees at December 31, 2011. SCE's operating revenue was approximately $10.6 billion in 2011. 

Sources of energy to serve SCE's customers during 2011 were approximately: 36% purchased power; 21% CDWR; and 43% 

SCE-owned generation.

SCE separately files reports pursuant to Section 13(a) or 15(d) of the Securities Exchange Act. SCE also files a joint Proxy 

Statement with its parent, Edison International. Such reports and Proxy Statement are available at www.edisoninvestor.com 

or on the SEC's website at www.sec.gov. The information contained on, or connected to, the Edison investor website is not 

incorporated by reference into this report.

EMG is the holding company for its principal wholly owned subsidiary, EME. EME is also a holding company with 

subsidiaries and affiliates engaged in the business of developing, acquiring, owning or leasing, operating and selling energy 

and capacity from independent power production facilities. Some of the facilities are operated on a merchant basis, with 

energy being sold into the marketplace, and others are operated under contracts calling for the delivery of energy to specific 

purchasers. EME also engages in hedging and energy trading activities in competitive power markets through its Edison 

Mission Marketing & Trading, Inc. ("EMMT") subsidiary. At December 31, 2011, EMG and its subsidiaries employed 1,795 

people. EMG's consolidated operating revenue was approximately $2.2 billion in 2011.

EMG's subsidiaries or affiliates have typically been formed to own full or partial interests in one or more power generation 

facilities and ancillary facilities, with each plant or group of related plants being individually referred to by EMG as a project. 

EMG's operating projects primarily consist of coal-fired and natural gas-fired generating facilities, and renewable energy 

facilities, primarily wind projects. As of December 31, 2011, EMG's subsidiaries and affiliates owned or leased interests in 43 

operating projects with an aggregate net physical capacity of 11,504 MW of which EME's pro rata share was 10,379 MW. At 

December 31, 2011, EME's subsidiaries and affiliates also had one wind project and one natural gas-fired peaker plant under 

construction, totaling 80 MW and 479 MW, respectively of net generating capacity. 

EME separately files reports pursuant to Section 13(a) or 15(d) of the Securities Exchange Act. Such reports are available at 

www.edisoninvestor.com or on the SEC's internet website at www.sec.gov. The information contained on, or connected to, 

the Edison investor website is not incorporated by reference into this report.

Edison International maintains a property and casualty insurance program for itself and its subsidiaries, which includes 
4

business interruption (for EMG only), and excess liability insurance covering liabilities to third parties for bodily injury or

property damage resulting from operations. These policies are subject to specific retentions, sublimits and deductibles, which 

are comparable to those carried by other utility and electric generating companies of similar size. SCE also has separate 

insurance programs for nuclear property and liability, workers compensation and solar rooftop construction. EMG maintains 

a separate wind liability insurance program for its wind projects. For further information on wildfire insurance, see "Item 8. 

Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

Regulation of Edison International and Subsidiaries

Edison International and its subsidiaries are subject to extensive regulation. As a public utility holding company, Edison 

International is subject to the Public Utility Holding Company Act. The Public Utility Holding Company Act primarily 

obligates Edison International and its utility subsidiaries to provide access to their books and records to the FERC and the 

CPUC for ratemaking purposes.

Edison International is not a public utility. The 1988 CPUC decision authorizing SCE to reorganize into a holding company 

structure, however, contains certain obligations on Edison International and its affiliates. These include a requirement that 

SCE's dividend policy shall continue to be established by SCE's Board of Directors as though SCE were a stand-alone utility 

company, and that the capital requirements of SCE, as deemed to be necessary to meet SCE's service obligations, shall 

receive first priority from the Boards of Directors of Edison International and SCE. The CPUC has also promulgated Affiliate 

Transaction Rules, which, among other requirements, prohibit holding companies from (1) being used as a conduit to provide 

non-public information to a utility's affiliate and (2) causing or abetting a utility's violation of the rules, including providing 

preferential treatment to affiliates.

SOUTHERN CALIFORNIA EDISON COMPANY

Regulation

CPUC 

SCE's retail operations are subject to regulation by the CPUC. The CPUC has the authority to regulate, among other things, 

retail rates, energy purchases on behalf of retail customers, rate of return, rates of depreciation, issuance of securities, 

disposition of utility assets and facilities, oversight of nuclear decommissioning funding and costs, and aspects of the 

transmission system planning, site identification and construction.

FERC

SCE's wholesale operations (including sales of electricity into the wholesale markets) are subject to regulation by the FERC. 

The FERC has the authority to regulate wholesale rates as well as other matters, including unbundled transmission service 

pricing, accounting practices, and licensing of hydroelectric projects. The FERC also has jurisdiction over a portion of the 

retail rates and associated rate design.

NERC

The North American Electric Reliability Corporation ("NERC") establishes and enforces reliability standards and critical 

infrastructure protection standards to protect the bulk power system against potential disruptions from cyber and physical 

security breaches. The critical infrastructure protection standards focus on controlling access to critical physical and cyber 

security assets. Compliance with these standards is mandatory. The maximum penalty that may be levied for violating a 

NERC reliability or critical infrastructure protection standard is $1 million per violation, per day.

SCE has a formal cyber security program that is staffed and has a dedicated budget. The program covers SCE's information 

technology systems as well as the electric grid where SCE has control of it. Program staff is engaged with industry groups as 

well as public-private initiatives to reduce risk and to strengthen the security and reliability of SCE's systems and 

infrastructure. The program is also engaged in the protection of SCE's customer information.

Transmission and Substation Facilities Regulation

The construction, planning and project site identification of SCE's transmission lines and substation facilities require the 

approval of many governmental agencies and compliance with various laws. These agencies include utility regulatory 

commissions such as the CPUC and other state regulatory agencies depending on the project location; the CAISO, and other 

environmental, land management and resource agencies such as the Bureau of Land Management, the U.S. Forest Service, 

and the California Department of Fish and Game; and regional water quality control boards. In addition, to the extent that 
5

SCE transmission line projects pass through lands owned or controlled by Native American tribes, consent and approval from 

the affected tribes and the Bureau of Indian Affairs are also necessary for the project to proceed.

CEC

The construction, planning, and project site identification of SCE's power plants of 50 MW or greater within California are 

subject to the jurisdiction of the CEC. The CEC is also responsible for forecasting future energy needs. These forecasts are 

used by the CPUC in determining the adequacy of SCE's electricity procurement plans.

Nuclear Power Plant Regulation

SCE is subject to the jurisdiction of the NRC with respect to the safety of its San Onofre and Palo Verde Nuclear Generating 

Stations. The NRC regulates commercial nuclear power plants through licensing, oversight and inspection, performance 

assessment, and enforcement of its requirements.

In light of the events at the Fukushima Daiichi nuclear plant in Japan resulting from the March 2011 earthquake and tsunami, 

the NRC has been performing and plans to continue to perform additional operational and safety reviews of nuclear facilities 

in the United States. The NRC's Near Term Task Force ("NTTF") conducted a systematic review of NRC processes and 

regulations to determine whether additional improvements to the existing nuclear regulatory system are warranted in light of 

the events in Japan. The NTTF concluded that a sequence of events like the Fukushima accident is unlikely to occur in the 

U.S., and that continued operation of U.S. reactors does not pose an imminent risk to public health and safety. The NTTF 

Report proposed changes to regulations applicable to protection against natural phenomena, including earthquakes and 

flooding and emergency preparedness, and the NTTF made a number of recommendations as to actions that the NRC might 

implement. In October 2011, the NRC identified seven of the near-term actions recommended by the NRC staff as having the 

greatest potential for safety improvement. The NRC staff was directed to strive to implement these actions by 2016. 

Implementation of these actions will require further interactions between the NRC staff and the nuclear industry. These 

actions may impact future operations and capital requirements at U.S. nuclear facilities at the time of their implementation, 

including the operations and capital requirements of SCE's nuclear facilities.

Operating License Renewal

In April 2011, the NRC extended the operating license for Palo Verde Operating Units 1, 2 and 3 for an additional 20 years, to 

2045, 2046 and 2047, respectively. San Onofre's current operating licenses for Units 2 and 3 will expire in 2022. The NRC's 

review of a license renewal application typically takes three to five years. Prior to filing a license renewal application at the 

NRC, SCE would make an application to the CPUC to demonstrate the cost effectiveness of continuing operations at San 

Onofre and to seek authority to recover the cost of seeking a license renewal at the NRC and pursuing approvals from other 

state and federal agencies, such as the Department of the Navy and the California Coastal Commission. SCE will consider a 

decision to file an application for cost recovery at the CPUC in 2012. If SCE were to choose not to pursue license renewal or 

if SCE' efforts to obtain license renewal were not successful, SCE will need to determine what generation and transmission 

alternatives would need to be made available to replace the capacity, energy, and grid reliability benefits that SCE's customers 

now receive from San Onofre by the time San Onofre ceases generating electricity. Should SCE decide to pursue a license 

extension for San Onofre, SCE will likely need to simultaneously consider generation and transmission alternatives given the 

long lead times for the NRC to approve a license extension and to site, permit and construct new generation and transmission 

facilities. The costs of these alternatives could be substantial.

Overview of Ratemaking Process

CPUC 

Revenue authorized by the CPUC through triennial GRC proceedings is intended to provide SCE a reasonable opportunity to 

recover its costs and earn a return on its net investment in generation and distribution assets (also referred to as “rate base”). 

The CPUC sets an annual revenue requirement for the base year which is made up of the operation and maintenance costs, 

depreciation, taxes and a return consistent with the capital structure (discussed below). The return is established by 

multiplying an authorized rate of return, determined in separate cost of capital proceedings, by SCE's generation and 

distribution rate base. In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecast 

basis. Following the base year, the revenue requirements for the remaining two years are set by a methodology established in 

the GRC proceeding, which generally, among other items, includes annual allowances for escalation in operation and 

maintenance costs, additional changes in capital-related investments and the recovery for expected nuclear refueling outages. 

SCE's authorized revenue requirements were $4.83 billion, $5.04 billion and $5.25 billion for the years ended December 31, 

2009, 2010 and 2011, respectively. SCE filed its 2012 GRC application with the CPUC on November 23, 2010, to be 
6

effective on January 1, 2012. For further discussion of the 2012 GRC, see "Edison International Overview—Management 

Overview of SCE—2012 CPUC General Rate Case" in the MD&A.

CPUC rates decouple authorized revenue from the volume of electricity sales, so that SCE earns revenue equal to amounts 

authorized. Differences between amounts collected and authorized levels are either collected from or refunded to customers, 

and, therefore, such differences do not impact operating revenue. Accordingly, SCE is neither benefited nor burdened by the 

volumetric risk related to retail electricity sales.

The CPUC regulates SCE's capital structure and authorized rate of return. SCE's current authorized capital structure is 48% 

common equity, 43% long-term debt and 9% preferred equity. SCE's current authorized cost of capital consists of: cost of 

long-term debt of 6.22%, cost of preferred equity of 6.01% and return on common equity of 11.5%. SCE is scheduled to file a 

new cost of capital application with the CPUC in April 2012 that will be effective beginning in 2013.

In addition, to the ratemaking process described above, the CPUC has also authorized ratemaking mechanisms outside of the 

GRC process for significant capital projects, as needed.

Balancing accounts (also referred to as cost-recovery mechanisms) are typically used to track and recover SCE's costs of fuel, 

purchased-power, and certain operation and maintenance expenses, including certain demand-side management program 

costs. SCE earns no return on these activities and although differences between forecasted and actual costs do not impact 

earnings, such differences do impact cash flows and can change rapidly.

SCE's balancing account for fuel and power procurement-related costs is established under the Energy Resource Recovery 

Account ("ERRA") Mechanism. SCE sets rates based on an annual forecast of the costs that it expects to incur during the 

following year. In addition, the CPUC has established a "trigger" mechanism for the ERRA balancing account that allows for 

a rate adjustment if the balancing account over-collection or under-collection exceeds 5% of SCE's prior year's revenue that is

classified as generation for retail rates. For 2012, the trigger amount is approximately $237 million.

The majority of costs eligible for recovery through cost-recovery rates are approved upfront by the CPUC though a 

procurement plan with predefined standards, or through CPUC preapproval, and thus could negatively impact earnings and 

cash flows if SCE's costs were found to be unreasonable or out of compliance and disallowed.

FERC

Revenue authorized by the FERC is intended to provide SCE a reasonable opportunity to recover its costs and earn a return 

on its net investment in transmission assets. In August 2011, the FERC accepted SCE's request to implement a formula rate 

effective January 1, 2012 to determine SCE's FERC transmission revenue requirement, including its construction work in 

progress ("CWIP") revenue requirement that was previously recovered through a separate mechanism. For further discussion 

of SCE's FERC formula rates, see "Edison International Overview—Management Overview of SCE—FERC Formula Rates" 

in the MD&A.

Retail Rates

To develop retail rates, the authorized revenue requirements are allocated among all customer classes (residential, 

commercial, industrial and agricultural) on a functional basis (i.e., generation, distribution, transmission, etc.). Specific rate 

components are designed to recover the authorized revenue allocated to each customer class. 

Currently, SCE has a five tier residential rate structure. Each tier represents a certain electricity usage level and within each 

increasing usage level, the electricity is priced at higher rates per kilowatt hour. The first tier is a baseline tier and has the 

lowest rate per kilowatt hour. "Baseline" refers to a specific amount of energy allocated for residential customers that is 

charged at a lower price than energy used in excess of that amount. Baseline quantities are determined by SCE for approval 

by the CPUC using average residential electricity consumption for nine geographical regions in southern and central 

California. Seasonal variations in usage are also accounted for in determining baseline allowances.

The intent of the baseline and the tiered structure is to provide a portion of reasonable energy needs (baseline usage) of 

residential customers at the lowest rate, and to encourage conservation of energy by increasing the rate charges as energy 

usage increases. Statutory restrictions on tier one and two rates have shifted the burden of residential rate increases to the 

higher tier/usage customers. As part of the second phase of SCE's 2012 GRC, SCE requested certain rate design 

modifications that are intended to provide a more equitable, cost-based rate design.

CDWR-Related Rates

As a result of the California energy crisis, in 2001 the CDWR entered into contracts to purchase power for sale at cost 
7

directly to SCE's retail customers and issued bonds to finance those power purchases. The CDWR's total statewide power 

charge and bond charge revenue requirements were allocated by the CPUC among the customers of the investor-owned 

utilities (SCE, PG&E and SDG&E). SCE billed and collected from its customers the costs of power purchased and sold by 

the CDWR. SCE will continue to bill and collect CDWR bond-related charges and direct access exit fees until 2022. The 

CDWR-related charges and a portion of direct access exit fees that are remitted directly to the CDWR are not recognized as 

electric utility operating revenue; but did affect customer rates. All CDWR power contracts that were allocated to SCE 

expired by the end of 2011. See "SCE: Results of Operations—Supplemental Operating Revenue Information" in the MD&A 

for further discussion of the impact of CDWR charges on customer rates.

Purchased Power and Fuel Supply

SCE obtains the power needed to serve its customers from its generating facilities and from sales by qualifying facilities, 

independent power producers, renewable power producers, the CAISO, and other utilities. 

Natural Gas Supply

SCE requires natural gas to meet contractual obligations for power tolling agreements (power contracts in which SCE has 

agreed to provide or pay for the natural gas burned to generate electricity). SCE also requires natural gas to fuel its 

Mountainview and peaker plants, which are generation units that are designed to operate in response to changes in demand 

for power. The physical natural gas purchased by SCE is subject to competitive bidding.

Nuclear Fuel Supply

For San Onofre Units 2 and 3, contractual arrangements are in place covering 100% of the projected nuclear fuel 

requirements through the years indicated below:

Uranium concentrates

Conversion

Enrichment

Fabrication

2020

2020

2020

2015

For Palo Verde, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the 

years indicated below: 

Uranium concentrates

Conversion

Enrichment

Fabrication

2017

2018

2020

2016

Coal Supply

On January 1, 2010, SCE and the other Four Corners participants entered into a Four Corners Coal Supply Agreement with 

the BHP Navajo Coal Company, under which coal will be supplied to Four Corners Units 4 and 5 until July 6, 2016. The 

co-owners of Four Corners (excluding SCE) are currently negotiating a potential new Coal Supply Agreement with BHP 

Navajo Coal Company for the period after July 6, 2016. In November 2010, SCE entered into an agreement to sell its interest 

in Four Corners subject to certain conditions and regulatory approvals. See "Item 8. Edison International Notes to 

Consolidated Financial Statements—Note 2. Property, Plant and Equipment," for more information on the sale of SCE's 

interest in Four Corners.

CAISO Wholesale Energy Market

In California and other states, wholesale energy markets exist through which competing electricity generators offer their 

electricity output to electricity retailers. Each state's wholesale electricity market is generally operated by its state ISO or a 

regional RTO. California's wholesale electricity market is operated by the CAISO. The CAISO schedules power in hourly 

increments with hourly prices through a real-time and day-ahead market that combines energy, ancillary services, unit 

commitment and congestion management. SCE participates in the day-ahead and real-time markets for the sale of its 

generation and purchases of its load requirements.

The CAISO uses a nodal locational pricing model, which sets wholesale electricity prices at system points ("nodes") that 
8

reflect local generation and delivery costs. Generally, SCE schedules its electricity generation to serve its load but when it has 

excess generation or the market price of power is more economic than its own generation, SCE may sell power from utilityowned generation assets and existing power procurement contracts into, or buy generation and/or ancillary services to meet 

its load requirements from, the day-ahead market. SCE will offer to buy its generation at nodes near the source of the 

generation, but will take delivery at nodes throughout SCE's service territory. Congestion may occur when available energy 

cannot be delivered due to transmission constraints, which results in transmission congestion charges and differences in 

prices at various nodes. The CAISO also offers congestion revenue rights or CRRs, a commodity that entitles the holder to 

receive (or pay) the value of transmission congestion between specific nodes, acting as an economic hedge against 

transmission congestion charges.

Competition

Because SCE is an electric utility company operating within a defined service territory pursuant to authority from the CPUC, 

SCE faces retail competition only to the extent that federal and California laws permit other entities to provide electricity and 

related services to customers within SCE's service territory. While California law provides only limited opportunities for 

customers to choose to purchase power directly from an energy service provider other than SCE, a California statute was 

adopted in 2009 that permits a limited, phased-in expansion of customer choice (direct access) for nonresidential customers. 

SCE also faces some competition from cities and municipal districts that create municipal utilities or community choice 

aggregators. Competition between SCE and other electricity providers is conducted mainly on the basis of price; customers 

seek the lowest cost power available. The effect of this competition on SCE generally is to reduce the number of customers 

purchasing power from SCE, but those departing customers typically continue to utilize and pay for SCE's transmission and 

distribution services.

Technological developments, such as on-site power generation (self generation), pose additional competitive challenges for 

traditional utilities. See "Item 1A. Risk Factors—Risks Relating to SCE—Regulatory Risks." In the area of transmission 

infrastructure, SCE may experience increased competition from merchant transmission providers. The FERC has made 

changes to its transmission planning requirements with the goal of opening transmission development to competition from 

independent developers. In July 2011, the FERC adopted new rules that remove incumbent public utility transmission 

owners' federally-based right of first refusal to construct certain new transmission facilities. The rules direct regional entities, 

such as ISOs, to create new processes that would allow other providers to develop new transmission projects. The new 

processes will not become effective until approved by the FERC, which is expected in late 2012. The majority of SCE's 

2012 – 2014 transmission capital forecast relates to transmission projects that have been approved by the CAISO and barring 

a re-evaluation under the new rules, will not be subject to the new processes. SCE does not expect these projects to be reevaluated. The impact of the new rules on future transmission projects will depend on the processes ultimately implemented 

by regional entities.

Properties

SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, 

which are located primarily in California but also in Nevada and Arizona, deliver power from generating sources to the 

distribution network and consist of lines ranging from 33 kV to 500 kV and substations. SCE's distribution system, which takes 

power from substations to customers, includes over 59,000 circuit miles of overhead lines, 44,000 circuit miles of underground 

lines and over 700 distribution substations, all of which are located in California.
9

SCE owns the generating facilities listed in the following table.

Generating Facility

San Onofre Nuclear

Generating Station

Hydroelectric Plants (36)

Pebbly Beach Generating

Station

Mountainview

Peaker Plants (4)

Palo Verde Nuclear

Generating Station

Four Corners Units 4 and 5

Solar PV Plants (23)

Total

Location

(in CA, unless

otherwise noted)

South of San

Clemente

Various

Catalina Island

Redlands

Various

Phoenix, AZ

Farmington, NM

Various

Fuel Type

Nuclear

Hydroelectric

Diesel

Natural Gas

Gas fueled

Combustion

Turbine

Nuclear

Coal-fired

Photovoltaic

Operator

SCE

SCE

SCE

SCE

SCE

APS

APS

SCE

SCE's

Ownership

Interest (%)

78.21%

100%

100%

100%

100%

15.8%

48%

100%

1

Net Physical

Capacity

(in MW)

2,150

1,176

9

1,050

196

3,739

1,540

53

9,913

SCE's Capacity

pro rata share

(in MW)

1,760

1,176

9

1,050

196

591

739

53

5,574

1 In November 2010, SCE entered into an agreement to sell its interest in Four Corners to APS for approximately $294 million. The sale is 

contingent upon the satisfaction of several conditions and the obtaining of multiple regulatory approvals. Currently SCE estimates that 

the sale will close in the second half of 2012. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. 

Property, Plant and Equipment" for more information.

San Onofre, Four Corners, certain of SCE's substations, and portions of its transmission, distribution and communication 

systems are located on lands owned by the United States or others under licenses, permits, easements or leases, or on public 

streets or highways pursuant to franchises. Certain of the documents evidencing such rights obligate SCE, under specified 

circumstances and at its expense, to relocate such transmission, distribution, and communication facilities located on lands 

owned or controlled by federal, state, or local governments.

Twenty-eight of SCE's 36 hydroelectric plants and related reservoirs are located in whole or in part on U.S.-owned lands 

pursuant to 30- to 50-year FERC licenses that expire at various times between 2012 and 2046. Such licenses impose numerous 

restrictions and obligations on SCE, including the right of the United States to acquire projects upon payment of specified 

compensation. When existing licenses expire, the FERC has the authority to issue new licenses to third parties that have filed 

competing license applications, but only if their license application is superior to SCE's and then only upon payment of 

specified compensation to SCE. New licenses issued to SCE are expected to contain more restrictions and obligations than the 

expired licenses because laws enacted since the existing licenses were issued require the FERC to give environmental 

objectives greater consideration in the licensing process.

Substantially all of SCE's properties are subject to the lien of a trust indenture securing first and refunding mortgage bonds. See 

"Item 8. Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

Seasonality

Due to warm weather during the summer months and SCE's rate design, operating revenue during the third quarter of each 

year is generally higher than the other quarters.
10

EDISON MISSION GROUP INC.

Overview

EMG's competitive power generation business primarily consists of the generation and sale into the PJM market of energy 

and capacity from merchant coal-fired power plants and a portfolio of natural gas and wind projects. EMG's operating results 

were significantly lower in 2011 compared to 2010 due to lower realized energy and capacity prices and generation at the 

coal plants.

At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available 

borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash 

and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility 

maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility and there can be 

no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of 

these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be 

able to, replace these credit lines or any portion of them. EME had $3.7 billion of unsecured notes outstanding at 

December 31, 2011, $500 million of which mature in 2013. Unless energy and capacity prices increase, EME expects that it 

will experience further reductions in cash flow and losses in 2012 and subsequent years. EME's liquidity will be strained by a 

continuation of recent adverse trends, combined with pending debt maturities, higher operating costs and the need to retrofit 

its coal-fired plants to comply with governmental regulations. To address such a scenario, EME would need to consider all 

options available to it, including potential sales of assets or restructurings or reorganization of the capital structure of EME 

and its subsidiaries. 

Homer City failed to obtain sufficient interest from market participants to fund the capital improvements during the process 

undertaken in the fourth quarter of 2011. Homer City is currently engaged in discussions with the owner-lessors regarding the 

potential for such funding. EME expects that the outcome of any such discussions, if successful in providing funding for the 

Homer City plant, will likely result in EME's loss of substantially all beneficial economic interest in and material control of

the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the Homer City plant 

could result in Homer City's default under the lease agreements giving rise to remedies for the owner-lessors and secured 

lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of Homer City, or 

both. For further discussion of these matters, see "Edison International Overview—Management Overview of EMG" in the 

MD&A.

Regulation

Federal Power Act

The FERC has exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission 

services in interstate commerce (other than transmission that is "bundled" with retail sales), including ongoing, as well as 

initial, rate jurisdiction. The FERC also has jurisdiction over the sale or transfer of specified assets, including wholesale 

power sales contracts and generation facilities and, in some cases, jurisdiction over the issuance of securities or the 

assumption of specified liabilities. Dispositions of EMG's jurisdictional assets and certain types of financing arrangements 

may require FERC approval.

Each of EMG's domestic generating facilities is either a qualifying facility, as determined by the FERC, or the subsidiary 

owning the facility is an exempt wholesale generator. Most qualifying facilities, including EMG's qualifying facilities, are 

exempt from the ratemaking and several other provisions of the Federal Power Act. EMG's exempt wholesale generators are 

subject to the FERC's ratemaking jurisdiction under the Federal Power Act, but have been authorized by the FERC to sell 

power at market-based rates. In addition, EMG's power marketing subsidiaries, including EMMT, have been authorized by 

the FERC to make wholesale market sales of power at market-based rates and are subject to FERC ratemaking regulation 

under the Federal Power Act.

If one of the projects in which EMG has an interest were to lose its qualifying facility or exempt wholesale generator status, 

the project would no longer be entitled to the related exemptions from regulation and could become subject to rate regulation 

by the FERC and state authorities. Loss of status could also trigger defaults under covenants contained in the project's power 

sales agreements and financing agreements.

Transmission of Wholesale Power

EMG's projects that sell power to wholesale purchasers other than the local utility to which the project may be interconnected 

require the transmission of electricity over power lines owned by others. The prices and other terms and conditions of 
11

transmission contracts are regulated by the FERC when the entity providing the transmission service is subject to FERC 

jurisdiction.

Markets for Generation

The United States electric industry, including companies engaged in providing generation, transmission, distribution and 

retail sales and service of electric power, has undergone significant deregulation over the last three decades, which has led to 

increased competition, especially in the generation sector. In areas where ISOs and RTOs have been formed, market 

participants have open access to transmission service typically at a system-wide rate. ISOs and RTOs may also operate realtime and day-ahead energy and ancillary service markets, which are governed by FERC-approved tariffs and market rules. 

The development of such organized markets into which independent power producers are able to sell has reduced their 

dependence on bilateral contracts with electric utilities. In addition, capacity markets in various regional wholesale power 

markets compensate supply resources for the capability to supply electricity when needed, and demand resources, for 

electricity they avoid using.

Wholesale Markets

EMG's largest power plants are its coal power plants located in Illinois, which are collectively referred to as the Midwest 

Generation plants, and the Homer City plant located in Pennsylvania. Collectively, both the Midwest Generation plants and 

the Homer City plant are referred to as the coal plants in this annual report. The coal plants sell power primarily into PJM, an 

RTO which includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, 

Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. Sales may also be made from PJM into 

the Midwest Independent Transmission System Operator ("MISO") RTO, which includes all or parts of Illinois, Wisconsin, 

Indiana, Michigan, Ohio and other states in the region, and into the NYISO, which controls the transmission grid and energy 

and capacity markets for New York State.

PJM operates a wholesale spot energy market and determines the market-clearing price for each hour based on bids submitted 

by participating generators indicating the minimum prices at which a bidder is willing to dispatch energy at various 

incremental generation levels. PJM requires all load-serving entities and generators, such as Midwest Generation and Homer 

City, to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM's capacity 

markets have a single market-clearing price for each capacity zone. In May of each year, PJM conducts an annual capacity 

auction ("RPM") to commit generation, energy efficiency and demand side resources three years forward, and to provide a 

long-term pricing signal for the construction of capacity resources.

Fuel Supply

The Midwest Generation plants purchase coal from several suppliers located in the Southern PRB of Wyoming. The total 

volume of coal consumed annually is largely dependent on the amount of generation and has historically ranged between 

17 million to 19 million tons. Coal consumption in the current low natural gas price environment may be lower than the 

historical range. Coal is transported under transportation agreements with Union Pacific Railroad and various short-line 

carriers. In late 2011, Midwest Generation signed new agreements, effective January 1, 2012, to provide fuel transportation 

on a long-term basis. For additional information, see "EMG: Results of Operations—Market Risk Exposures—Commodity 

Price Risk—Coal and Transportation Risk" in the MD&A. As of December 31, 2011, Midwest Generation leased 

approximately 3,400 railcars to transport the coal from the mines to the generating stations, under leases with remaining 

terms that range from less than one year to eight years, with options to extend the leases or purchase some railcars at the end

of the lease terms.

Homer City's Units 1 and 2 have historically consumed approximately 2.8 million to 3.3 million tons of mid-range sulfur coal 

per year. Two types of coal are purchased, ready-to-burn and raw coal. Ready-to-burn coal is of the quality that can be burned 

directly in Units 1 and 2, whereas the raw coal purchased for consumption by Units 1 and 2 must be cleaned in the Homer 

City coal cleaning facility, which has the capacity to clean up to 5 million tons of coal per year. Unit 3 has historically 

consumed approximately 1.5 million to 2 million tons of coal per year and can consume either raw or ready-to-burn coal. 

Coal consumption in the current low natural gas price environment may be lower than the historical range. A wet scrubber 

FGD system for Unit 3 enables this unit to burn less expensive, higher sulfur coal, while still meeting environmental 

standards for emission control. In general, the coal purchased for all three units is acquired locally. For additional 

information, see "Edison International Overview—Management Overview of EMG" and "EMG: Results of Operations—

Market Risk Exposures—Commodity Price Risk—Coal and Transportation Risk" in the MD&A.
12

Competition

EMG is subject to competition from energy marketers, public utilities, government-owned power agencies, industrial 

companies, financial institutions, and other independent power producers. These companies may have competitive 

advantages as a result of scale, the location of their generation facilities, or other factors. Some of EMG's competitors have a 

lower cost of capital than EMG and, in the case of utilities, may be able to recover fixed costs through rate base mechanisms, 

allowing them to build, buy and upgrade generation without relying exclusively on market clearing prices to recover their 

investments.

State and local environmental regulations, particularly those that impose stringent state-specific emission limits in Illinois,

could put EMG's coal plants at a disadvantage compared with competing power plants operating in nearby states and subject 

to less stringent state emission limits or to federal emission limits alone. The CPS puts the Midwest Generation plants at a 

disadvantage compared with competing plants not subject to similar regulations, and federal air quality regulations such as 

CSAPR and the MATS rule will put EMG's coal plants, particularly Homer City, at a disadvantage compared to plants 

utilizing other fuels. Potential future climate change regulations could also put EME's coal plants at a disadvantage compared 

to power plants utilizing other fuels as well as utilities that can also be able to recover climate change compliance costs 

through rate base mechanisms. The ability of EMG's coal plants to compete may be affected by future environmental 

regulations, by governmental and regulatory activities designed to support the construction and operation of power generation 

facilities fueled by renewable energy sources, and by developments such as shale gas technology that lower the price of other 

fuels.
13

Properties

Power Plants in Operation

As of December 31, 2011, EMG's operations consisted of ownership or leasehold interests in the following operating projects

Power Plants

MERCHANT POWER PLANTS

Midwest Generation plants1

Midwest Generation plants1

Homer City plant1

Merchant Wind

Goat Wind

Lookout

Big Sky

CONTRACTED POWER PLANTS – Domestic

Natural Gas

Big 4 Projects

Kern River1

Midway-Sunset1

Sycamore1

Watson

Westside Projects (4)1

Sunrise1

Renewable Energy

Buffalo Bear

Cedro Hill

Community Wind North

Crosswinds

Elkhorn Ridge

Forward

Hardin

High Lonesome

Jeffers

Laredo Ridge

Minnesota Wind projects4

Mountain Wind I

Mountain Wind II

Odin

Pinnacle5

San Juan Mesa

Sleeping Bear

Spanish Fork

Storm Lake1

Taloga

Wildorado

Huntington Waste-to-Energy

Coal

American Bituminous1

CONTRACTED POWER PLANTS – International

Doga

Total

Location

Illinois

Illinois

Pennsylvania

Texas

Pennsylvania

Illinois

California

California

California

California

California

California

Oklahoma

Texas

Minnesota

Iowa

Nebraska

Pennsylvania

Iowa

New Mexico

Minnesota

Nebraska

Minnesota

Wyoming

Wyoming

Minnesota

West Virginia

New Mexico

Oklahoma

Utah

Iowa

Oklahoma

Texas

New York

West Virginia

Republic of Turkey

Primary

Electric

Purchaser2

 PJM

 PJM

PJM

ERCOT

PJM

PJM

SCE

PG&E

SCE

SCE

PG&E

CDWR

WFEC

CSA

NSPC

CBPC

NPPD

CECG

IPLC

APSC

NSPC

NPPD

NSPC/IPLC

PC

PC

MRES

MDGS/USM

SPS

PSCO

PC

MEC

OGEC

SPS

LIPA

MPC

TEDAS

Fuel Type

coal

oil

coal

wind

wind

wind

natural gas

natural gas

natural gas

natural gas

natural gas

natural gas

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

wind

biomass

waste coal

natural gas

EMG's

Ownership

Interest

100%

100%

100%

99.9%

100%

100%

50%

50%

50%

49%

50%

50%

100%

100%

99%

99%

67%

100%

99%

100%

99.9%

100%

75-99%

100%

100%

99.9%

100%

75%

100%

100%

100%

100%

99.9%

38%

50%

80%

3

3

3

3

3

3

3

Net

Physical

Capacity

(in MW)

5,172

305

1,884

150

38

240

300

225

300

385

152

572

19

150

30

21

80

29

15

100

50

80

73

61

80

20

55

120

95

19

108

130

161

25

80

180

11,504

EMG's 

Capacity Pro 

Rata Share

(in MW)

5,172

305

1,884

150

38

240

150

113

150

189

76

286

19

150

30

21

53

29

15

100

50

80

67

61

80

20

55

90

95

19

108

130

161

9

40

144

10,379

1 Plant is operated under contract by an EME operations and maintenance subsidiary or the plant is operated or managed directly by 

an EME subsidiary.
14

2 Electric purchaser abbreviations are as follows:

APSC

CBPC

CDWR

CECG

CSA

ERCOT

IPLC

LIPA

MDGS

MEC

MPC

MRES

Arizona Public Service Company

Corn Belt Power Cooperative

California Department of Water Resources

Constellation Energy Commodities Group, Inc.

City of San Antonio

Electric Reliability Council of Texas

Interstate Power and Light Company

Long Island Power Authority

Maryland Department of General Services

Mid-American Energy Company

Monongahela Power Company

Missouri River Energy Services

NPPD

NSPC

OGEC

PC

PG&E

PJM

PSCO

SCE

SPS

TEDAS

USM

WFEC

Nebraska Public Power District

Northern States Power Company

Oklahoma Gas and Electric Company

PacifiCorp

Pacific Gas & Electric Company

PJM Interconnection, LLC

Public Service Company of Oklahoma

Southern California Edison Company

Southwestern Public Service

Türkiye Elektrik Dagitim Anonim Sirketi

University System of Maryland

Western Farmers Electric Cooperative

3

 Represents EME's current ownership interest. If the project achieves a specified rate of return, EME's interest will decrease.

4

 Composed of six individual wind projects.

5 Two-thirds of project achieved commercial operation in December 2011. The remaining one-third of project achieved commercial 

operation in January 2012.

Significant Customers

For information on EMG's significant customers, see "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 6. Derivative Instruments and Hedging Activities."

Asset Management and Trading Activities

EMG's power marketing and trading subsidiary, EMMT, manages the energy and capacity of EMG's merchant generating 

plants and, in addition, trades electric power, gas, oil and related commodity and financial products, including forwards, 

futures, options and swaps. EMMT segregates its activities into two categories:

• Asset Management–EMMT engages in the sale of energy and capacity and the purchase and sale of fuels, including 

natural gas and fuel oil, through intercompany contracts with EMG's subsidiaries that own or lease EMG's facilities. 

EMG uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, 

capacity, fuel, emission allowances, and transmission rights. The objective of these activities is to sell the output of 

EMG's facilities on a forward basis or to hedge the risk of future changes in prices or price differences between different 

locations. Hedging activities include on-peak and off-peak periods and may include load service requirements contracts 

with local utilities. Transactions related to hedging activities are designated separately from EMMT's trading activities. 

Not all contracts entered into by EMMT for hedging purposes qualify as hedges for accounting purposes.

• Trading–EMMT seeks to generate trading profits from volatility in the price of electricity, capacity, fuels, and 

transmission congestion by buying and selling contracts in wholesale markets under limitations approved by EMG's risk 

management committee.
15

Energy and Infrastructure Investments

EMG's energy and infrastructure investments include leveraged leases and affordable housing projects in the United States. 

As of December 31, 2011, Edison Capital was the lessor with an investment balance (including current lease receivable) of 

$117 million in the following leveraged leases:

Transaction

Vidalia: selling

power to Entergy

Louisiana, City of

Vidalia

Beaver Valley:

selling power to Ohio

Edison Company,

Centerior Energy

Corporation

American Airlines

Asset

192 MW

hydro power plant

836 MW

nuclear power plant 

3 Boeing 767 ER

aircraft

Location

Vidalia, Louisiana

Shippingport, Pennsylvania

Domestic and international

routes

Basic Lease

Term Ends

2020

2017

2016

Investment

Balance

(In millions)

$ 69

$ 46

$ 8 1

1 American Airlines filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code in November 2011. As a 

result, Edison Capital recorded a pre-tax $26 million charge related it its net investments in aircraft leases. 

Seasonality

Due to fluctuations in electric demand resulting from warm weather during the summer months and cold weather during the 

winter months, electric revenues from the coal plants normally vary substantially on a seasonal basis. In addition, 

maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall), further 

reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, 

income from the coal plants is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also

be affected by changes in market prices. For further discussion regarding market prices, see "EMG: Market Risk Exposures

—Commodity Price Risk—Energy Price Risk" in the MD&A.

EMG's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income 

related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.
16

ENVIRONMENTAL REGULATION OF EDISON INTERNATIONAL AND SUBSIDIARIES

Legislative and regulatory activities by federal, state, and local authorities in the United States relating to energy and the 

environment impose numerous restrictions on the operation of existing facilities and affect the timing, cost, location, design,

construction and operation of new facilities by Edison International's subsidiaries, as well as the cost of mitigating the 

environmental impacts of past operations. Many of these laws, regulations and other activities affect both SCE and EMG's 

facilities, although not always to the same extent. The environmental regulations and other developments discussed below 

have the largest impact on fossil-fuel fired power plants, and therefore the discussion in this section focuses on regulations 

applicable to the states of California, New Mexico, Illinois and Pennsylvania, where such facilities are located.

Edison International continues to monitor legislative and regulatory developments and to evaluate possible strategies for 

compliance with environmental regulations. Additional information about environmental matters affecting Edison 

International, including projected environmental capital expenditures, is included in the MD&A under the heading "SCE: 

Liquidity—Capital Investment Plan," "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. 

Commitments and Contingencies" and "—Note 10. Environmental Developments, and "Edison International (Consolidated): 

Liquidity and Capital Resources—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets" in the 

MD&A.

Air Quality

The CAA, which regulates air pollutants from mobile and stationary sources, has a significant impact on the operation of 

fossil fuel plants, especially coal-fired plants. The CAA requires the US EPA to establish concentration levels in the ambient 

air for six criteria pollutants to protect public health and welfare. These concentration levels are known as National Ambient 

Air Quality Standards, or NAAQS. The six criteria pollutants are carbon monoxide, lead, nitrogen dioxide, ozone, particulate 

matter, and SO2.

Federal environmental regulations of these criteria pollutants require states to adopt state implementation plans, known as 

SIPs, for certain pollutants, which detail how the state will attain the standards that are mandated by the relevant law or 

regulation. The SIPs must be equal to or more stringent than the federal requirements and must be submitted to the US EPA 

for approval. Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do 

not (non-attainment areas), and must develop a SIP both to bring non-attainment areas into compliance with the NAAQS and 

to maintain good air quality in attainment areas. If the attainment status of areas changes, states may be required to develop 

new SIPs that address the changes. Many of EMG's facilities are located in areas that have not attained NAAQS for ozone 

(affected by NOx emissions from power plants) and fine particulate matter (affected by SO2 and NOx emissions from power 

plants) and much of Southern California is in a non-attainment area for several criteria pollutants.

As described further below, on December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA, 

which was subsequently embodied in an Illinois rule called the Combined Pollutant Standard or "CPS," to reduce mercury, 

NOx and SO2 emissions at the Midwest Generation plants. The CPS requires Midwest Generation to achieve air emission 

reductions for NOx and SO2, and those reductions should contribute to or effect compliance with various existing US EPA 

ambient air quality standards. It is possible that if lower ozone, particulate matter, NOx or SO2 NAAQS are finalized by US 

EPA in the future, Illinois may implement regulations that are more stringent than those required by the CPS.

Nitrogen Oxide and Sulfur Dioxide

Clean Air Interstate and Cross-State Air Pollution Rules

The CAIR, issued by the US EPA on March 10, 2005, mandated significant reductions in NOx and SO2 emission allowance 

caps under the CAA in 28 eastern states and the District of Columbia. In 2008, the U.S. Court of Appeals for the D.C. Circuit 

initially vacated the CAIR, but later remanded the CAIR to the US EPA for the issuance of a revised rule. The CAIR remains 

in effect until a replacement regulation becomes effective.

On July 6, 2011, the US EPA adopted the Cross-State Air Pollution Rule ("CSAPR"). CSAPR establishes emissions 

reductions for annual SO2 emissions and annual and ozone season NOx emissions in two phases: a first phase originally 

scheduled to be effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a 

second phase effective January 1, 2014 that requires additional reductions in annual SO2 emissions.

In December 2011, the United States Court of Appeals for the District of Columbia granted a stay of CSAPR pending 

completion of its review of the rule's validity. Oral argument is scheduled for April 13, 2012, and a court decision is expected 

during the third quarter of 2012. The court directed the US EPA to continue administering the CAIR until its review is 

completed.
17

CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. If the stay is lifted and CSAPR 

becomes effective, the amount of actual SO2 or NOx emissions from plant operations will need to be matched by a sufficient 

amount of SO2 or NOx allowances that are either allocated or purchased in the open market. In connection with CSAPR, the 

US EPA has, for each phase, established SO2 and NOx allowance allocations for each state and each generating unit subject to 

the regulation, and at the close of the annual or seasonal compliance period, units will need to surrender allowances for each 

ton of SO2 and NOx emitted or face penalties. 

With the staying of CSAPR, CAIR SO2 allowances have been provided and a sufficient supply is available for purchase to 

permit Homer City to continue operations consistent with 2011 levels. If the stay is lifted, the SO2 allowances allocated to 

Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) would be significantly lower than the amount that would be 

required based on Homer City's historical emissions. It is unclear at this time whether Homer City would be able to acquire 

allowances in sufficient quantity to cover its normal operations during Phase I of CSAPR and whether it would be able to 

pass through the cost of such allowances in the marketplace. Accordingly, despite the stay, Homer City continues to evaluate 

alternative options, including reduced dispatch and fuel modifications, for complying with Phase I of CSAPR. The cost of 

allowances, together with possible operational impacts or reductions of output that may be required to comply with Phase I of 

CSAPR, could have a material effect on Homer City.

Homer City has begun work on designing SO2 and particulate emissions control equipment for Units 1 and 2. Based on 

preliminary estimates, Homer City expects the cost of such equipment to be approximately $700 million to $750 million. 

However, construction of these improvements is dependent upon funding from the owner-lessors or other third parties. For 

additional information, see "Edison International Overview—Management Overview of EMG—Homer City Lease."

Revised NAAQS for Sulfur Dioxide

In June 2010, the US EPA finalized the primary NAAQS for SO2 by establishing a new one-hour standard at a level of 75 

parts per billion. In June 2011, Pennsylvania and Illinois submitted their initial recommended attainment/nonattainment 

designations in connection with the standard. Pennsylvania recommended designating Indiana County, where the Homer City 

plant is located, as nonattainment for the SO2 NAAQS. Illinois recommended designating parts of Tazewell County (where 

the Powerton plant is located) and Will and Cook Counties as nonattainment with this standard. The recommended 

designation for parts of Will and Cook Counties included the area where the Will County plant is located, but not the areas 

where Midwest Generation's other plants in those counties are located.

Illinois

On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NOx and 

SO2 emissions at the Midwest Generation plants. The agreement has been embodied in the CPS. All of Midwest Generation's 

Illinois coal-fired electric generating units are subject to the CPS. The CPS also specifies the control technologies that are to 

be installed on some units by specified dates. Midwest Generation must either install the required technology by the specified 

deadline or shut down the unit. The principal emission standards and control technology requirements for NOx and SO2 under 

the CPS are as described below:

NOx Emissions–Beginning in calendar year 2012 and continuing in each calendar year thereafter, Midwest Generation must 

comply with an annual and seasonal NOx emission rate of no more than 0.11 lbs/million Btu. Midwest Generation 

substantially completed installation of SNCR equipment in 2011 for compliance with the emission limitations. Capital 

expenditures relating to these controls were $105 million.

SO2 Emissions–Midwest Generation must comply with an overall SO2 annual emission rate beginning with 0.44 lbs/million 

Btu in 2013 and decreasing annually until it reaches 0.11 lbs/million Btu in 2019 and thereafter.

Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO2

emissions. Use of dry sorbent injection technology in conjunction with low sulfur coal is expected to require substantially 

less capital and time to construct than the use of spray dryer absorber technology, but would likely result in higher ongoing 

operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, 

depending on competitors' costs. For further discussion, see "Edison International Overview—Management Overview of 

EMG—Midwest Generation and Compliance Plans and Cost" in the MD&A.

Pennsylvania

The Homer City plant was subject to the federal CAIR during 2011 and complied with both the NOx and SO2 requirements 

by using existing equipment and purchasing SO2 allowances. Pennsylvania adopted a state version of the CAIR, which the 

US EPA approved in December 2009. Homer City expects to comply with the Pennsylvania CAIR, which is substantially 
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similar to the federal CAIR as it existed prior to the implementation of CSAPR, in the same manner in which it complies with 

the federal standards.

Mercury/Hazardous Air Pollutants

Mercury and Air Toxics Standards Rule

In December 2011, the US EPA announced the Mercury and Toxics Air Standards ("MATS") rule, limiting emissions of 

hazardous air pollutants from coal- and oil-fired electrical generating units. The rule was published in the Federal Register on 

February 16, 2012, and becomes effective on April 16, 2012. EMG does not expect that these standards will require Midwest 

Generation to make material changes to the approach to compliance with state and federal environmental regulations that it 

contemplates for CPS compliance. EMG also does not expect that these standards will require Homer City to make additional 

capital expenditures beyond those that would be required for compliance with CSAPR Phase II.

Illinois

The CPS requires that, beginning in calendar year 2015, and continuing thereafter on a rolling 12-month basis, Midwest 

Generation must either achieve an emission standard of .008 lbs mercury/GWh gross electrical output or a minimum 90% 

reduction in mercury for each unit (except Unit 3 at the Will County Station, which will be included in calendar year 2016). 

Midwest Generation will be required to install cold side electrostatic precipitator or baghouse equipment on Unit 7 at the 

Waukegan Station by December 31, 2013, and on Unit 3 at the Will County Station by December 31, 2015.

Pennsylvania

Pennsylvania currently has no state level mercury regulations.

Ozone

National Ambient Air Quality Standards

In January 2010, the US EPA proposed a revision to the primary and secondary NAAQS for 8-hour ozone that it had finalized 

in 2008. The 8-hour ozone standard established in 2008 was 0.075 parts per million. In January 2010, the US EPA proposed 

establishing a primary 8-hour ozone NAAQS between 0.060 and 0.070 parts per million and a distinct secondary standard to 

protect sensitive vegetation and ecosystems. In September 2011, President Obama announced that the proposed revision was 

being withdrawn. The ozone NAAQS established in 2008 remains in place, but the implementation process must be 

completed before the 0.075 parts-per-million standard can be enforced. The US EPA has indicated that it intends to issue 

initial area designations of attainment, nonattainment, and unclassifiable areas across the nation in 2012. States will then be

required to develop and submit SIPs outlining how compliance with the 2008 NAAQS will be achieved. New primary and 

secondary ozone standards are expected in 2014.

In January 2012, the US EPA indicated that it intended to designate the counties in Illinois where Midwest Generation's coalfired power plants are located as nonattainment with the 2008 NAAQS. In December 2011, the US EPA indicated that it 

intended to designate Indiana County, where the Homer City plant is located, as in attainment with the 2008 NAAQS.

Regional Haze

The regional haze rules under the CAA are designed to prevent impairment of visibility in certain federally designated areas. 

The goal of the rules is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to 

natural background conditions by 2064. Sources such as power plants that are reasonably anticipated to contribute to 

visibility impairment in Class I areas may be required to install best available retrofit technology ("BART") or implement 

other control strategies to meet regional haze control requirements. 

In relation to Four Corners, the US EPA issued its proposed FIP in October 2010. The proposed FIP would require the 

installation of SCR pollution control equipment within designated time periods. In November 2010, SCE and APS entered 

into an agreement for the sale of SCE's interest in Four Corners Units 4 and 5 to APS, subject to regulatory approvals and 

other conditions. Due to the investment constraints of SB 1368, the California law on GHG emission performance standards 

discussed below in "—Greenhouse Gas Regulation—Regional Initiatives and State Legislation," SCE does not expect to be a 

Four Corners participant after the 2016 expiration of the current participant agreements and does not expect to participate in 

any investment in Four Corners SCRs. See "Item 8. Edison International Notes to Consolidated Financial Statements—

Note 2. Property, Plant and Equipment" for more information on the sale of SCE's interest in Four Corners.
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Illinois and Pennsylvania

Both Pennsylvania and Illinois have submitted their proposed SIP revisions to the US EPA to address regional haze. Illinois 

proposed that the emission reductions that the Midwest Generation plants will be required to make pursuant to the CPS, 

discussed above in "—Nitrogen Oxide and Sulfur Dioxide—Illinois," satisfy the BART requirement. Pennsylvania proposed 

that the existing particulate matter emission limits on the Homer City plant, as well as the plant's participation in the CAIR,

would satisfy the BART requirement in that state. Because the CAIR was scheduled to expire on December 31, 2011, the 

US EPA proposed, on December 30, 2011, a limited disapproval of Pennsylvania's SIP, as well as a Federal Implementation 

Plan that would allow the Homer City plant's participation in CSAPR to satisfy the BART requirement. It is unclear how the 

stay of CSAPR will affect the Pennsylvania SIP. EME believes that the control measures being undertaken to comply with 

other environmental regulations will likely satisfy the requirements of these SIPs.

New Source Review Requirements

The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made 

to air emissions sources at the facility. Since 1999, the US EPA has pursued a coordinated compliance and enforcement 

strategy to address NSR compliance issues at the nation's coal-fired power plants. The US EPA has filed enforcement actions 

against Homer City and Midwest Generation alleging NSR violations. For further discussion, see "Item 8. Edison 

International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

New Mexico

In April 2009, APS, as operating agent of Four Corners, received a US EPA request pursuant to Section 114 of the CAA for 

information about Four Corners, including information about Four Corners' capital projects from 1990 to the present. SCE 

understands that in other cases the US EPA has utilized responses to similar Section 114 letters to examine whether power 

plants have triggered NSR requirements under the CAA. In October 2011, four environmental organizations filed a lawsuit 

against the Four Corners owners alleging NSR violations. See "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 2. Property, Plant and Equipment," for information on the sale of SCE's interest in Four Corners.

Water Quality

Clean Water Act

Regulations under the federal Clean Water Act govern critical operating parameters at generating facilities, such as the 

temperature of effluent discharges and the location, design and construction of cooling water intake structures at generating 

facilities. In March 2011, the US EPA proposed standards under the federal Clean Water Act that would affect cooling water 

intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in 

screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities 

(entrainment). The regulations are expected to be finalized by July 2012. The required measures to comply with the proposed 

standards regarding entrainment are subject to the discretion of the permitting authority, and Edison International is unable at 

this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants and San 

Onofre, but are not expected to be material for the Homer City plant, which already has cooling towers.

California—Prohibition on the Use of Ocean-Based Once-Through Cooling

California has a US EPA-approved program to issue individual or group permits for the regulation of Clean Water Act 

discharges. California also regulates certain discharges not regulated by the US EPA. Effective October 1, 2010, the 

California State Water Resources Control Board issued a final policy, which establishes closed-cycle wet cooling as required 

technology for retrofitting existing once-through cooled plants like SCE's San Onofre and many of the existing fossil-fueled 

power plants along the California coast. The final policy required an independent engineering study to be completed prior to 

the fourth quarter of 2013 regarding the feasibility of compliance by California's two coastal nuclear power plants. The policy

may result in significant capital expenditures at San Onofre and may affect its operations. 

Illinois

Midwest Generation is a party to an administrative proceeding before the Illinois Pollution Control Board to determine 

whether more stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des 

Plaines River, which supply cooling water to Midwest Generation's Will County and Joliet Stations, will be implemented. 

The rule, if implemented, is expected to affect the manner in which those stations use water for station cooling. It is not 

possible to predict the timing for resolution of the proceeding, the final form of the rule, or how it would impact the operation 

of the affected stations; however, significant capital expenditures may be required.
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Coal Combustion Wastes

US EPA regulations currently classify coal ash and other coal combustion residuals as solid wastes that are exempt from 

hazardous waste requirements. This classification enables beneficial uses of coal combustion residuals, such as for cement 

production and fill materials. Midwest Generation currently provides a portion of its coal combustion residuals for beneficial 

uses. In June 2010, the US EPA published proposed regulations relating to coal combustion residuals that could result in their 

reclassification. For further discussion see "Item 8. Edison International Notes to Consolidated Financial Statements— 

Note 10. Environmental Developments."

Greenhouse Gas Regulation

There have been a number of federal and state legislative and regulatory initiatives to reduce GHG emissions. Any climate 

change regulation or other legal obligation that would require substantial reductions in GHG emissions or that would impose 

additional costs or charges for the emission of GHGs could significantly increase the cost of generating electricity from fossil 

fuels, and especially from coal-fired plants, as well as the cost of purchased power, which could adversely affect Edison 

International.

Federal Legislative/Regulatory Developments

In June 2010, the US EPA issued the Prevention of Significant Deterioration ("PSD") and Title V Greenhouse Gas Tailoring 

Rule, known as the "GHG tailoring rule." This regulation generally subjects newly constructed sources of GHG emissions 

and newly modified existing major sources to the PSD air permitting program beginning in January 2011 (and later, to the 

Title V permitting program under the CAA); however the GHG tailoring rule significantly increases the emissions thresholds 

that apply before facilities are subjected to these programs. The emissions thresholds for CO2 equivalents in the final rule 

vary from 75,000 tons per year to 100,000 tons per year depending on the date and whether the sources are new or modified.

Regulation of GHG emissions pursuant to the PSD program could affect efforts to modify EMG's or SCE's facilities in the 

future, and could subject new capital projects to additional permitting or emissions control requirements that could delay such

projects. In December 2010, the US EPA announced that it had entered into a settlement with various states and 

environmental groups to resolve a long-standing dispute over regulation of GHGs from electrical generating units pursuant to 

the New Source Performance Standards in the CAA and would propose performance standards for emissions from new and 

modified power plants and emissions guidelines for existing power plants. The specific requirements will not be known until 

the regulations are finalized. Since January 2010, the US EPA's Final Mandatory GHG Reporting Rule has required all 

sources within specified categories, including electric generation facilities, to monitor emissions and to submit annual reports 

to the US EPA by March 31 of each year. EMG's 2011 GHG emissions were approximately 43 million metric tons. SCE's 

2011 GHG emissions were approximately 5.8 million metric tons. 

Regional Initiatives and State Legislation

Regional initiatives and state legislation may also require reductions of GHG emissions and it is not yet clear whether or to 

what extent any federal legislation would preempt them. If state and/or regional initiatives remain in effect after federal 

legislation is enacted, utilities and generators could be required to satisfy them in addition to the federal standards.

Edison International subsidiary operations in California are subject to two laws governing GHG emissions. The first law, the 

California Global Warming Solutions Act of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce 

GHG emissions. AB 32 requires the California Air Resources Board ("CARB") to develop regulations, effective in 2012, that 

would reduce California's GHG emissions to 1990 levels in yearly increments by 2020. In December 2011, the CARB 

regulation was officially published establishing a California cap-and-trade program. The first compliance period under the 

regulations is for 2013 GHG emissions. CARB regulations implementing a cap-and-trade program and the cap-and-trade 

program itself, continue to be the subject of litigation. In December 2011, a federal district court enjoined the Low Carbon 

Fuel Standard, another AB 32 program regulating the carbon content of transportation fuels, on constitutional commerce 

clause grounds. Additional litigation challenging the cap-and-trade program on similar grounds is expected, though no suit 

has been filed to date. 

The second law, SB 1368, required the CPUC and the CEC to adopt GHG emission performance standards restricting the 

ability of California investor-owned and publicly owned utilities, respectively, to enter into long-term arrangements for the 

purchase of electricity. The standards that have been adopted prohibit these entities, including SCE, from entering into longterm financial commitments with generators that emit more than 1,100 pounds of CO2 per MWh, the performance of a 

combined-cycle gas turbine generator. SB 1368 may prohibit SCE from making emission control expenditures at Four 

Corners. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. Property, Plant and 

Equipment" for information on the sale of SCE's interest in Four Corners.
21

California law has also required SCE to increase its electricity generated from renewable resources by at least 1% of its 

annual retail electricity sales per year so that 20% of its annual electricity sales are provided from such resources (the "RPS

Program") by no later than December 31, 2010 or such later date as flexible compliance requirements permit. In accordance 

with the procurement rules and regulations, SCE demonstrated full compliance with the RPS Program in its March 2011 and 

August 2011 filings. 

In April 2011, California enacted a law requiring California retail sellers of electricity to procure 33% of their customers' 

electricity requirements from renewable resources, as defined in the statute. The impact of the new 33% law will depend on 

how the CPUC and CEC implement the law, which remains uncertain. On December 1, 2011, the CPUC approved a decision 

setting procurement quantity requirements for CPUC-regulated retail sellers that incrementally increase to 33% over several 

periods between January 2011 and December 31, 2020. The quantity would remain at 33% of retail sales for each year 

thereafter. Currently SCE estimates its delivery of eligible renewable resources to customers to be 21% of its total energy 

portfolio for 2011.

Litigation Developments

Litigation alleging that GHG is a public and private nuisance may affect Edison International and its subsidiaries, whether or 

not they are named as defendants. The law is unsettled on whether this litigation presents questions capable of judicial 

resolution or political questions that should be resolved by the legislative or executive branches. For further discussion, see

"Item 8. Edison International Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

ITEM 1A. RISK FACTORS

RISKS RELATING TO EDISON INTERNATIONAL

Edison International's subsidiaries are 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. The CPUC regulates SCE's retail operations, and the FERC regulates SCE's 

wholesale operations. The NRC regulates SCE's nuclear power plants. The construction, planning, and project site 

identification of SCE's power plants and transmission lines in California are also subject to the jurisdiction of the California 

Energy Commission (for plants 50 MW or greater), and 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 adversely 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 

would have an adverse effect on SCE's business.

EMG's projects are subject to federal laws and regulations that govern, among other things, transactions by and with 

purchasers of power, including utility companies, the development and construction of generation facilities, the ownership 

and operations of generation facilities, and access to transmission. Generation facilities are also subject to federal, state and 

local laws and regulations that govern, among other things, the geographical location, zoning, land use and operation of a 

project. EMG in the course of its business must obtain and periodically renew licenses, permits and approvals for its 

facilities. The FERC may impose various forms of market mitigation measures, including price caps and operating 

restrictions, where it determines that potential market power might exist and that the public interest requires mitigation. 

Independent System Operators and Regional Transmission Operators may impose bidding and scheduling rules, both to curb 

the potential exercise of market power and to facilitate market functions. EMG is required to surrender emission allowances 

equal to emissions of specific substances in connection with the operation of its facilities. This may require the purchase of 

allowances, which are subject to price volatility and which could be unavailable.

This extensive governmental regulation creates significant risks and uncertainties for Edison International's business. Existing 

regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to SCE, 

EMG or their facilities or operations in a manner that may have a detrimental effect on Edison International's business or 

result in significant additional costs. In addition, regulation adopted via the public initiative process may apply to SCE or 

EMG, or its facilities or operations in a manner that may have a detrimental effect on Edison International's business or result 

in significant additional costs.
22

Edison International's subsidiaries are subject to extensive environmental regulations that may involve significant and 

increasing costs and adversely affect them.

Edison International's subsidiaries are subject to extensive and frequently changing environmental regulations and permitting 

requirements that involve significant and increasing costs and substantial uncertainty. SCE and EMG devote significant 

resources to environmental monitoring, emissions 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 adversely affect operations, particularly of the coal-fired plants. 

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 continued operation of SCE and EMG facilities, particularly the 

coal-fired facilities, is expected to require substantial capital expenditures for environmental controls or cessation of 

operations. Cessation of operations of such coal-fired plants at EMG would have a material adverse effect on EMG. SCE and 

EMG may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or 

with respect to offsite waste disposal sites that have been used in its operations. Current and future state laws and regulations 

in California also could increase the required amount of power that must be procured from renewable resources. For further 

discussion of the environmental regulations applicable to Edison International and its subsidiaries, see "Item 1. Business—

Environmental Regulation of Edison International and Subsidiaries" and "Item 8. SCE Notes to Consolidated Financial 

Statements—Note 10. Environmental Developments."

Edison International's liquidity depends on SCE's ability to pay dividends to Edison International and its 

subsidiaries' payment of tax-allocation payments that may become due to Edison International.

Edison International is a holding company and, as such, it has no operations of its own. Edison International's ability to meet

its financial obligations and to pay dividends on its common stock at the current rate 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. SCE and EMG may also owe tax-allocation payments to Edison International under applicable tax-allocation or 

payment agreements. Financial market and economic conditions may have an adverse effect on Edison International's 

subsidiaries. See "Risks Relating to SCE" and "Risks Relating to EMG" below for further discussion.

The businesses of Edison International's subsidiaries may be adversely affected by technological developments.

Technological advancements such as energy storage or self generation via solar panels may adversely affect the economics of 

SCE's business as a regulated utility. Other technological advancements in the area of power production that create or 

increase the supply of less expensive power, such as shale natural gas extraction technology, may adversely affect EMG's 

business as an independent merchant power producer. See "Risks Relating to SCE" and "Risks Relating to EMG" below for 

further discussion.

The generation, transmission and distribution of electricity are dangerous and involve inherent risks of injury to 

employees and the general public.

Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical 

equipment. Injuries caused by such contact can subject SCE and EMG to liability that, despite the existence of insurance 

coverage, can be significant. In the wake of recent natural disasters such as windstorms, which can cause wildfires, pole 

failures and associated property damage and outages, 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. Such penalties and liabilities could be significant but are very difficult to predict. The range of possible penalties 

and liabilities includes amounts that could adversely affect SCE's and EMG's liquidity and results of operations.

RISKS RELATING TO SCE

Regulatory Risks

SCE's financial results depend upon its ability to recover its costs 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 capital investment plan, increasing procurement of renewable power, increasing environmental regulations, 
23

moderating demand, and the cumulative impact of other public policy requirements, collectively place continuing upward 

pressure on customer rates. Increases in self generation also reduce the pool of customers from whom fixed costs are 

recovered, while costs potentially increase due to system modifications that may be necessary to cope with the systemic 

effects of self-generation. Customers that self-generate their own power do not currently pay most transmission and 

distribution charges and are only subject to certain non-bypassable charges. The net result is to increase utility rates further 

for those customers who do not self-generate, which encourages more self generation and further rate increases. If SCE is 

unable to obtain a sufficient rate increase or to recover material amounts of its costs in rates in a timely manner or recover an 

adequate return on capital, its financial condition and results of operations could be materially adversely affected. For further 

information on SCE's rate requests, see "Edison International Overview—Management Overview of SCE—2012 General 

Rate Case" and "—FERC Formula Rates" in the MD&A.

SCE's energy procurement activities are subject to regulatory and market risks that could adversely 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, as well as 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 to 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 adversely affect SCE's liquidity and results of operations. See "SCE: 

Liquidity and Capital Resources—Market Risk Exposures" in the MD&A.

Operating Risks

SCE's financial condition and results of operations could be materially adversely affected if it is unable to successfully 

manage the risks inherent in operating and improving 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 one 

of the largest infrastructure investment programs in its history, which involves multiple large-scale projects in multiple 

locations. This substantial increase in activity from SCE's historical levels 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 improving 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, 

system limitations and degradation, and interruptions in necessary supplies. For example, SCE has recently experienced 

significant additional costs and disruptions in the progress of its Tehachapi Renewable Transmission Project. See "SCE: 

Liquidity and Capital Resources—Capital Investment Plan" in the MD&A.

SCE's systems and network infrastructure may be vulnerable to 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 the U.S. national electric grid and other energy infrastructures have potential 

vulnerabilities to cyber attacks and disruptions and that such cyber threats are becoming increasingly sophisticated and 

dynamic. SCE's operations require the continuous operation of critical information technology systems and network 

infrastructure. 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 and/or sensitive confidential personal and other 

data could be compromised, which could adversely affect SCE's financial condition and results of operations. See "Item 1. 

Business—Southern California Edison Company—Regulation—NERC" for further discussion.

There are inherent risks associated with operating nuclear power generating facilities.

Continued NRC scrutiny of San Onofre may result in additional corrective actions that will increase operations and 

maintenance costs or require additional capital expenditures.
24

San Onofre is subject to extensive oversight and scrutiny of the NRC. This scrutiny may result in SCE being required to take 

additional corrective actions and incur increased operations and maintenance expenses or new capital expenditures. If SCE is 

unable to take effective corrective actions required by the NRC, the NRC has the authority to impose fines or shut down a 

unit, or both, depending upon the NRC's assessment of the severity of the situation, until compliance is achieved. See 

"Item 1. Business—Southern California Edison Company—Regulation—Nuclear Power Plant Regulation" for further 

discussion.

Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection which is 

currently approximately $12.6 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 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 $12.6 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 $12.6 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. See "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 9. Commitments and Contingencies—Nuclear Insurance."

Spent fuel storage capacity could be insufficient to permit long-term operation of SCE's nuclear plants.

The U.S. Department of Energy has defaulted on its obligation to begin accepting spent nuclear fuel from commercial nuclear 

industry participants by January 31, 1998. If SCE or the operator of Palo Verde were unable to arrange and maintain 

sufficient capacity for interim spent-fuel storage now or in the future, it could hinder the operation of the plants and impair

the value of SCE's ownership interests until storage could be obtained, each of which may have a material adverse effect on 

SCE.

SCE's insurance coverage for wildfires arising from its ordinary operations may not be sufficient and Edison 

International may not be able to obtain sufficient insurance on SCE's behalf for such occurrences.

Edison International has been experiencing increased costs and difficulties in obtaining insurance coverage for wildfires that 

could arise from SCE's ordinary operations. In addition, the insurance Edison International has obtained on SCE's behalf 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 and adversely 

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. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 10. Environmental 

Developments."

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 would be adversely 

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 arrange financing as well as its ability to refinance debt and make scheduled payments of 

principal and interest 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 failure to obtain 

additional capital from time to time would have a material adverse effect on SCE's liquidity and operations. See "SCE: 

Liquidity and Capital Resources—Capital Investment Plan" and "—Historical Segment Cash Flows" in the MD&A.

RISKS RELATING TO EMG

Liquidity Risks

EME and its subsidiaries have significant cash requirements, limited sources of capital and expect to incur substantial 

losses in 2012 and subsequent years.

At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available 
25

borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash 

and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility 

maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility and there can be 

no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of 

these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be 

able to, replace these credit lines or any portion of them.

As of December 31, 2011, EME's consolidated debt was approximately $4.9 billion, of which $1.2 billion was nonrecourse 

project debt of EME's subsidiaries and the balance was senior unsecured debt of EME. In addition, EME's subsidiaries had 

$2.6 billion of long-term, power plant lease obligations that are due over a period ranging up to 23 years. Compliance with 

current and forthcoming environmental requirements will add to EME's near-term liquidity needs.

Unless energy and capacity prices increase, EME expects that it will experience further losses and reductions in cash flow in 

2012 and subsequent years. EME's liquidity will be strained by a continuation of recent adverse trends combined with 

pending debt maturities, higher operating costs and the need to retrofit its coal-fired plants to comply with governmental 

regulations. EME's and Midwest Generation's deteriorating financial results and below-investment grade credit status may 

limit their ability to extend or replace credit facilities, including those maturing in 2012, should they choose to do so, and the 

terms and conditions of any refinancing could be substantially less favorable than those in previous credit facilities, 

depending on market conditions. In the case of a further downgrade, EME expects that these negative effects would become 

more pronounced. If cash flow and other means for assuring liquidity are unavailable or insufficient, EME may be unable to 

complete environmental improvements at its coal plants (which in turn could lead to unit shutdowns) or to pay its senior debt 

as it matures. If EME's credit facilities are not replaced, EME's ability to hedge its merchant coal exposure or carry out its 

trading activities may also be limited. The terms of EME's and its subsidiaries' debt instruments may restrict EME's ability to

sell assets or incur secured indebtedness, and EME's subsidiaries' debt instruments may limit EME's ability to seek additional 

capital, or restructure or refinance debt to satisfy liquidity needs. For further discussion, see "EMG: Liquidity and Capital 

Resources" in the MD&A.

EME receives tax-allocation payments from Edison International only if, and only to the extent that, EME is included 

in the consolidated tax returns of Edison International and Edison International is able to utilize tax losses and credits 

generated by EME. EME may be required to make tax-allocation payments to Edison International.

EME's right to receive tax-allocation payments and the amount of and timing of those payments are dependent on the 

inclusion of EME in the consolidated income tax returns of Edison International and other factors, including the amount of 

consolidated taxable income and net operating losses of Edison International, and other tax items of EME, its subsidiaries, 

and other subsidiaries of Edison International. Edison International has not been able to fully utilize EME's consolidated tax 

losses and credits as a result of accelerated tax deductions taken by the consolidated group under the Small Business Jobs Act 

of 2010 and the 2010 Tax Relief Act and SCE's priority over EME in the utilization of available tax benefits. Realization of 

EME's tax losses and tax credits is not expected to begin again until at least 2013, subject to future changes in tax laws and 

Edison International's taxable income, and it may take several years before such benefits can be fully utilized. As of 

December 31, 2011, EME had recorded deferred tax assets of $520 million related to loss carryforwards and unused credits. 

EME expects to make tax-allocation payments to Edison International during 2012 of approximately $185 million as a result 

of the reallocation of tax obligations from an expected Edison International consolidated net operating loss in 2011.

These arrangements are subject to the terms of the tax-allocation and payment agreements among Edison International, EME 

and other Edison International subsidiaries. The agreements under which EME makes and receives tax-allocation payments 

may be terminated by the immediate parent company at any time, by notice given before the first day of the first year with 

respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with 

respect to any tax year beginning prior to the notice. See "EMG: Liquidity and Capital Resources—Intercompany TaxAllocation Agreement" in the MD&A.

Regulatory and Environmental Risks

The controls imposed on EMG's coal plants as a result of environmental regulations, including the Combined 

Pollutant Standard may require material expenditures or unit shutdowns.

Capital expenditures relating to required environmental controls for EMG's coal plants (including the CPS, to which all of 

Midwest Generation's coal-fired generating units are subject) are expected to be significant. In February 2012, EME decided 

to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014 and concluded it was less 

likely to install environmental controls at the Waukegan Station and Joliet Unit 6. EME may ultimately decide to shut down 

the Waukegan Station and Joliet Unit 6, and possibly other units, rather than make improvements. Unit shutdowns could have 
26

an adverse effect on EMG's business, results of operation and financial condition. For more information about EMG's plans 

for environmental compliance, see "Item 1. Business—Environmental Regulation of Edison International and Subsidiaries—

Air Quality—Nitrogen Oxide and Sulfur Dioxide," "Edison International (Consolidated): Liquidity and Capital Resources—

Critical Accounting Estimates and Policies" in the MD&A, and "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 10. Environmental Developments."

Market Risks

EMG has substantial interests in merchant energy power plants which are subject to market risks related to wholesale 

energy prices because they operate without long-term power purchase agreements. Wholesale energy prices have 

substantially declined in recent years.

EMG's merchant energy power plants do not have long-term power purchase agreements. Because the output of these power 

plants is not committed to be sold under long-term contracts, these projects are subject to market forces which determine the 

amount and price of energy, capacity and ancillary services sold from the power plants. Unlike most other commodities, 

electric power can only be stored on a very limited basis and generally must be produced when it is to be used. As a result, 

the wholesale power markets are subject to significant and unpredictable price fluctuations over relatively short periods of 

time. Due to the volume of sales into PJM from the coal plants, EMG has concentrated exposure to market conditions and 

fluctuations in PJM. Prices for power and capacity have declined significantly due largely to lower natural gas prices and 

have been affected in recent years by increased use of demand response technology, changes in final demand for power 

during the economic slowdown, and technological developments that have increased access to natural gas shale reserves, 

resulting in substantial declines in market prices for natural gas which supplies power plants that compete with EMG's coal 

plants.

Market prices of energy, capacity and ancillary services sold from these power plants are influenced by multiple factors 

beyond EMG's control, and thus there is considerable uncertainty whether or when current depressed prices will recover. 

EMG's hedging activities may not cover the entire exposure of its assets or positions to market price volatility, and the level

of coverage will vary over time. The effectiveness of EMG's hedging activities may depend on the amount of credit available 

to post collateral, either in support of performance guarantees or as cash margin, and liquidity requirements may be greater 

than EMG anticipates or will be able to meet. EMG cannot provide assurance that its hedging strategies will successfully 

mitigate market risks. For more detail on these matters, see "EMG: Market Risk Exposures—Commodity Price Risk" in the 

MD&A.

EMG's financial results can be affected by changes in prices, transportation cost, and supply interruptions related to 

fuel, sorbents, and other commodities used for power generation and emission controls.

In addition to volatile power prices, EMG's business is subject to changes in the cost of fuel, sorbents, and other commodities 

used for power generation and emission controls, and in the cost of transportation. These costs can be volatile and are 

influenced by many factors outside of EMG's control. The price at which EMG can sell its energy may not rise or fall at the 

same rate as a corresponding rise or fall in commodity costs. Operations at the coal plants are dependent upon the availability

and affordability of coal which is available only from a limited number of suppliers and which, in the case of Midwest 

Generation, is transported by rail under a multi-year long-term transportation contract. All of these factors may have an 

adverse effect on EMG's financial condition and results of operations. See "EMG: Market Risk Exposures—Commodity 

Price Risk" in the MD&A.

Competition could adversely affect EMG's business

EMG has numerous competitors in all aspects of its business some of whom may have greater liquidity, greater access to 

credit and other financial resources, lower cost structures, greater ability to withstand losses, larger staffs or more experience 

than EMG. Multiple participants in the wholesale markets, including many regulated utilities, have a lower cost of capital 

than most merchant generators and often are able to recover fixed costs through rate base mechanisms, allowing them to 

build, buy and upgrade generation assets without relying exclusively on market clearing prices to recover their investments. 

These factors could affect EMG's ability to compete effectively in the markets in which those entities operate. Newer plants 

owned by EMG's competitors are often more efficient than EMG's facilities and may also have lower costs of operation. Over 

time, some of EMG's merchant facilities may become obsolete in their markets, or be unable to compete with such plants.

Operating Risks

EMG's capital projects may not be successful.

EMG's capital projects are subject to risks including, without limitation, risks related to financing, construction, permitting, 
27

and governmental approvals. EME may be required to spend significant amounts before it can determine whether a project is 

feasible or economically attractive. The timing of such projects may be delayed beyond the date that equipment is ready for 

installation, in which case EMG may be required to incur material equipment and/or material costs with no deployment plan 

at delivery. Due to competing capital needs, EMG's further development of its renewable business will depend upon the 

availability of third-party equity capital.

EMG's projects may be affected by general operating risks and hazards customary in the power generation industry. 

EMG may not have adequate insurance to cover all these hazards.

The operation of power generation facilities is a potentially dangerous activity that involves many operating risks, including 

transmission disruptions and constraints, equipment failures or shortages, and system limitations, degradation and 

interruption. EMG's operations are also subject to risks of human performance and workforce capabilities. There can be no 

assurance that EMG's insurance will be sufficient or effective under all circumstances or protect against all hazards to which 

EMG may be subject, or that insurance coverage will continue to be available on terms similar to those presently available, or 

at all. EMG has a number of older facilities that are subject to higher risks of failure or outage, and EMG has in the past 

experienced serial defects in certain models of wind turbines deployed at its wind projects.

Uncertainties in EMG's future operations could affect its ability to attract and retain skilled people.

Uncertainties concerning EMG's future operations could affect its ability to attract and retain qualified personnel with 

experience in the energy industry. If EMG is unable to successfully attract and retain an appropriately qualified workforce, its 

results of operations will be negatively affected.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

As a holding company, Edison International does not directly own any significant properties other than the stock of its 

subsidiaries. The principal properties of SCE are described above under "Item 1. Business—Southern California Edison 

Company—Properties." Properties of EMG are described above under "—Edison Mission Group Inc.—Properties."

ITEM 3. LEGAL PROCEEDINGS

Midwest Generation New Source Review and Other Litigation

Information about the Midwest Generation New Source Review and Other Litigation appears in "Item 8. Edison International 

Notes to the Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies."

Homer City New Source Review and Other Litigation

Information about the Homer City New Source Review and Other Litigation appears in "Item 8. Edison International Notes 

to the Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies."
28

Pursuant to Form 10-K's General Instruction G(3), the following information is included as an additional item in Part I:

EXECUTIVE OFFICERS OF THE REGISTRANT

Executive Officer

Theodore F. Craver, Jr.

Robert L. Adler

Polly L. Gault

W. James Scilacci

Janet T. Clayton

Daryl D. David

Bertrand A. Valdman

Mark C. Clarke

Ronald L. Litzinger

Pedro J. Pizarro

Age at

December 31,

2011

60

64

58

56

57

57

49

55

52

46

Company Position

Chairman of the Board, President and Chief Executive Officer, Edison

International

Executive Vice President and General Counsel, Edison International

Executive Vice President, Public Affairs, Edison International

Executive Vice President, Chief Financial Officer and Treasurer, Edison International

Senior Vice President, Corporate Communications, Edison International

Senior Vice President, Human Resources, Edison International

Senior Vice President, Strategic Planning

Vice President and Controller, Edison International

President, SCE

President, EMG and EME

As set forth in Article IV of Edison International's and the relevant subsidiary's Bylaws, the elected officers of Edison 

International and its subsidiaries are chosen annually by, and serve at the pleasure of, Edison International and the relevant 

subsidiary's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from

service, or until their respective successors are elected. All of the officers of Edison International and its subsidiaries have 

been actively engaged in the business of Edison International and its subsidiaries for more than five years, except for 

Messrs. Adler, David, and Valdman, and Ms. Clayton, and have served in their present positions for the periods stated below. 

Additionally, those officers who have had other or additional principal positions in the past five years had the following 

business experience during that period:
29

Executive Officers

Theodore F. Craver, Jr.

Robert L. Adler

Polly L. Gault

W. James Scilacci

Janet T. Clayton

Daryl D. David

Bertrand A. Valdman

Mark C. Clarke

Ronald J. Litzinger

Pedro J. Pizarro

Company Position

Chairman of the Board, President and Chief

Executive Officer, Edison International

President, Edison International

Chairman of the Board, President and Chief

Executive Officer, EMG

Chairman of the Board, President and Chief

Executive Officer, EME

Executive Vice President and General Counsel,

Edison International

Executive Vice President, Edison International

Partner, Munger, Tolles & Olson LLP1

Executive Vice President, Public Affairs, Edison

International

Executive Vice President, Public Affairs, SCE

Senior Vice President, Public Affairs, Edison

International and SCE

Executive Vice President, Chief Financial Officer and 

Treasurer, Edison International

Senior Vice President and Chief Financial Officer, EME

Senior Vice President and Chief Financial Officer, EMG

Senior Vice President, Corporate Communication,

Edison International

President, Think Cure2

Assistant Managing Editor, Los Angeles Times3

Senior Vice President, Human Resources, Edison

International

Executive Vice President & Chief Human Resources

Officer, Washington Mutual, Inc.4

Senior Vice President, Strategic Planning, 

Edison International

Executive Vice President, Chief Operating Officer 

Puget Sound Energy5

Senior Vice President, Chief Financial Officer

Puget Sound Energy5

Vice President and Controller, Edison International

Vice President and Controller, EME

President, SCE

Chairman of the Board, President and Chief

Executive Officer, EMG and EME

Senior Vice President, Transmission

and Distribution, SCE

President, EMG and EME

Executive Vice President, Power Operations, SCE

Senior Vice President, Power Procurement, SCE

Effective Dates

August 2008 to present

April 2008 to July 2008

November 2005 to March 2008

January 2005 to March 2008

August 2008 to present

July 2008 to August 2008

January 1978 to June 2008

March 2007 to present

March 2007 to September 2008

March 2006 to February 2007

August 2008 to present

March 2005 to July 2008

November 2005 to July 2008

April 2011 to present

Jan 2008 to April 2011

June 2004 to September 2007

June 2009 to present

May 2000 to October 2008

March 2011 to present

May 2007 to March 2011

December 2003 to May 2007

August 2009 to present

January 2003 to July 2009

January 2011 to present

April 2008 to December 2010

May 2005 to March 2008

January 2011 to present

April 2008 to December 2010

May 2005 to March 2008

1

2

3

4

5

Munger, Tolles & Olson LLP is a California-based law firm. Mr. Adler also served as a Co-Managing Partner.

Think Cure is a community-based nonprofit organization that raises funds to accelerate collaborate research to cure cancer and is not a parent, affiliate

or subsidiary of Edison International.

The Los Angeles Times is a daily newspaper published in Los Angeles, California and is not a parent, affiliate or subsidiary at Edison International.

Washington Mutual was a bank holding company and the former owner of Washington Mutual Bank and is not a parent, subsidiary or affiliate of

Edison International.

Puget Sound Energy is a regulated energy utility in Washington State and is not a parent, affiliate or subsidiary of Edison International.
30

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND 

ISSUER PURCHASES OF EQUITY SECURITIES.

Edison International Common Stock is traded on the New York Stock Exchange under the symbol "EIX."

Market information responding to Item 5 is included in "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 19. Quarterly Financial Data." There are restrictions on the ability of Edison International's subsidiaries to 

transfer funds to Edison International that materially limit the ability of Edison International to pay cash dividends. Such 

restrictions are discussed in the MD&A under the heading "Edison International Parent and Other" and in "Item 8. Edison 

International Notes to Consolidated Financial Statements—Note 5. Debit and Credit Agreements." The number of common 

stockholders of record of Edison International was 45,430 on February 24, 2011. Additional information concerning the 

market for Edison International's Common Stock is set forth on the cover page of this report. The description of Edison 

International's equity compensation plans required by Item 201(d) of Regulation S-K is incorporated by reference to "Part III

—Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" of this 

report.

Issuer Purchases of Securities

The following table contains information about all purchases of Edison International Common Stock made by or on behalf of 

Edison International in the fourth quarter of 2011.

Period

October 1, 2011 to

October 31, 2011

November 1, 2011 to

November 30, 2011

December 1, 2011 to

December 31, 2011

Total

(a) Total

Number of Shares

(or Units)

Purchased1

499,480

812,326

446,349

1,758,155

(b) Average

Price Paid per 

Share (or Unit)1

$ 38.84

$ 39.46

$ 40.71

$ 39.60

(c) Total

Number of Shares

(or Units)

Purchased

as Part of

Publicly

Announced

Plans or

Programs

—

—

—

—

(d) Maximum

Number (or

Approximate

Dollar Value)

of Shares

(or Units) that May

Yet Be Purchased

Under the Plans or

Programs

—

—

—

—

1

The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in

connection with Edison International's: (i) 401(k) Savings Plan; (ii) Dividend Reinvestment and Direct Stock Purchase Plan; and

(iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or

participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as

a result of the transactions.
31

Comparison of Five-Year Cumulative Total Return

Edison International

S & P 500 Index

Philadelphia Utility Index

At December 31,

2006

$ 100

100

100

2007

$ 120

105

119

2008

$ 74

66

87

2009

$ 84

84

95

2010

$ 96

97

101

2011

$ 107

99

120

Note: Assumes $100 invested on December 31, 2006 in stock or index including reinvestment of dividends. Performance of the

Philadelphia Utility Index is regularly reviewed by management and the Board of Directors in understanding Edison International's

relative performance and is used in conjunction with elements of the company's incentive compensation program.
32

ITEM 6. SELECTED FINANCIAL DATA

Selected Financial Data: 2007 – 2011 

(in millions, except per-share amounts)

Edison International and Subsidiaries

Operating revenue

Operating expenses

Income from continuing operations

Net income

Net income (loss) attributable to common

shareholders

Weighted-average shares of common stock

outstanding (in millions)

Basic earnings (loss) per share:

Continuing operations

Discontinued operations

Total

Diluted earnings per share

Dividends declared per share

Total assets

Long-term debt

Preferred and preference stock of utility

Common shareholders' equity

2011

$ 12,760

$ 12,440

$ 24

$ 21

$ (37)

326

$ (0.10)

$ (0.01)

$ (0.11)

$ (0.11)

$ 1.285

$ 48,039

$ 13,689

$ 1,029

$ 10,055

2010

$ 12,409

$ 10,283

$ 1,303

$ 1,307

$ 1,256

326

$ 3.83

$ 0.01

$ 3.84

$ 3.82

$ 1.265

$ 45,530

$ 12,371

$ 907

$ 10,583

2009

$ 12,361

$ 10,963

$ 952

$ 945

$ 849

326

$ 2.61

$ (0.02)

$ 2.59

$ 2.58

$ 1.245

$ 41,444

$ 10,437

$ 907

$ 9,841

2008

$ 14,112

$ 11,549

$ 1,348

$ 1,348

$ 1,215

326

$ 3.69

$ —

$ 3.69

$ 3.68

$ 1.225

$ 44,615

$ 10,950

$ 907

$ 9,517

2007

$ 12,868

$ 10,359

$ 1,307

$ 1,305

$ 1,098

326

$ 3.34

$ (0.01)

$ 3.33

$ 3.31

$ 1.175

$ 37,523

$ 9,016

$ 915

$ 8,444

The selected financial data was derived from Edison International's audited financial statements and is qualified in its entirety 

by the more detailed information and financial statements, including notes to these financial statements, included in this 

annual report.
33

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF 

OPERATIONS

EDISON INTERNATIONAL OVERVIEW

Highlights of Operating Results

(in millions)

Net Income (Loss) attributable to Edison International

SCE

EMG

Edison International Parent and Other

Edison International Consolidated

Less: Non-Core Items

Asset impairments and other charges:

 EMG – Homer City Plant

 EMG – Fisk, Crawford and Waukegan Stations

 EMG – Wind related charges and other

EMG – Write-down of net investment in aircraft

leases

 EMG – Write-down of capitalized costs

EMG – Gain on sale of March Point

Global Settlement:

SCE

EMG1

Edison International Parent and Other

SCE – tax impact of health care legislation

SCE – regulatory items

Edison International Parent and Other – deferred taxes

EMG discontinued operations

Total non-core items

Core Earnings (Losses)

SCE

EMG

Edison International Parent and Other

Edison International Consolidated

2011

$ 1,085

(1,089)

(33)

(37)

(623)

(386)

(41)

(16)

—

5

—

—

—

—

—

(21)

(3)

(1,085)

1,085

(25)

(12)

$ 1,048

2010

$ 1,040

224

(8)

1,256

—

—

—

—

(24)

—

95

52

28

(39)

—

—

4

116

984

192

(36)

$ 1,140

Change

$ 45

(1,313)

(25)

(1,293)

(623)

(386)

(41)

(16)

24

5

(95)

(52)

(28)

39

—

(21)

(7)

(1,201)

101

(217)

24

$ (92)

2009

$ 1,226

(395)

18

849

—

—

—

—

—

—

306

(610)

50

—

46

—

(7)

(215)

874

222

(32)

$ 1,064

1 Includes termination of Edison Capital's cross-border leases in 2009 and state tax impact of the Global Settlement with the IRS.

Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United 

States. Management uses core earnings by principal operating subsidiary internally for financial planning and for analysis of 

performance. Core earnings (losses) by principal operating subsidiary are also used when communicating with analysts and 

investors regarding our 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 and income or loss from significant discrete items that management does not consider representative of ongoing 

earnings, such as: exit activities, including lease terminations, sale of certain assets, early debt extinguishment costs and other 

activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings.

SCE's 2011 core earnings increased $101 million primarily due to rate base growth. 

EMG's 2011 core earnings declined $217 million due to lower realized energy and capacity prices along with lower 
34

generation from merchant coal plants, higher plant maintenance costs from outages, higher interest expense related to 

renewable projects, and lower trading income. 

Edison International Parent and Other 2011 core results changed primarily due to higher tax benefits in 2011 compared to 

2010.

Consolidated non-core items for Edison International included:

• An after-tax earnings charge of $1.09 billion ($1.76 billion pre-tax) recorded in the fourth quarter of 2011 resulting 

primarily from the impairment the Homer City, Fisk, Crawford and Waukegan power plants, wind related charges, writedown of a net investment in aircraft leases with American Airlines, and the impact on Edison International consolidated 

deferred income taxes resulting from an increase in the state apportionment rates due to such impairment charges as 

discussed further below and in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 16. 

Asset Impairments, Lease Terminations and Other."

• An after tax earnings benefit of $175 million recorded in 2010 relating to the California impact of the federal Global 

Settlement resulting from acceptance by the California Franchise Tax Board of tax positions finalized with the IRS in 

2009 and receipt of the final interest determination from the Franchise Tax Board. For further discussion of the Global 

Settlement, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes."

• An after-tax earnings charge of $39 million recorded in 2010 to reverse previously recognized federal tax benefits 

eliminated by federal health care legislation enacted in 2010. The health care law eliminated the federal tax deduction for 

retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

• An after-tax earnings charge of $24 million ($40 million pre-tax) recorded in 2010 resulting from the write-off of 

capitalized engineering and other costs related to a change in air emission control technology selection at EMG's 

Powerton Station.

See "SCE: Results of Operations" for discussion of SCE results of operations, including a comparison of 2010 results to 

2009. Also, see "EMG: Results of Operations" for discussion of EMG results of operations, including a comparison of 2010 

results to 2009.

Management Overview of SCE

SCE's core mission is to deliver safe, reliable and affordable electric service to its customers. Accomplishing this mission 

requires balancing competing priorities, including public policies regarding air and water quality, energy efficiency and 

renewable energy and the need to replace aging infrastructure. The accumulation of several major policy mandates is 

expected to add significantly to the cost of electric service, which could cause a growing number of customers to seek to selfgenerate their power. Choices by customers to self-generate results in fewer kilowatt hour sales to absorb the increasing costs

of the electrical system, further increasing rates for SCE's other customers. Working with policy makers to balance competing 

priorities, a key focus of SCE is to manage the costs that drive increases in electricity rates while delivering safe and reliable 

electric service to its customers.

2012 CPUC General Rate Case

SCE filed its 2012 GRC application in November 2010. In October 2011, SCE submitted updated testimony to reflect 

changes in escalation rates, known changes due to governmental actions and changes in the timing of recovery for nuclear 

refueling outages at San Onofre, which taken together changed its requested 2012 base rate revenue requirement to 

$6.3 billion. SCE's updated request, after considering the effects of sales growth and including the impacts of reducing SCE's 

solar program as approved by the CPUC, would result in incremental customer base rate increases of $809 million, 

$117 million and $513 million in 2012, 2013 and 2014, respectively.

The Division of Ratepayer Advocates ("DRA") recommended that SCE's requested 2012 base rate revenue requirement be 

decreased by approximately $850 million, comprised of approximately $630 million in operation and maintenance expense 

reductions and approximately $220 million in capital-related revenue requirement reductions. The Utility Reform Network 

("TURN") and other intervenors recommended an additional $610 million revenue requirement reduction, beyond the DRA 

adjustments, primarily capital-related in nature, as well as disallowances of recorded capital investments for specific projects. 

Intervenors have also recommended changes to SCE's proposed post-test year ratemaking methodology to be used for 2013 

and 2014 as well as limiting the recovery amount of SCE's pension costs. A final decision on the GRC is expected in the first 

half of 2012. The CPUC has authorized the establishment of a GRC memorandum account, which will make the 2012 

revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. Recognition of the revenue for the 
35

period January 1, 2012 through the date of a final decision, as well as any delays in certain expenditures, may impact the 

timing of earnings in 2012.

FERC Formula Rates

The FERC has accepted, subject to refund and settlement procedures, SCE's request to implement formula rates as a means to 

determine SCE's FERC transmission revenue requirement effective January 1, 2012. The formula rates include revenue 

requirements related to construction work in progress ("CWIP") that was previously recovered through a separate 

mechanism. SCE estimates its total 2012 FERC weighted average ROE will be 11.1%, including the previously authorized 50 

basis point incentive for CAISO participation and individual authorized project incentives. The actual weighted average ROE 

and rate base is dependent upon the amount and timing of capital expenditures among FERC incentive and non-incentive 

projects. SCE's request proposed the adoption of a specific formula to calculate a forecasted annual revenue requirement that 

is used to establish rates and is trued-up annually to allow SCE to recover its actual revenue requirement, including its actual 

cost of service, actual rate base and the authorized return on investment. SCE's request also allows SCE to make single-issue 

rate filings requesting changes to certain elements of the formula, including the base ROE, depreciation rates and the retail 

rate structure. SCE and the other parties to the proceeding are currently in settlement negotiations. 

Capital Program

During 2011, SCE continued execution of its capital investment program. Total capital expenditures (including accruals) were 

$3.9 billion in 2011 compared to $3.8 billion in 2010. The level of future spending is significantly dependent on a final 

outcome of SCE's 2012 GRC decision and the timing, scope and approvals of major transmission projects. SCE's capital 

program for 2012 – 2014 is focused primarily in the following areas:

• Maintaining reliability and expanding the capability of SCE's transmission and distribution system.

• Upgrading and constructing new transmission lines and substations for system reliability and increased access to 

renewable energy, including the Tehachapi, Devers-Colorado River, Eldorado-Ivanpah, and Red Bluff projects.

• Completing installation of digital meters in households and small businesses, referred to as EdisonSmartConnectTM. 

Through 2011, SCE installed 3.8 million meters and plans to install the remaining 1.2 million meters during 2012.

• Generation capital projects for nuclear and hydro-electric plants.

SCE forecasts capital expenditures in the range of $11.8 billion to $13.2 billion for 2012 – 2014. 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 as discussed further under "SCE: Liquidity and Capital 

Resources—Capital Investment Plan." SCE has experienced significant cost pressures on its Tehachapi and Devers-Colorado 

River Transmission Projects, primarily related to environmental monitoring and mitigation costs, scope changes and schedule 

delays. Currently, SCE is completing the final engineering design for these projects and expects to file revised cost estimates

with the CPUC later this year. Subject to further permitting and schedule delays, SCE has revised its direct capital 

expenditure estimates for the Tehachapi Project to $2.5 billion from $2.1 billion and revised its estimates for the DeversColorado River Project to $860 million from $649 million. The Tehachapi Project may be further impacted by issues related 

to aviation marking and lighting and community opposition to portions of the line, as further discussed in "SCE: Liquidity 

and Capital Resources—Capital Investment Plan." Capital program cost increases have been partially offset by expenditures 

for other transmission reliability projects, which were deferred due to delays from once-through cooling requirements for 

coastal generating plants. SCE plans to utilize cash generated from its operations, tax benefits and issuance of additional debt 

and preferred equity to fund its capital needs.

Management Overview of EMG

EMG's competitive power generation business primarily consists of the generation and sale into the PJM market of energy 

and capacity from merchant coal-fired power plants and a portfolio of natural gas and wind projects. EMG's operating results 

were significantly lower in 2011 compared to 2010 due to lower realized energy and capacity prices and generation at the 

coal plants. Power prices fell in the fourth quarter of 2011 and have continued to fall in 2012, driven by an abundance of lowpriced natural gas, weather conditions and a slow economic recovery. Moreover, the abundance of low-priced natural gas has 

resulted in increased competition from natural gas-fired generating units in the markets in which Midwest Generation 

operates, and generation from Midwest Generation's plants has been correspondingly affected. Also at the end of 2011, a 

favorable long-term rail contract that supplied Midwest Generation's fleet expired and was replaced by a higher priced 

contract. EMG expects that Midwest Generation's average fuel cost ($/MWh) will increase by approximately one-third in 

2012. Furthermore, Homer City is engaged in discussions with the owner-lessors regarding funding of retrofit expenditures 
36

for the Homer City plant that, if successful in providing funding, will likely result in EME's loss of substantially all beneficial 

economic interest in and material control of the Homer City plant. Finally, as discussed below, EMG recorded significant 

impairment charges during the fourth quarter of 2011. 

At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available 

borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash 

and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility 

maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility, and there can be

no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of 

these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be 

able to, replace these credit lines or any portion of them. EME had $3.7 billion of unsecured notes outstanding at 

December 31, 2011, $500 million of which mature in 2013.

Unless energy and capacity prices increase, EMG expects that it will incur further reductions in cash flow and losses in years 

subsequent to 2012 as well as in 2012, and a continuation of these adverse trends coupled with pending debt maturities and 

the need to retrofit its plants to comply with governmental regulations will strain EMG's liquidity. To address such scenario, 

EMG would need to consider all options available to it, including potential sales of assets or restructurings or reorganization

of the capital structure of EMG and its subsidiaries. EMG's current business plans are focused on liquidity and operating 

effectively through the current commodity price cycle and on environmental compliance as described below.

Midwest Generation Environmental Compliance Plans and Costs

During 2011, Midwest Generation continued to advance necessary activities for NOx and SO2 controls to meet the 

requirements of the CPS. Midwest Generation does not anticipate a material change to its current approach in order to 

comply with the MATS rule. Midwest Generation expects to continue to develop and implement a compliance program that 

includes the operations of ACI systems, upgrades to particulate removal systems and the use of dry sorbent injection, 

combined with its use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NOx and SO2 as well as 

for hazardous air pollutants, such as mercury, acid gas and non-mercury metals.

A significant decline in power prices from September 30, 2011, combined with new environmental regulations and public 

policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants. Decisions 

regarding whether or not to proceed with retrofitting any particular remaining units to comply with CPS requirements for SO2

emissions, including those that have received permits, are subject to a number of factors, such as market conditions, 

regulatory and legislative developments, liquidity and forecasted commodity prices and capital and operating costs applicable 

at the time decisions are required or made. Midwest Generation may also elect to shut down units, instead of installing 

controls, to be in compliance with the CPS. Decisions about any particular combination of retrofits and shutdowns Midwest 

Generation may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. 

Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital or continue 

with the expenditure of capital will be made as required, subject to the requirements of the CPS and other applicable 

regulations. In February 2012, Midwest Generation decided to shut down the Fisk Station by the end of 2012 and the 

Crawford Station by the end of 2014 and concluded it was less likely to retrofit the Waukegan Station rather than the larger 

Powerton, Joliet and Will County Stations. As a result, EMG recorded an impairment charge of $640 million at December 31, 

2011 related to the Crawford, Fisk and Waukegan Stations. For further discussion, see "Edison International (Consolidated): 

Liquidity and Capital Resources—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—

Application to Midwest Generation Stations" and "Item 8. Edison International Notes to Consolidated Financial Statements—

Note 16. Asset Impairments, Lease Terminations and Other." Units that are not retrofitted may continue to operate until 

required to shut down by applicable regulations or operate with reduced output.

In connection with its decision to close the Fisk and Crawford Stations, Midwest Generation entered into a Memorandum of 

Understanding with the City of Chicago, acting through the Commissioner of Health, which acknowledges that the cessation 

of coal-fired electric generation at the Fisk and Crawford Stations will achieve the objectives of the proposed Chicago Clean 

Power Ordinance without a need to pass the proposed Clean Power Ordinance or similar ordinances (recognizing that such 

agreement cannot bind the Chicago City Council or its members). Midwest Generation and the City of Chicago have also 

agreed to collaborate with key stakeholders to consider potential future uses, ownership and sources of external funding to 

transition the sites for such uses. The closure of the Fisk and Crawford Stations will be subject to review for reliability by 

PJM Interconnection LLC, the regional transmission organization that controls the area where these plants are located. In 

total, Midwest Generation estimates 150 to 180 employees will be affected. The timing and amount of severance benefits, if 

any, will be determined after completion of review of personnel based on seniority and other factors and, in the case of the 

Crawford Station, the amount may be affected by the timing of the plant closure. Other obligations related to the Fisk and 

Crawford Stations could be affected by the plant closing, including sales of capacity, for which Midwest Generation is unable 
37

to reasonably estimate the impact, or range of impacts, that could be incurred. Midwest Generation does not expect to incur 

future capital expenditures to close these plants. 

Based on work to date, Midwest Generation estimates the cost of retrofitting the large stations (Powerton, Joliet Units 7 and 8

and Will County) using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, and 

the associated upgrading of existing particulate removal systems, would be up to approximately $628 million. The cost of 

retrofitting Joliet Unit 6 is not included in the large unit amounts as it is less likely that Midwest Generation will make 

retrofits for this unit. The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the 

estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. For further discussion 

related to EMG's impairment policy on the unit of account, see "Edison International (Consolidated): Liquidity and Capital 

Resources—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets."

In February 2012, Midwest Generation received an extension of its permit to install a dry sorbent injection system at the 

Powerton Station.

Homer City Lease

Homer City engaged a financial advisor and conducted a bidding process to obtain capital funding from third parties during 

the second half of 2011 to partially finance the installation of the environmental improvements. During the fourth quarter of 

2011, such efforts failed to obtain sufficient interest from market participants necessary to fund the capital needed to make 

such improvements under the current lease arrangement. Homer City does not currently have sufficient capital and does not 

expect to generate sufficient funds from operations to complete retrofits. EMG is under no legal obligation to, and has chosen 

not to, provide funding. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback 

transaction affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital 

expenditures. Consequently, Homer City's ability to install environmental compliance equipment will be dependent on 

funding from the owner-lessors or third parties. Homer City is currently engaged in discussions with the owner-lessors 

regarding the potential for such funding. EMG expects that the outcome of any such discussions, if successful in providing 

funding for the Homer City plant, will likely result in EMG's loss of substantially all beneficial economic interest in and 

material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the 

Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the ownerlessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of 

Homer City, or both.

There is no assurance that an agreement will be reached with the owner-lessors or the existing secured lease obligation 

bondholders on funding the capital improvements. Homer City believes it is unlikely to meet the covenant requirements of its 

sale-leaseback documents relating to the payment of equity rent at April 1, 2012 and will be unable to make the required 

equity rent payment. There is no assurance that subsequent rent payments will be made. Under the sale-leaseback documents, 

rent payments are comprised of two components, senior rent and equity rent. Senior rent is used exclusively for debt service 

to secured lease obligation bondholders, while equity rent is paid to the owner-lessors. In order to pay equity rent, among 

other requirements, Homer City must meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to 

reduction to 1.3 to 1 under certain circumstances). A failure to pay equity rent does not entitle the owner-lessors to foreclose 

upon Homer City's leasehold interest, but it does result in the suspension of Homer City's ability to make permitted 

distributions. Moreover, Homer City would be permanently restricted in its ability to make permitted distributions if a failure

to pay equity rent when due was not cured within nine months, or even if cured, occurred more than one additional time 

during the term of the lease. Homer City is not subject to any minimum historical and projected senior rent service coverage 

ratios except as conditions to distributions and equity rent payments. Also, failure by Homer City to pay equity rent when due 

in April 2012 could trigger termination of the $48 million senior rent reserve letter of credit. Homer City would then be 

required to fund the senior rent reserve, and failure to do so could entitle counterparties to seek available remedies under the 

sale-leaseback documents, including termination or foreclosure upon the leasehold interest. As a result of the expectation that

EMG is likely to lose substantially all beneficial economic interest in and material control of the Homer City plant, EMG 

recorded an impairment charge of $1.03 billion for the fourth quarter of 2011. For further discussion, see "Item 8. Edison 

International Notes to Consolidated Financial Statements—Note 16. Asset Impairments, Lease Terminations and Other."

Included in the consolidated financial statements are the assets and liabilities related to Homer City. In the event that EMG no 

longer controls Homer City, EMG will record a loss on disposition of assets and liabilities and likely classify Homer City as a

discontinued operation. The loss on disposition will be determined based on the assets and liabilities at the date of disposition 

and an assessment whether any ongoing contingencies exist. For further discussion, see "Edison International (Consolidated): 

Liquidity and Capital Resources—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—

Application to Homer City Plant" and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 16. 

Asset Impairments, Lease Terminations and Other."
38

As a result of the financial outlook of Homer City, as previously discussed, EMG's subsidiary, EMMT, has ceased to enter 

into hedging activities related to future power sales, but continues to enter into energy and capacity transactions on behalf of 

Homer City pursuant to an intercompany agreement. Those transactions are generally back-to-back transactions in which 

EMMT enters into a transaction with a third party as a principal and then enters into an equivalent transaction with Homer 

City. In the case of capacity, EMMT has sold Homer City capacity in the annual PJM base residual auctions through May 

2015. If Homer City were to default on its obligations to supply capacity, then EMMT would be liable to PJM to supply that 

capacity, and failure to do so would expose EMMT to penalties under the PJM tariffs. If one or more of the Homer City units 

were to be unavailable as a capacity resource and EMMT did not fulfill this obligation through market transactions, then 

EMMT would be required to refund any capacity payments received and would be assessed by PJM a penalty equal to the 

greater of 20% of the capacity payments or $20 per MW-day.

EMG's Renewable Energy Activities

Recent developments related to EMG renewable financing and development activities include:

• On December 21, 2011, EMG's subsidiary, EME closed a $242 million portfolio financing of three contracted wind 

projects representing 204 megawatts of generation capacity previously funded entirely with equity. Funding available in 

the amount of $110 million from the term loan facility, net of transaction costs, was distributed to EME in 2011 and 

approximately $95 million, net of transaction costs, of available funds is expected to be distributed in the first quarter of 

2012 when the Pinnacle project achieves certain completion milestones.

• As part of its plan to obtain third-party equity capital to finance the development of a portion of EMG's wind portfolio, 

on February 13, 2012, Edison Mission Wind sold its indirect equity interests in the Cedro Hill wind project (150 MW in 

Texas), the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in 

Wyoming) to a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. 

Capistrano Wind Partners also agreed to acquire the Broken Bow I wind project (80 MW in Nebraska) and the Crofton 

Bluffs wind project (40 MW in Nebraska) for consideration expected to include $141 million from the same outside 

investors upon the satisfaction of specified conditions, including commencement of commercial operation and 

completion of project debt financing. The proceeds from outside investors net of costs on the projects to be completed 

are expected to be distributed to EMG and available for general corporate purposes. For additional information, see 

"Item 8. Edison International Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—

Categories of Variable Interest Entities—Projects or Entities that are Consolidated."

During the fourth quarter of 2011, EMG significantly reduced development of renewable energy projects to conserve cash 

and in light of more limited market opportunities. As a result, EMG reduced staffing and has undertaken efforts to reduce 

funding joint development projects, thereby reducing the development pipeline of potential wind projects to a projected 

installed capacity to approximately 1,300 megawatts. These changes triggered charges of $34 million. In addition, 

management has reviewed the Storm Lake project and four small wind projects in Minnesota, and based on an expected 

future increase in operating costs and declines in long-term power prices that the projects could potentially realize following

the term of the power purchase agreements, EMG has recorded an impairment charge of $30 million. For additional 

information on renewable energy projects, see "EMG: Liquidity and Capital Resources—Capital Investment Plan," "Edison 

International (Consolidated): Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to 

Selected Wind Projects," and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 16. Asset 

Impairments, Lease Terminations and Other."

Environmental Developments

For a discussion of environmental developments, see "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 10. Environmental Developments."
39

SOUTHERN CALIFORNIA EDISON COMPANY

RESULTS OF OPERATIONS

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 forecasted 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, 

if any. 

• Utility cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery 

of specific project or program costs incurred or provide for mechanisms to track and recover or refund differences in 

forecasted and actual amounts, subject to reasonableness review or compliance with upfront standards.
40

The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately 

identifies utility earning activities and utility cost-recovery activities.

(in millions)

Operating revenue

Fuel and purchased power

Operations and maintenance

Depreciation decommissioning

and amortization

Property taxes and other

Gain on sale of assets

Total operating expenses

Operating income

Net interest expense and other

Income before income taxes

Income tax expense

Net income

Net income attributable to

noncontrolling interest

Dividends on preferred and

preference stock

Net income available for

common stock

Core Earnings3

Non-Core Earnings:

Global tax settlement

Tax impact of health care

legislation

Regulatory items

Total SCE GAAP Earnings

2011

Utility

Earning

Activities

$ 5,902

—

2,208

1,294

277

—

3,779

2,123

(378)

1,745

601

1,144

—

59

$ 1,085

Utility

CostRecovery

Activities

$ 4,675

3,356

1,179

132

8

—

4,675

—

—

—

—

—

—

—

$ —

Total

Consolidated

$ 10,577

3,356

3,387

1,426

285

—

8,454

2,123

(378)

1,745

601

1,144

—

59

$ 1,085

$ 1,085

—

—

—

$ 1,085

2010

Utility

Earning

Activities

$ 5,606

—

2,271

1,213

260

—

3,744

1,862

(330)

1,532

440

1,092

—

52

$ 1,040

Utility

CostRecovery

Activities

$ 4,377

3,293

1,020

60

3

(1)

4,375

2

(2)

—

—

—

—

—

$ —

Total

Consolidated

$ 9,983

3,293

3,291

1,273

263

(1)

8,119

1,864

(332)

1,532

440

1,092

—

52

$ 1,040

$ 984

95

(39)

—

$ 1,040

2009

Utility

Earning

Activities

$ 5,303

—

2,111

1,124

244

—

3,479

1,824

(298)

1,526

249

1,277

—

51

$ 1,226

Utility

CostRecovery

Activities1,2

$ 4,662

3,472

1,043

54

—

(1)

4,568

94

—

94

—

94

94

—

$ —

Total

Consolidated

$ 9,965

3,472

3,154

1,178

244

(1)

8,047

1,918

(298)

1,620

249

1,371

94

51

$ 1,226

$ 874

306

—

46

$ 1,226

1 Effective January 1, 2010, SCE deconsolidated the Big 4 projects and therefore these projects are reflected in 2009 activities only (see 

"Item 8. Edison International Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities" for further discussion).

2 Effective July 1, 2009, SCE transferred Mountainview Power Company, LLC to SCE. As a result of the transfer and for comparability 

purposes, Mountainview's 2009 activity was reclassified from cost-recovery activities to utility earning activities consistent with the 

revised recovery mechanism.

3 See use of Non-GAAP financial measures in "Edison International Overview—Highlights of Operating Results."

Utility Earning Activities

2011 vs. 2010

Utility earning activities were primarily affected by the following:

• Higher operating revenue of $296 million primarily due to the following:

• $135 million increase primarily due to a $215 million (4.35%) increase in 2011 authorized revenue approved in the 

2009 CPUC GRC decision. The 2011 increase was partially offset by reductions of $80 million mainly resulting 

from revenue recognized in 2010 associated with the recovery of San Onofre Unit 3 scheduled outage costs with no 

comparable amount in 2011. 
41

• $95 million increase in FERC-related revenue primarily resulting from the inclusion of capital expenditures related 

to the Tehachapi Transmission Project in rate base.

• $25 million increase in capital-related revenue requirements related to the San Onofre steam generator replacement 

project and a $20 million increase for the EdisonSmartConnectTM project.

• $20 million increase related to recovery of legal costs incurred between 2004 and 2009 in support of SCE's efforts to 

obtain generator refunds related to claims arising out of the energy crisis in California in 2000 – 2001.

• Lower operation and maintenance expense of $63 million primarily due to costs incurred in 2010 related to the San 

Onofre Unit 3 scheduled outage.

• Higher depreciation, decommissioning and amortization expense of $81 million primarily related to increased 

transmission and distribution investments.

• Higher net interest expense and other of $48 million primarily due to higher outstanding balances on long-term debt. For 

details of other income and expenses, see "Item 8. Edison International Notes to Consolidated Financial Statements—

Note 17. Other Income and Expenses."

• Higher income taxes primarily due to an increase in income as well as benefits recorded in 2010 related to the Global 

Settlement. See "—Income Taxes" below for more information.

2010 vs. 2009

Utility earning activities were primarily affected by the following:

• Higher operating revenue of $303 million primarily due to the following:

• $190 million increase primarily due to a 4.25% increase in 2010 authorized revenue approved in the 2009 CPUC 

GRC decision. 

• $55 million increase in FERC-related revenue, primarily due to the implementation of SCE's 2010 and 2009 FERC 

rate cases effective March 1, 2010 and March 1, 2009, respectively.

• $25 million increase in capital-related revenue requirements related to the San Onofre steam generator replacement 

project and a $20 million increase for the EdisonSmartConnectTM project.

• Higher operation and maintenance expense of $160 million primarily due to the following:

• $75 million of higher expenses to support company growth programs, including new information technology system 

requirements and facility maintenance.

• $45 million of higher transmission and distribution expenses to support system reliability and infrastructure 

replacement, right of way costs; preventive maintenance work, technical training and line clearing.

• $15 million of higher generation expenses primarily from a $25 million increase from the San Onofre Unit 2 and 3 

scheduled outages, including $10 million of additional work identified during the Unit 2 scheduled outage, and a 

$10 million increase primarily due to overhaul and outage costs at Four Corners. These increases were partially 

offset by a $20 million decrease resulting from 2009 scheduled outages at the Mountainview power plant.

• $15 million of higher expense related to general liability and property insurance due to higher premiums for wildfire 

coverage.

• Higher depreciation expense of $89 million primarily related to increased capital expenditures, including capitalized 

software costs.

• Higher net interest expense and other of $32 million primarily due to:

• Lower other income of $19 million primarily related to a decrease in AFUDC – equity earnings due to the transfer of 

the Mountainview power plant to utility rate base in the third quarter of 2009 partially offset by an increase in 

AFUDC – equity resulting from a higher capitalization rate and level of construction in progress associated with 

SCE's capital expenditure plan.

• Higher interest expense of $7 million primarily due to higher outstanding balances on long-term debt.
42

See "—Income Taxes" below for discussion of higher income taxes during 2010 compared to the same period in 2009.

Utility Cost-Recovery Activities

2011 vs. 2010

Utility cost-recovery activities were primarily affected by the following:

• Higher purchased power expense of $59 million primarily driven by the cost to replace CDWR contracts that expired in 

2011, which were not previously recorded as an SCE cost but impacted customer bills (see "—Supplemental Operating 

Revenue Information" below), and higher costs associated with renewable contracts. The increase was partially offset by 

increased purchased power in 2010 during the outages at San Onofre and Four Corners.

• Higher operation and maintenance expense of $159 million including $75 million of increased energy efficiency program 

costs and $40 million related to the EdisonSmartConnectTM project.

• Higher depreciation, decommissioning and amortization expense of $72 million including $35 million related to the 

EdisonSmartConnectTM project and $25 million related to the San Onofre steam generator replacement project.

2010 vs. 2009

Utility cost-recovery activities exclude the impact of the consolidation of the Big 4 projects in 2009 for comparability 

purposes. The following amounts were excluded for 2009: $370 million for purchased power expense to reflect the 

elimination of sales between the VIEs and SCE; $368 million for fuel expense; and $94 million for operation and 

maintenance expense. Utility cost-recovery activities were primarily affected by:

• Lower purchased power expense of $191 million primarily related to lower realized losses on economic hedging 

activities ($156 million in 2010 compared to $344 million in 2009) reflecting the impact of higher natural gas prices in 

2010 and changes in SCE's hedge portfolio mix.

• Higher operation and maintenance expense of $71 million primarily due to an increase in spending for various public 

purpose programs.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was 

$10.0 billion for both 2011 and 2010 and $9.5 billion for 2009. The 2011 revenue reflects:

• a rate decrease of $408 million resulting from a rate adjustment beginning on June 1, 2011, primarily reflecting the 

refund of over collected fuel and power procurement-related costs, offset by 

• a sales volume increase of $393 million primarily due to SCE providing power that was previously provided by CDWR 

contracts which expired in 2011.

The 2010 revenue reflects:

• a rate increase of $777 million mainly due to the implementation of the CPUC 2009 GRC decision and approved FERC 

transmission rate changes, partially offset by 

• a sales volume decrease of $255 million primarily due to milder weather experienced during 2010 compared to the same 

period in 2009 and continuing recessionary effects. 

As a result of the CPUC-authorized decoupling mechanism, SCE earnings are not affected by changes in retail electricity 

sales (see "Item 1. Business—Overview of Ratemaking Process").

SCE remits to CDWR and does not recognize as revenue the amounts that SCE bills and collects from its customers for 

electric power purchased and sold by the CDWR to SCE's customers, as well as CDWR bond-related costs and a portion of 

direct access exit fees. The amounts collected and remitted to CDWR were $1.1 billion, $1.2 billion and $1.8 billion for years 

ended December 31, 2011, 2010 and 2009, respectively. All CDWR power contracts allocated to SCE by the CPUC had 

expired by the end of 2011. SCE's revenue and related purchased power expense is expected to increase in 2012 as these 

CDWR contracts are replaced by new power purchase agreements entered into by SCE.
43

Effective January 1, 2010, the CDWR-related rates were decreased to reflect lower power procurement expenses and a refund 

of operating reserves that CDWR releases as its contracts terminate. Approximately $440 million is expected to be refunded 

to SCE customers through lower CDWR rates in 2012.

Income Taxes

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the 

income tax provision.

(in millions)

Income from continuing operations before income taxes

Net income attributable to noncontrolling interests in the Big 4 projects

Adjusted income from continuing operations before income taxes

Provision for income tax at federal statutory rate of 35%

Increase (decrease) in income tax from:

Items presented with related state income tax, net

Global settlement related1

Change in tax accounting method for asset removal costs2

State tax – net of federal benefit

Health care legislation3

Property-related

Other

Total income tax expense from continuing operations

Effective tax rate

Years ended December 31,

2011

$ 1,745

—

$ 1,745

$ 611

—

—

80

—

(76)

(14)

$ 601

34.4%

2010

$ 1,532

—

$ 1,532

$ 536

(95)

(40)

59

39

(47)

(12)

$ 440

28.7%

2009

$ 1,620

(94)

$ 1,526

$ 534

(306)

—

67

—

(64)

18

$ 249

16.3%

1

 Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolved all of 

SCE's federal income tax disputes and affirmative claims through tax year 2002. During 2009, SCE recorded after-tax earnings of

approximately $306 million. During 2010, SCE recognized a $95 million earnings benefit from the acceptance by the California 

Franchise Tax Board of the tax positions finalized in 2009 and receipt of the final interest determination from the Franchise Tax Board.

2

 During 2010, the IRS approved SCE's request to change its tax accounting method for asset removal costs primarily related to its 

infrastructure replacement program. As a result, SCE recognized a $40 million earnings benefit (of which $28 million relates to asset 

removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions were 

recorded on a flow-through basis, as required by the CPUC.

3

 During 2010, SCE recorded a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the 

federal health care legislation enacted in March 2010. The health care law eliminated the federal tax deduction for retiree health care 

costs to the extent those costs are eligible for federal Medicare Part D subsidies.

The increase in income taxes for property-related items was primarily due to a cumulative deferred income tax adjustment of 

$30 million in 2011 related to nuclear fuel.

For a discussion of the status of Edison International's income tax audits, see "Edison International Notes to Consolidated 

Financial Statements—Note 7. Income Taxes."

LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, fund capital expenditures, and implement its business strategy are 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 and dividend payments to investors, and the outcome of tax and regulatory matters.

SCE expects to fund its 2012 obligations, capital expenditures and dividends through operating cash flows, tax benefits 

(including bonus depreciation) and capital market financings of debt and preferred equity, as needed. SCE also has 

availability under its credit facilities to meet operating and capital requirements.

In January and February 2012, SCE issued 250,000 shares and 100,000 shares, respectively, of 6.25% Series E preference 
44

stock (cumulative, $1,000 liquidation value). The Series E preference stock may not be redeemed prior to February 1, 2022. 

The proceeds from the sale of these shares were used to repay commercial paper borrowings issued to fund SCE's capital 

program.

Available Liquidity

SCE has two credit facilities: a $2.4 billion five-year credit facility that matures in February 2013 and a $500 million threeyear credit facility that matures in March 2013.

(in millions)

Commitment

Outstanding borrowings supported by credit facilities

Outstanding letters of credit

Amount available

Credit Facilities

$ 2,894

(419)

(81)

$ 2,394

Debt Covenant

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. 

At December 31, 2011, SCE's debt to total capitalization ratio was 0.48 to 1.

Capital Investment Plan

SCE's forecasted capital expenditures for 2012 – 2014 include a capital forecast in the range of $11.8 billion to $13.2 billion

based on the average variability experienced in 2011, 2010 and 2009 of 11% between annual forecast capital expenditures 

and actual spending. This capital forecast includes certain projects under CPUC jurisdiction that are subject to the outcome of

the 2012 CPUC GRC. 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, weather and other unforeseen conditions.

SCE's 2011 capital expenditures and the 2012 – 2014 capital expenditures forecast are set forth in the table below:

(in millions)

Transmission

Distribution

Generation

EdisonSmartConnectTM

Total Estimated Capital Expenditures1

Total Estimated Capital Expenditures for 2012 – 2014 (using

11% variability discussed above)

2011

Actual

$ 929

1,847

729

372

$ 3,877

2012

$ 1,547

2,304

743

373

$ 4,967

$ 4,421

2013

$ 1,452

2,355

642

—

$ 4,449

$ 3,960

2014

$ 850

2,416

520

—

$ 3,786

$ 3,369

Total

$ 3,849

7,075

1,905

373

$ 13,202

$ 11,750

1 Included in SCE's capital expenditures plan are projected environmental capital expenditures of $499 million, $534 million and 

$576 million in 2012, 2013 and 2014, respectively. The projected environmental capital expenditures are to comply with laws, 

regulations, and other nondiscretionary requirements.
45

Transmission Projects

SCE has experienced cost increases on its Tehachapi and Devers-Colorado River Transmission Projects, primarily related to 

environmental monitoring and mitigation costs, scope changes and schedule delays. A summary of SCE's major transmission 

and substation projects during the next three years is presented below: 

Project Name

Tehachapi 1-11

Devers-Colorado River

Eldorado-Ivanpah

Red Bluff

Description

Transmission lines and

substation

Transmission line

Substation and upgraded

transmission line

Substation

Project Lifecycle

Phase

In construction

In construction

Engineering/

Construction

In construction

In Service

Date

2009 – 2015

2013

2013

2013

Direct 

Expenditures1

(in millions)

$ 2,500

860

444

234

% of Spend

Complete

62%

18%

6%

6%

2012 – 2014

Forecast

(in millions)

$ 904

709

417

220

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 2012 – 2014.

Currently, SCE is completing the final engineering design for the Tehachapi Transmission and the Devers-Colorado River 

Projects and has increased its 2012 – 2014 forecasted expenditures for these projects as a result of cost pressures discussed 

above. The Tehachapi Project costs and schedule may be further impacted by the CPUC's response to SCE's petition to 

modify the 2009 decision approving the project for the purpose of obtaining authorization to install aviation marking and 

lighting in accordance with FAA standards. In October 2011, the CPUC staff notified SCE that the constructed portions of the 

project should be marked and lighted as required, but instructed SCE to defer completion of remaining project components 

that may require aviation marking or lighting pending CPUC review of the petition to modify. Community opposition to 

portions of the project continues and requests for reconsideration of the CPUC's 2009 decision are pending. In January 2012, 

in response to a CPUC request, SCE provided information on potential new options for a portion of the project, including 

traversing a state park, changing the nature of some of the towers, and undergrounding lines. Adoption of any of these 

alternatives could create additional costs and delay the completion of the project. SCE is required to file revised cost 

estimates with the CPUC. As with all transmission investments, cost recovery will be subject to future rate proceedings.

Distribution Projects

Distribution expenditures include projects and programs to meet customer load growth requirements, reliability and 

infrastructure replacement needs, information and other technology and related facility requirements.

Generation Projects

Generation expenditures include:

• Nuclear-related capital expenditures necessary to maintain safe and reliable plant operation, meet NRC and other 

regulatory requirements, and optimize plant performance and cost-effectiveness.

• Hydro-related capital expenditures associated with infrastructure and equipment replacement 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.

• SCE's Solar Photovoltaic Program to develop up to 125 MW of utility owned Solar Photovoltaic generating facilities 

generally ranging in size from 1 to 2 MW each, on commercial and industrial rooftops and other space in SCE's service 

territory. The CPUC has authorized recovery of reasonable costs and allowed for a return on investment. 

EdisonSmartConnectTM

SCE's EdisonSmartConnectTM project involves installing state-of-the-art "smart" meters in approximately 5 million 

households and small businesses through its service area. In March 2008, SCE was authorized by the CPUC to recover 

$1.63 billion in customer rates for the deployment phase of EdisonSmartConnectTM. In 2009, SCE began full deployment of 

meters to all residential and small business customers under 200 kW. SCE anticipates completion of the deployment in 2012. 

In 2011, the CPUC began exploring the feasibility of allowing customers to voluntarily opt out of smart meter installation. 
46

SCE has provided information to the CPUC on the costs and technical issues involved. Should the CPUC order SCE to 

implement an opt out option, SCE would file an application seeking to recover the associated costs in rates.

Regulatory Proceedings

Energy Efficiency Shareholder Risk/Reward Incentive Mechanism 

The CPUC previously adopted and extended through 2009 an Energy Efficiency Risk/Reward Incentive Mechanism ("Energy 

Efficiency Mechanism") allowing SCE to earn incentives based on SCE's performance toward meeting CPUC energy 

efficiency goals. In December 2011, the CPUC issued a decision approving an $18 million final payment for 2009 

performance under the Energy Efficiency Mechanism. The CPUC is reviewing and may further modify or eliminate the 

Energy Efficiency Mechanism for performance periods subsequent to 2009.

San Onofre Outage and Repair Issues

Four replacement steam generators were installed at San Onofre Units 2 and 3 in 2010 and 2011. Inspections of the Unit 2 

steam generators during a planned maintenance and refueling outage in February 2012 found some isolated areas of wear in 

some of the 19,454 heat transfer tubes. In light of this condition, SCE, in consultation with the steam generators' 

manufacturer, determined that a number of the tubes should be removed from service as a preventive measure. The steam 

generators are designed to include sufficient tubes to accommodate a need to remove some from service for a variety of 

reasons, including wear, and the tubes that SCE is in the process of preventively removing from service in Unit 2 are well 

within the extra margin. Additionally, on January 31, 2012, a water leak was detected in one of the tubes of a new steam 

generator in Unit 3, and the Unit was safely taken offline. Extensive testing of the Unit 3 steam generators is ongoing to fully 

understand the cause of the leak. In a memorandum dated February 16, 2012, the NRC determined that inasmuch as the leak 

was in a newly installed steam generator, it will conduct an event follow-up baseline inspection to review San Onofre's 

response to the leak and verify the appropriateness of its remedial actions. Each Unit will be restarted when repairs on that 

Unit are completed, and SCE is satisfied that it is safe to do so.

The steam generators were supplied by Mitsubishi Heavy Industries (“MHI”) and are warranted for an initial period of 20 

years from acceptance. Subject to certain exceptions, the purchase agreement sets forth specified damages for certain repairs, 

generally limits MHI's aggregate contractual liability to the approximately $137 million purchase price of the generators and 

excludes consequential damages from recovery, such as the cost of replacement power. In 2005, the CPUC authorized 

expenditures of approximately $525 million ($665 million when adjusted for inflation) for SCE's 78.21% share of San Onofre 

to purchase and install new generators and remove their predecessors. Those expenditures remain subject to CPUC review 

upon submission of SCE's final costs for the overall project. SCE expects to file an application with the CPUC setting forth 

final project costs in the third or fourth quarter of 2012. Replacement power costs are recovered through the ERRA balancing 

account, subject to reasonableness review.

Dividend Restrictions

The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. In SCE's most recent 

cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component 

of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital 

structure remains at or above the 48% authorized level on a 13-month weighted average basis. At December 31, 2011, SCE's 

13-month weighted-average common equity component of total capitalization was 50.4% resulting in the capacity to pay 

$436 million in additional dividends.

During 2011, SCE made $461 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.

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, 2011, 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.
47

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, 2011.

(in millions)

Collateral posted as of December 31, 20111

Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of

SCE's credit rating to below investment grade

Posted and potential collateral requirements2

$ 149

89

$ 238

1 Collateral provided to counterparties and other brokers consisted of $51 million of cash which was offset against net derivative 

liabilities on the consolidated balance sheets, $17 million of cash reflected in "Other current assets" on the consolidated balance sheets 

and $81 million in letters of credit.

2 There would be no increase to SCE's total posted and potential collateral requirements based on SCE's forward positions as of 

December 31, 2011 due to adverse market price movements over the remaining lives of the existing power procurement contracts 

using a 95% confidence level.

Workers Compensation Self-Insurance Fund

SCE is self-insured for workers compensation claims. SCE assesses workers compensation claims that have been asserted 

and those that have been incurred but not reported to determine the probable amount of losses that should be recorded. The 

Department of Industrial Relations for the State of California requires companies that are self-insured for workers 

compensation to post collateral (in the form of cash and/or letters of credits) based on the estimated workers' compensation 

liability if a company's bond rating were to fall below "B." As of December 31, 2011, if SCE's bond rating were to fall below 

a "B" rating, SCE would be required to post $208 million for its workers compensation self-insurance plan.

Regulatory Balancing Accounts

SCE's cash flows are affected by regulatory balancing account 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, 2011, balancing account net over-collections were $1.2 billion primarily related to public purpose-related 

program costs as well as fuel and power procurement-related costs. Over-collections for public purpose-related programs are 

expected to decrease as costs are incurred to fund programs established by the CPUC. The fuel and power procurementrelated over-collections of $392 million are expected to be refunded through a rate adjustment in 2012.

Historical Segment Cash Flows

The table below sets forth condensed historical cash flow information for SCE:

(in millions)

Net cash provided by operating activities

Net cash provided (used) by financing activities

Net cash used by investing activities

Net decrease in cash and cash equivalents

2011

$ 3,261

799

(4,260)

$ (200)

2010

$ 3,386

503

(4,094)

$ (205)

2009

$ 4,069

(1,999)

(3,219)

$ (1,149)

Net Cash Provided by Operating Activities

Net cash provided by operating activities decreased $125 million in 2011 compared to 2010. The decrease in cash flows 

provided by operating activities was primarily due to the following:

• $310 million decrease from refunding to customers overcollections of revenue which resulted from actual electricity 

sales exceeding forecasted electricity sales. SCE began refunding this balance through a rate adjustment effective June 1, 

2011;

• $250 million decrease resulting from higher balancing account overcollections for fuel and power procurement-related 
48

costs in 2010 when compared to 2011 (overcollections of approximately $300 million in 2010 compared to 

approximately $50 million in 2011). The 2010 overcollection was primarily due to lower realized gas and power prices 

compared to the amounts forecasted for setting customer rates. SCE began refunding the overcollection through a rate 

adjustment beginning on June 1, 2011. The balancing account was over-collected by $392 million at December 31, 2011, 

$345 million at December 31, 2010, $46 million at December 31, 2009 and under-collected by $406 million at 

December 31, 2008; and

• $365 million increase resulting from higher income before depreciation and income taxes primarily driven by higher 

customer revenue.

Net cash provided by operating activities decreased $683 million in 2010, compared to 2009. The cash flows provided by 

operating activities were primarily due to the following:

• $531 million decrease in cash reflecting lower net tax receipts in 2010 compared to 2009 primarily related to the impacts 

of the Global Settlement. In 2009, SCE received tax-allocation payments of $875 million from the Global Settlement, 

compared to tax-allocation payments received of $26 million in 2010. This decrease was partially offset by higher 

estimated tax payments in 2009 compared to 2010.

• $155 million net cash inflow from balancing accounts composed of:

• $310 million net cash inflow from the funding of public purpose and solar initiative programs and lower pension and 

PBOP contributions in 2010 compared to 2009; and

• $155 million net cash outflow due to the decrease in balancing account cash flows for fuel and power procurementrelated costs (collections of approximately $300 million in 2010, compared to collections of approximately 

$450 million in 2009).

• Timing of cash receipts and disbursements related to working capital items, including a net cash outflow of $95 million 

related to the timing of fuel and power procurement-related activities primarily related to ISO charges and a $60 million 

decrease in margin and collateral deposits – net of collateral received.

Net Cash Provided (Used) by Financing Activities

Cash provided (used) by financing activities mainly consisted of net repayments of short-term debt and long-term debt 

issuances (payments).

Net cash provided by financing activities for 2011 was $799 million consisting of the following significant events:

• Issued $500 million of 3.875% first and refunding mortgage bonds due in 2021. The proceeds from these bonds were 

used to repay commercial paper borrowings and to fund SCE's capital program.

• Issued a net $419 million of commercial paper supported by SCE's line of credit to fund interim working capital 

requirements.

• Issued $250 million of 3.9% first and refunding mortgage bonds due in 2041. The proceeds from these bonds were used 

to fund SCE's capital program.

• Issued $150 million of floating rate first and refunding mortgage bonds due in 2014. The proceeds from these bonds 

were used to finance fuel inventories.

• Issued $125 million of 6.5% Series D preference stock. The proceeds from the issuance were used to fund SCE's capital 

program.

• Paid $461 million of dividends to Edison International.

• Purchased $86 million of SCE variable rate tax-exempt bonds.

Net cash provided by financing activities for 2010 was $503 million consisting of the following significant events:

• Issued $1 billion of first refunding mortgage bonds due in 2040 to fund SCE's capital program.

• Reissued $144 million of tax-exempt pollution control bonds due in 2035 to fund SCE's capital program.

• Repaid $250 million of senior unsecured notes.
49

• Paid $300 million in dividends to Edison International.

Net cash used by financing activities for 2009 was $2.0 billion consisting of the following significant events:

• Issued $500 million of first refunding mortgage bonds due in 2039 and $250 million of first and refunding mortgage 

bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories, 

respectively.

• Repaid a net $1.9 billion of short-term debt.

• Repaid $150 million of first and refunding mortgage bonds.

• Purchased $219 million of two issues of tax-exempt pollution control bonds and converted the issues to a variable rate 

structure. As discussed above, SCE reissued $144 million of these bonds in 2010. SCE continues to hold the remaining 

$75 million of these bonds which are outstanding and have not been retired or cancelled.

• Paid $300 million in dividends to Edison International.

Net Cash Used by Investing Activities

Cash flows from investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. 

Capital expenditures were $4.1 billion, $3.8 billion and $3.0 billion for 2011, 2010 and 2009, respectively, primarily related 

to transmission, distribution and generation investments. Net purchases of nuclear decommissioning trust investments and 

other were $167 million, $219 million and $199 million for 2011, 2010 and 2009, respectively.

Contractual Obligations and Contingencies

Contractual Obligations

SCE's contractual obligations as of December 31, 2011, for the years 2012 through 2016 and thereafter are estimated below.

(in millions)

Long-term debt maturities and interest1

Power purchase agreements2:

Renewable energy contracts

Qualifying facility contracts

Other power purchase agreements

Other operating lease obligations3

Purchase obligations4:

Nuclear fuel supply contract payments

Other fuel supply contract payments

Other contractual obligations5

Employee benefit plans contributions6

Total7,8

Total

$ 16,422

16,578

3,677

6,298

641

1,068

268

323

1,528

$ 46,803

Less than

1 year

$ 434

561

439

624

73

190

42

21

325

$ 2,709

1 to 3 years

$ 2,028

1,328

875

1,640

135

213

97

51

635

$ 7,002

3 to 5 years

$ 1,411

1,503

794

1,181

109

206

129

39

568

$ 5,940

More than

5 years

$ 12,549

13,186

1,569

2,853

324

459

—

212

—

$ 31,152

1 For additional details, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 5. Debt and 

Credit Agreements." Amount includes interest payments totaling $8.0 billion over applicable period of the debt.

2 Certain power purchase agreements entered into with independent power producers are treated as operating or capital 

leases. At December 31, 2011, minimum operating lease payments for power purchase agreements were $839 million in 

2012, $966 million in 2013, $930 million in 2014, $916 million in 2015, $815 million in 2016, and $11.5 billion for the 

thereafter period. At December 31, 2011, minimum capital lease payments for power purchase agreements were 

$33 million in 2012, $33 million 2013, $72 million for 2014, $109 million for 2015, $109 million for 2016, and 

$1.8 billion for the thereafter period (amounts include executory costs and interest of $445 million and $773 million, 

respectively). For further discussion, see "Item 8. Edison International Notes to Consolidated Financial Statements—

Note 9. Commitments and Contingencies."
50

3 At December 31, 2011, minimum other operating lease payments were primarily related to vehicles, office space and 

other equipment. For further discussion, see "Item 8. Edison International Notes to Consolidated Financial Statements—

Note 9. Commitments and Contingencies."

4 For additional details, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. 

Commitments and Contingencies."

5 At December 31, 2011, other commitments were primarily related to maintaining reliability and expanding SCE's 

transmission and distribution system. 

6 Amount includes estimated contributions to the pension and PBOP plans. The estimated contributions for SCE are not 

available beyond 2016. These amounts represent estimates that are based on assumptions that are subject to change. In 

addition, funding of future contributions could be impacted by the final 2012 GRC decision. See "Item 8. Edison 

International Notes to Consolidated Financial Statements—Note 8. Compensation and Benefit Plans" for further 

information.

7 At December 31, 2011, SCE had a total net liability recorded for uncertain tax positions of $258 million, which is 

excluded from the table. 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.

8 The contractual obligations table does not include derivative obligations and asset retirement obligations, which are 

discussed in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 6. Derivative Instruments 

and Hedging Activities," and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. 

Property, Plant and Equipment," respectively.

Contingencies

SCE has contingencies related to the CPSD Investigations, Four Corners New Source Review litigation, nuclear insurance, 

wildfire insurance and spent nuclear fuel, which are discussed in "Item 8. Edison International Notes to Consolidated 

Financial Statements—Note 9. 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, 2011, SCE had identified 24 material sites for remediation and recorded an estimated minimum liability 

of $49 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Item 8. Edison International Notes 

to Consolidated Financial Statements—Note 9. Commitments and Contingencies" for further discussion.

MARKET RISK EXPOSURES

SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. 

Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and 

counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery 

through regulatory mechanisms. Derivative instruments are used, as appropriate, to manage market risks for customers and 

SCE. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate 

risk, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and 

Hedging Activities" and "—Note 4. Fair Value Measurements."

Interest Rate Risk

SCE is exposed to changes in interest rates primarily as a result of its financing and short-term investing activities used for

liquidity purposes, to fund business operations and to fund capital investments. The nature and amount of 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. 

Changes in interest rates may impact SCE's authorized rate of return for the period beyond 2012, see "Item 1. Business—

Overview of Ratemaking Process—CPUC" for further discussion.
51

At December 31, 2011, the fair market value of SCE's long-term debt (including current portion of long-term debt) was 

$10.1 billion, compared to a carrying value of $8.4 billion. A 10% increase in market interest rates would have resulted in a 

$399 million decrease in the fair market value of SCE's long-term debt. A 10% decrease in market interest rates would have 

resulted in a $430 million increase in the fair market value of SCE's long-term debt.

Commodity Price Risk

SCE and its customers are exposed to the risk of a change in the market price of natural gas and electric power. SCE's 

hedging program reduces 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 the 

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. For further discussion on derivative instruments entered into to mitigate commodity price exposures, see "Item 8. 

Edison International Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."

Fair Value of Derivative Instruments

With some exceptions, SCE records derivative instruments on its consolidated balance sheets at fair value. Changes in the fair 

value of derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms 

and, therefore, SCE's fair value changes have no impact on 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 "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."

The fair value of outstanding derivative instruments used at SCE to mitigate its exposure to commodity price risk was a net 

liability of $936 million and $207 million at December 31, 2011 and 2010, respectively. The increase in the net liability was 

related to changes in unrealized losses on economic hedging activities primarily due to declining power and natural gas 

prices. The following table summarizes the increase or decrease to the fair values of outstanding derivative instruments as of 

December 31, 2011, if the electricity prices or gas prices were changed while leaving all other assumptions constant:

(in millions)

Increase in electricity prices by 10%

Decrease in electricity prices by 10%

Increase in gas prices by 10%

Decrease in gas prices by 10%

December 31,

2011

$ 266

(581)

(340)

(7)

Credit Risk

For information related to credit risks and how SCE manages credit risk, see "Item 8. Edison International Notes to 

Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts 

receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less 

derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide

for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these 

arrangements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings 

using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory 

filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, 

including master netting agreements. 
52

As of December 31, 2011, the amount of balance sheet exposure as described above broken down by the credit ratings of 

SCE's counterparties, was as follows:

(in millions)

S&P Credit Rating1

A or higher

Not rated3

Total

December 31, 2011

Exposure2

$ 122

11

$ 133

Collateral

$ —

(3)

$ (3)

Net Exposure

$ 122

8

$ 130

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 nonderivative 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.
53

EDISON MISSION GROUP

RESULTS OF OPERATIONS

Results of Continuing Operations

EMG primarily operates in one line of business, independent power production. The following table is a summary of 

competitive power generation results of operations for the periods indicated.

(in millions)

Competitive power generation operating revenues

Fuel

Operation and maintenance

Depreciation and amortization

Asset impairments, lease terminations and other

Total operating expenses

Operating income (loss)

Interest and dividend income

Equity in income from unconsolidated affiliates – net

Other income

Interest expense

Other expenses

Income (loss) from continuing operations before income taxes

Income tax benefit

Income (loss) from continuing operations

Income (loss) from discontinued operations–net of tax

Net income (loss)

Less: Net loss attributable to noncontrolling interests

Net income (loss) available for common stock

Core Earnings (Losses)1

Non-Core Earnings (Losses):

Global Settlement2

Asset impairments and other charges

Gain on sale of March Point

Write down of net investment in aircraft leases

Discontinued Operations

Total EMG GAAP Earnings (Losses)

For The Years ended December 31,

2011

$ 2,186

799

1,069

310

1,772

3,950

(1,764)

32

86

19

(324)

—

(1,951)

(864)

(1,087)

(3)

(1,090)

(1)

$ (1,089)

$ (25)

—

(1,050)

5

(16)

(3)

$ (1,089)

2010

$ 2,429

809

1,020

249

48

2,126

303

30

106

8

(264)

—

183

(36)

219

4

223

(1)

$ 224

$ 192

52

(24)

—

—

4

$ 224

2009

$ 2,399

796

964

239

891

2,890

(491)

30

89

12

(306)

(9)

(675)

(284)

(391)

(7)

(398)

(3)

$ (395)

$ 222

(610)

—

—

—

(7)

$ (395)

1

 See use of Non-GAAP financial measures in "Edison International Overview—Highlights of Operating Results."

2

 Includes termination of Edison Capital's cross-border leases and state tax impacts of Global Settlement with the IRS.

EMG had a core loss in 2011 compared to core earnings in 2010 primarily due to the following pre-tax items: 

• $206 million and $122 million decreases in Midwest Generation and Homer City income, respectively, primarily due to 

lower average realized energy and capacity prices and generation.

• $60 million increase in interest expense due to new energy project financings ($33 million) and lower capitalized interest 

($27 million). 

• $36 million decrease in energy trading due to reduced revenues from trading power contracts and the allocation to 

Homer City of benefits from an arrangement that allows EMMT to deliver a portion of Homer City's power into the 
54

NYISO (such decrease resulting from that allocation is offset by revenues recognized at Homer City). 

• $18 million increase in renewable energy income due to the increase in wind projects in operation coupled with higher 

generation due to more favorable wind conditions, partially offset by lower realized energy prices at the merchant wind 

projects. 

Consolidated non-core items for 2011 and 2010 included:

• An after-tax earnings charge of $1.09 billion ($1.76 billion pre-tax) recorded in the fourth quarter of 2011 resulting 

primarily from the impairment the Homer City, Fisk, Crawford and Waukegan power plants, wind related charges, writedown of a net investment in aircraft leases with American Airlines, and the impact on Edison International consolidated 

deferred income taxes resulting from an increase in the state apportionment rates due to such impairment charges as 

discussed in "Edison International Overview—Management Overview of EMG" and "Item 8. Edison International Notes 

to Consolidated Financial Statements Note 16—Asset Impairments, Lease Terminations and Other."

• An earnings benefit of $52 million in 2010 related to the acceptance by the California Franchise Tax Board of the tax 

positions finalized with the Internal Revenue Service in 2009 for the tax years 1986 through 2002 as part of the federal 

settlement of tax disputes and a revision to interest on federal disputed tax items. For more information, see "—Income 

Taxes" below.

• An after-tax earnings charge of $24 million ($40 million pre-tax) recorded in the fourth quarter of 2010 resulting from 

the write-off of capitalized engineering and other costs related to a change in air emissions control technology selection 

at the Powerton Station.
55

Adjusted Operating Income (Loss) ("AOI")—Overview

The following table shows the adjusted operating income (loss) (AOI) of EMG's projects:

(in millions)

Midwest Generation plants

Homer City plant1

Renewable energy projects

Energy trading1

Big 4 projects

Sunrise

Doga

March Point

Westside projects

Leveraged lease income

Lease terminations and other

Other projects

Other operating income (expense)2

Corporate administrative and general

Corporate depreciation and amortization

AOI3

Years ended December 31,

2011

$ (542)

(1,040)

39

74

44

32

26

8

7

5

(22)

10

(36)

(1,395)

(142)

(24)

$ (1,561)

2010

$ 264

114

51

110

52

33

15

17

1

5

(3)

10

1

670

(150)

(19)

$ 501

2009

$ 340

186

53

49

46

37

8

11

4

14

(887)

3

(2)

(138)

(175)

(15)

$ (328)

1

 Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT 

to deliver a portion of Homer City's power into the NYISO. To the extent this arrangement is not utilized, 

Homer City's power is delivered into PJM.

2

 Primarily related to EMG's decision to reduce its development pipeline and ongoing development 

activities. For additional information, see "Edison International (Consolidated): Liquidity and Capital 

Resources—Critical Accounting Estimates and Policies—Impairment of Long Lived Assets—Application 

to Selected EMG Wind Projects" in the MD&A and "Item 8. Edison International Notes to Consolidated 

Financial Statements—Note 16. Asset Impairments, Lease Terminations and Other."

3

 AOI is equal to operating income (loss) under GAAP, plus equity in income (loss) of unconsolidated 

affiliates, dividend income from projects, production tax credits, other income and expenses, and net loss 

attributable to noncontrolling interests. Production tax credits are recognized as wind energy is generated 

based on a per-kilowatt-hour rate prescribed in applicable federal and state statutes. AOI is a non-GAAP 

performance measure and may not be comparable to those of other companies. Management believes that 

inclusion of earnings of unconsolidated affiliates, dividend income from projects, production tax credits, 

other income and expenses, and net loss attributable to noncontrolling interests in AOI is meaningful for 

investors as these components are integral to the operating results of EMG.
56

The following table reconciles AOI to operating income (loss) as reflected on EMG's consolidated statements of operations:

(in millions)

AOI

Less:

Equity in income of unconsolidated affiliates

Dividend income from projects

Production tax credits

Other income, net

Net loss attributable to noncontrolling interests

Operating Income (Loss)

Years ended December 31,

2011

$ (1,561)

86

31

66

19

1

$ (1,764)

2010

$ 501

106

21

62

8

1

$ 303

2009

$ (328)

89

12

56

3

3

$ (491)

Adjusted Operating Income from Consolidated Operations

Midwest Generation Plants

The following table presents additional data for the Midwest Generation plants:

(in millions)

Operating Revenues

Operating Expenses

Fuel1

Plant operations

Plant operating leases

Depreciation and amortization

Asset impairments and other charges

Administrative and general

Total operating expenses

Operating Income (Loss)

Other Income

AOI

Statistics

Generation (in GWh)

Energy contracts

Load requirements services contracts

Total

Years ended December 31

2011

$ 1,286

512

456

75

117

650

22

1,832

(546)

4

$ (542)

28,145

—

28,145

2010

$ 1,479

519

448

75

114

42

22

1,220

259

5

$ 264

29,798

—

29,798

2009

$ 1,487

547

396

75

109

2

21

1,150

337

3

$ 340

28,977

1,333

30,310

1

 Included in fuel costs were $3 million, $13 million and $63 million in 2011, 2010 and 2009, respectively, 

related to the net cost of emission allowances.

AOI from the Midwest Generation plants decreased $806 million in 2011 compared to 2010, and decreased $76 million in 

2010 compared to 2009. The 2011 decrease in AOI, excluding the $640 million impairment charge previously discussed in 

"Edison International Overview—Highlights of Operating Results," was primarily attributable to lower energy and capacity 

revenues. The decline in energy revenues was due to lower average realized energy prices and lower generation due to the 

permanent shutdown of Will County Units 1 and 2 at the end of 2010 in accordance with the CPS. The decline in capacity 

revenues was due to lower capacity prices from the RPM auction. In addition, the change in AOI was impacted by a 

$40 million pre-tax charge in 2010 related to the write-off of capitalized engineering and other costs related to a change in air 

emissions control technology at the Powerton Station and a $24 million gain from the sale of bankruptcy claims against 

Lehman. The claims originated from power contracts that were terminated in 2008 due to the bankruptcy of Lehman. 
57

The 2010 decrease in AOI from 2009 was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 

2009 related to hedge contracts and an increase in plant maintenance costs, partially offset by higher capacity revenues and 

lower average realized fuel costs. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of 

plant outages in 2009. Average realized fuel costs per megawatt-hour were lower in 2010 as compared to 2009 primarily due 

to lower emission allowance costs partially offset by higher costs for activated carbon, which is used to reduce mercury 

emissions. The write-off of capitalized costs at the Powerton Station and the gain from the sale of bankruptcy claims against 

Lehman also affected the comparison of results between these periods. 

Included in operating revenues were unrealized gains (losses) of $3 million, $(6) million and $30 million in 2011, 2010 and 

2009, respectively. Unrealized gains (losses) were primarily attributable to economic hedge contracts that are accounted for at

fair value with offsetting changes recorded on the consolidated statements of operations. In addition, $10 million and 

$14 million was reversed from accumulated other comprehensive income and recognized in 2010 and 2009, respectively, 

related to power contracts with Lehman that were dedesignated as cash flow hedges, subsequently terminated and recorded as 

unrealized losses in 2008. Unrealized gains (losses) also included the ineffective portion of hedge contracts at the Midwest 

Generation plants attributable to changes in the difference between energy prices at the Northern Illinois Hub (the settlement 

point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where 

power generated by the Midwest Generation plants is delivered into the transmission system) resulting from marginal losses. 

Included in fuel costs were unrealized gains (losses) of $(4) million, $(7) million and $15 million in 2011, 2010 and 2009, 

respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 

2010 and 2009 to hedge variable fuel oil components of rail transportation costs.

Homer City

The following table presents additional data for the Homer City plant:

(in millions)

Operating Revenues1

Operating Expenses

Fuel2

Plant operations

Plant operating leases

Depreciation and amortization

Asset impairments and other charges

Administrative and general

Total operating expenses

Operating Income (Loss)

AOI

Statistics

Generation (in GWh)

Years ended December 31,

2011

$ 527

269

137

102

21

1,032

6

1,567

(1,040)

$ (1,040)

9,428

2010

$ 636

279

116

103

18

1

5

522

114

$ 114

11,028

2009

$ 663

251

103

102

16

1

4

477

186

$ 186

11,446

1

 Effective April 1, 2011, EMMT allocated to Homer City the benefit of an arrangement that allows EMMT 

to deliver a portion of Homer City's power into the NYISO. To the extent this arrangement is not utilized, 

Homer City's power is delivered into PJM.

2

 Included in fuel costs were $9 million, $7 million and $16 million in 2011, 2010 and 2009, respectively, 

related to the net cost of emission allowances.

AOI from the Homer City plant decreased $1.2 billion in 2011 compared to 2010 and decreased $72 million in 2010 

compared to 2009. The 2011 decrease in AOI, excluding the $1.03 billion impairment charge previously discussed in "Edison 

International Overview—Highlights of Operating Results," was primarily attributable to lower energy revenues, driven by 

lower generation and average realized energy prices, lower capacity revenues, and higher plant maintenance costs from 

outages at Units 1 and 2, partially offset by unrealized gains in 2011 compared to unrealized losses in 2010 related to hedge 

contracts and lower fuel costs. The decline in fuel costs was primarily due to lower generation, mostly offset by higher coal 

costs. Coal costs increased due to higher coal prices. The Homer City plant continued to have a high forced outage rate 

during 2011 partially as a result of the steam pipe rupture on Unit 1 and the related precautionary maintenance on Unit 2. 
58

The 2010 decrease in AOI from 2009 was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 

2009 related to hedge contracts, higher coal costs, lower generation, and higher plant operations costs related to scheduled 

plant outages, partially offset by an increase in capacity revenues. The Homer City plant experienced increased forced 

outages in 2010 compared to 2009 due to deratings to comply with opacity restrictions and unscheduled outages. Plant 

maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Coal costs 

increased due to higher coal prices and changes in the mix of ready-to-burn coal and raw coal consumed. 

Included in operating revenues were unrealized gains (losses) from hedge activities of $5 million, $(20) million and 

$15 million in 2011, 2010 and 2009, respectively. Unrealized gains (losses) were primarily attributable to the ineffective 

portion of hedge contracts at the Homer City plant attributable to changes in the difference between energy prices at the PJM 

West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point 

where power generated by the Homer City plant is delivered into the transmission system). 

For additional discussion, see "Edison International Overview—Management Overview of EMG—Homer City Lease."

Renewable Energy Projects

The following table presents additional data for EMG's renewable energy projects:

(in millions)

Operating Revenues

Production Tax Credits

Operating Expenses

Plant operations

Depreciation and amortization

Asset impairments and other charges

Administrative and general

Total operating expenses

Equity in income from unconsolidated affiliates

Other Income

Net Loss Attributable to Noncontrolling Interests

AOI1

Statistics

Generation (in GWh)2

Years ended December 31,

2011

$ 221

66

287

78

141

30

4

253

1

3

1

$ 39

5,564

2010

$ 137

62

199

55

89

3

3

150

—

2

—

$ 51

3,646

2009

$ 141

56

197

55

92

—

3

150

—

3

3

$ 53

3,081

1

 AOI is equal to operating income (loss) under GAAP plus equity in income (loss) of unconsolidated 

affiliates, dividend income from projects, production tax credits, other income and expense, and net 

(income) loss attributable to noncontrolling interests. Production tax credits are recognized as wind energy 

is generated based upon a per-kilowatt-hour rate prescribed in applicable federal and state statutes. Under 

GAAP, production tax credits generated by wind projects are recorded as a reduction in income taxes. 

Accordingly, AOI represents a non-GAAP performance measure which may not be comparable to those of 

other companies. Management believes that inclusion of production tax credits in AOI for wind projects is 

meaningful for investors as federal and state subsidies are an integral part of the economics of these 

projects. 

2

 Includes renewable energy projects that are unconsolidated at EMG. Generation excluding unconsolidated 

projects was 4,816 GWh in 2011, 3,037 GWh in 2010 and 2,514 GWh in 2009. 

AOI from renewable energy projects, excluding the $30 million impairment charge previously discussed in "Edison 

International Overview—Highlights of Operating Results," increased $18 million in 2011, and decreased $2 million in 2010 

compared to 2009. The 2011 increase was primarily attributable to projects that achieved commercial operation in late 2010 

and 2011 and increased generation at other projects due to favorable wind conditions during 2011, partially offset by lower 

realized prices from the merchant wind projects. EMG's share of installed capacity of new wind projects that commenced 

operations during 2011, 2010 and 2009 was 295 MW, 150 MW and 223 MW, respectively. 

AOI in 2010 and 2009 included payments from Suzlon Wind Energy Corporation (Suzlon) for availability losses of 
59

$2 million and $17 million, respectively. Payments under the availability guarantee are designed to compensate EMG for lost 

earnings, including production tax credits. Accordingly, the payments under the availability guarantee are paid on a pre-tax 

basis which affects period-to-period comparisons that include production tax credits which are after tax. 

Energy Trading

AOI from energy trading activities decreased $36 million in 2011 compared to 2010, and increased $61 million in 2010 

compared to 2009. The 2011 decrease was partially due to reduced revenues from power trading contracts in 2011 compared 

to 2010, partially offset by increased congestion revenues due to outages in the PJM markets. The decrease is also partially 

due to the allocation to Homer City of the benefit of an arrangement that allows EMMT to deliver a portion of Homer City's 

power into the NYISO. The 2010 increase in AOI energy trading activities was attributable to increased revenues in 

congestion and power trading. Congestion trading results increased in 2010 compared to 2009 due to unseasonably cold 

weather and transmission outages in the New York and PJM markets.

Adjusted Operating Income from Leveraged Lease Activities and Lease Terminations and Other

AOI from leveraged lease income declined from 2009 as a result of the termination of cross border leases which resulted in a 

$920 million loss. This loss was partially offset by a $33 million gain in 2009 from the sale of an interest in a leveraged lease 

(Midlands Cogeneration Ventures). For further discussion, see "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 16. Asset Impairments, Lease Terminations and Other."

Adjusted Operating Income from Other Projects

The CPUC-approved comprehensive settlement related to power sales from cogeneration facilities became effective in 

November 2011, and resulted in additional non-recurring adjusted operating income in 2011 totaling $11 million. 

Big 4 Projects. AOI from the Big 4 projects decreased $8 million in 2011 compared to 2010, and increased $6 million in 

2010 compared to 2009. The 2011 decrease was primarily due to lower energy margins at Watson and lower contracted 

capacity under Midway-Sunset's new power purchase agreement, partially offset by additional revenues due to the settlement 

agreement discussed above. The 2010 increase was driven by changes in natural gas prices affecting steam revenues and 

plant maintenance. 

Westside Projects. AOI from the Westside projects increased $6 million in 2011 compared to 2010, and decreased 

$3 million in 2010 compared to 2009. The 2011 increase was primarily attributable to the new power purchase agreements, 

which became effective upon the settlement discussed above, and provided higher capacity prices retroactive to 2010. The 

2010 decrease was primarily due to higher fuel and maintenance costs partially offset by higher revenues. 

Doga. The 2011 increase in AOI was due to higher distributions resulting primarily from the elimination of restricted cash 

as a result of the repayment of the remaining project debt. The 2010 increase was due to the timing of distributions. AOI is 

recognized when cash is distributed from the project as the Doga project is accounted for on the cost method. 

March Point. The 2011 income was due to the receipt of payment from the sale of the project. The 2010 AOI was primarily 

due to equity distributions received from the project prior to the sale of EMG ownership interest to its partner. 

Corporate Administrative and General Expenses

Corporate administrative and general expenses were lower during the past two years as EMG reduced development costs 

incurred pursuing renewable projects. 

Interest Income (Expense)

(in millions)

Interest income

Interest expense, net of capitalized interest

EME debt

Non-recourse debt

Years ended December 31,

2011

$ 1

(257)

(67)

$ (324)

2010

$ 9

(229)

(35)

$ (264)

2009

$ 17

(267)

(39)

$ (306)

Interest income decreased primarily due to lower interest rates and, to a lesser extent, lower average cash balances.
60

EMG's interest expense increased $60 million in 2011 from 2010 and decreased $42 million in 2010 from 2009. The 2011 

increase in interest expense was primarily due to higher debt balances from new project financings and lower capitalized 

interest. The 2010 decrease in interest expense was primarily due to higher capitalized interest and lower debt balances under 

EME's and Midwest Generation's credit facilities, partially offset by higher wind project financing. Capitalized interest was 

$27 million, $54 million and $19 million in 2011, 2010 and 2009, respectively. The 2011 decrease was due to completion of 

the renewable energy projects under construction in 2010 and 2011. The 2010 increase was the result of increased interest 

capitalization for renewable energy projects under construction.

Income Taxes

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate:

(in millions)

Income (loss) from continuing operations before

income taxes

Provision for income tax expense (benefit) at

federal statutory rate of 35%

Increase (decrease) in income tax from:

Global settlement related

 State tax – net of federal provision (benefit)

 Tax credits, net

Property-related

Other

Total income tax benefit from continuing

operations

Effective tax rate

Years ended December 31,

2011

$ (1,951)

$ (683)

—

(104)

(68)

(6)

(3)

$ (864)

44%

2010

$ 183

$ 64

(52)

3

(66)

15

—

$ (36)

*

2009

$ (675)

$ (236)

37

(20)

(63)

(2)

—

$ (284)

42%

*

 Not meaningful.

EMG's effective tax rate for 2011 was impacted by production tax credits and estimated state income tax benefits allocated 

from Edison International. The effective tax rate for 2010 was impacted by production tax credits and the Global Settlement. 

Estimated state income tax benefits allocated from Edison International of $6 million, $7 million and $15 million were 

recognized for the years ended December 31, 2011, 2010 and 2009, respectively.

For further discussion, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 7. Income 

Taxes."

Results of Discontinued Operations

The results of discontinued operations include foreign exchange gains and interest expense on contract indemnities 

denominated in euros, adjustments to unrecognized tax benefits, and expiration in 2010 of another contract indemnity. The 

contract indemnities relate to the sale of EMG's international projects in December 2004.

Related Party Transactions

EMG owns interests in partnerships that sell electricity generated by their project facilities to SCE and others under the terms 

of power purchase agreements. Sales by these partnerships to SCE under these agreements amounted to $277 million, 

$367 million and $366 million in 2011, 2010 and 2009, respectively.
61

LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

The following table summarizes available liquidity at December 31, 2011:

(in millions)

EME as a holding company

EME subsidiaries without contractual dividend restrictions

EME corporate cash and cash equivalents

EME subsidiaries with contractual dividend restrictions

Midwest Generation2

Homer City

Other EME subsidiaries

Other EMG subsidiaries

Total

Cash and Cash

Equivalents

$ 738

213

951

213

84

52

61

$ 1,361

Available

Under Credit

Facilities1

$ 498

—

498

497

—

—

—

$ 995

Total

Available

Liquidity

$ 1,236

213

1,449

710

84

52

61

$ 2,356

1

 Existing credit facilities mature in 2012. For further discussion, see "Edison International Overview—

Management Overview of EMG" in the MD&A and "Item 1A. Risk Factors—Risks Relating to EMG—

Liquidity Risks." The EME credit facility was terminated subsequent to year end.

2

 Cash and cash equivalents are available to meet Midwest Generation's operating and capital expenditure 

requirements.

EME, as a holding company, does not directly operate any revenue-producing generation facilities, EME relies on cash 

distributions and tax payments from its projects and tax benefits received under a tax-allocation agreement with Edison 

International to meet its obligations, including debt service obligations on long-term debt. The timing and amount of 

distributions from EME's subsidiaries may be restricted. For further details, including the current restrictions on distributions 

from the Homer City facility, see "—Debt Covenants and Dividend Restrictions—Dividend Restrictions in Major 

Financings."

The following table summarizes the status of the EME and Midwest Generation credit facilities, which mature in June 2012, 

at December 31, 2011:

(in millions)

Commitments

Outstanding borrowings

Outstanding letters of credit

Amount available

EME

$ 564

—

(66)

$ 498

Midwest

Generation

$ 500

—

(3)

$ 497

Senior notes in the principal amount of $500 million, which bear interest at 7.50% per annum, are due in June 2013. EME 

may from time to time, seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, open 

market purchases, privately negotiated transactions or otherwise, depending on prevailing market conditions, EME's liquidity 

requirements, contractual restrictions and other factors.

For information regarding EMG's plan to obtain third-party capital to finance the development of a portion of EMG's wind 

portfolio, see "Edison International Overview—Management Overview of EMG—EMG's Renewable Energy Activities" in 

the MD&A and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities

—Categories of VIEs—Capistrano Wind Equity Capital-2012."
62

Capital Investment Plan

Forecasted capital expenditures through 2014 by EMG's subsidiaries for existing projects and corporate activities are as 

follows:

(in millions)

Midwest Generation Plants

Environmental1

Plant Capital

Walnut Creek Project

Renewable Energy Projects

Capital and construction

Other capital

Total

2012

$ 35

21

229

114

22

$ 421

2013

$ 102

46

40

1

19

$ 208

2014

311

16

—

2

15

344

1

 For additional information, see "Edison International Overview—Management Overview of EMG—

Midwest Generation Environmental Compliance Plans and Costs."

Midwest Generation Capital Expenditures

Midwest Generation plants' projected environmental expenditures would retrofit Powerton Units 5 and 6, Joliet Units 7 and 8 

and Will County Units 3 and 4, using dry scrubbing with sodium-based sorbents and upgrading particulate removal systems 

to comply with CPS requirements for SO2 emissions and the US EPA's regulation on HAP emissions. Decisions regarding 

whether or not to proceed with retrofitting any particular remaining units to comply with CPS requirements for SO2

emissions, including those that have received permits, remain subject to a number of factors, such as market conditions, 

regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the 

time decisions are required or made. Final decisions on whether to install controls, to install particular kinds of controls, and 

to actually expend capital or continue with the expenditure of capital will be made as required, subject to the requirements of

the CPS and other applicable regulations. Furthermore, the timing of commencing capital projects may vary from the 

amounts set forth in the above table. For additional discussion, see "Edison International Overview—Management Overview 

of EMG—Midwest Generation Environmental Compliance Plans and Costs."

Plant capital expenditures for Midwest Generation includes capital projects for boiler and turbine controls, major boiler 

components and electrical systems.

Homer City Capital Expenditures

The capital investment plan set forth above does not include environmental capital expenditures to retrofit the Homer City 

plant because Homer City does not have the funds for retrofits and has not yet been able to raise capital needed for such 

retrofits. The funding of Homer City's environmental expenditures will be dependent on external funding. See "Edison 

International Overview—Management Overview of EMG—Homer City Lease." Plant capital expenditures for Homer City 

are projected to be $39 million, $23 million, and $14 million in 2012, 2013, and 2014, respectively. 

Walnut Creek Capital Expenditures

In July 2011, EME secured $495 million in construction and term financing for the Walnut Creek project. 

Renewable Energy Projects

Construction of the 80 MW Broken Bow I wind project commenced during the third quarter of 2011 and EME expects the 40 

MW Crofton Bluffs wind project to commence construction in the second quarter of 2012. Commercial operations of the 

Broken Bow I and the Crofton Bluffs projects are expected in the fourth quarter of 2012.

On December 21, 2011, EMG closed a $242 million financing for a portfolio of three contracted wind projects representing 

204 megawatts of generation capacity previously funded entirely with equity.

For information regarding third-party equity capital raised in February 2012 to finance the development of a portion of 

EMG's wind portfolio, see "Edison International Overview—Management Overview of EMG—EMG's Renewable Energy 

Activities" in the MD&A and "Item 8. Edison International and Subsidiaries Notes to Consolidated Financial Statements—

Note 3. Variable Interest Entities—Categories of VIEs—Capistrano Wind Equity Capital-2012."
63

During the fourth quarter of 2011, EMG significantly reduced its development activities to conserve cash and in light of more 

limited market opportunities. As a result, EMG reduced staffing and has undertaken efforts to reduce funding joint 

development projects, thereby reducing the development pipeline of potential wind projects to approximately 1,300 MW. 

Future development of the wind portfolio is dependent on the availability of third-party capital. To the extent that third-party 

capital is available, the success of development efforts will depend upon, among other things, obtaining permits and 

agreements necessary to support an investment.

Historical Segment Cash Flows

The table below sets forth condensed historical cash flow information for EMG.

(in millions)

Operating cash flow from continuing operations

Operating cash flow from discontinued operations

Net cash provided (used) by operating activities

Net cash provided (used) by financing activities

Net cash provided (used) by investing activities

Net increase (decrease) in cash and cash equivalents

Years ended December 31,

2011

$ 662

(3)

659

277

(674)

$ 262

2010

$ 306

4

310

336

(732)

$ (86)

2009

$ (985)

(7)

(992)

(656)

861

$ (787)

Net Cash Provided (Used) by Operating Activities

Cash provided by operating activities from continuing operations increased $356 million in 2011 compared to 2010 primarily 

due to a $253 million deposit paid by Edison Capital to the IRS in 2010 related to Global Settlement and an increase in U.S. 

Treasury grants received by EME, partially offset by a decrease in operating income at EME due to declining energy prices, 

increasing operating costs, and higher interest payments due to new energy project financings.

Cash provided by operating activities from continuing operations increased $1.3 billion in 2010 compared to 2009 primarily 

due to the impacts of the Global Settlement. In April 2010, Edison Capital funded a $253 million deposit to the IRS related to 

the Global Settlement. In 2009, Edison Capital made a net tax-allocation payment to Edison International of $1.1 billion 

related to the termination of Edison Capital's interest in cross-border leases (see "Item 8. Edison International Notes to 

Consolidated Financial Statements—Note 7. Income Taxes" for further discussion). The 2010 increase was also due to higher 

realized revenue from derivative contracts and payments on U.S. Treasury grants.

Net Cash Provided (Used) by Financing Activities

Cash provided by financing activities from continuing operations decreased $59 million in 2011 compared to 2010 primarily 

due to higher repayment of credit facilities by EME in 2011, partially offset by Edison Capital redeeming $89 million of its 

medium-term loans in 2010.

Cash provided by financing activities from continuing operations increased $1 billion in 2010 compared to 2009. In 2010, 

financing activities included project-level financing of renewable energy projects and repayment of credit facilities in 2009.

Net Cash Used by Investing Activities

Cash used by investing activities from continuing operations decreased $58 million in 2011 compared to 2010 primarily due 

to the timing of construction of EME's wind projects.

Cash used by investing activities from continuing operations decreased $1.6 billion in 2010 compared to 2009. The 2010 

decrease was primarily due to $1.385 billion of net proceeds from termination of the cross-border leases at Edison Capital in 

2009. The change was also due to the construction of wind projects.
64

Credit Ratings

Credit ratings for EME, Midwest Generation and EMMT as of December 31, 2011 were as follows:

EME1

Midwest Generation2

EMMT

Moody's

Rating

Caa1

Ba3

Not Rated

S&P Rating

BB+

BFitch

Rating

CCC

BBNot Rated

1 Senior unsecured rating.

2 First priority senior secured rating.

All the above ratings are on negative outlook. EMG cannot provide assurance that its current credit ratings or the credit 

ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be

lowered. EMG notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at 

any time by a rating agency.

EMG does not have any "rating triggers" contained in subsidiary financings that would result in a requirement to make equity 

contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at 

Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations 

for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts 

that do not require margin, but contain the right of each party to request additional credit support in the form of adequate 

assurance of performance in the case of an adverse development affecting the other party.

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

To reduce its exposure to market risk, EMG hedges a portion of its electricity price exposure through EMMT. In connection 

with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, 

margining or other credit support. EME has entered into guarantees in support of EMMT's hedging and trading activities. 

However, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of 

counterparties. For further details, see "Edison International Notes to Consolidated Financial Statements—Note 6. Derivative 

Instruments and Hedging Activities."

Future cash collateral requirements may be higher than the margin and collateral requirements at December 31, 2011, if 

wholesale energy prices change or if EMMT enters into additional transactions. EMG estimates that margin and collateral 

requirements for energy and congestion contracts outstanding as of December 31, 2011 could increase by approximately 

$34 million over the remaining life of the contracts using a 95% confidence level.

Intercompany Tax-Allocation Agreement

EMG and its subsidiaries, EME and Edison Capital, are included in the consolidated federal and combined state income tax 

returns of Edison International and are eligible to participate in tax-allocation payments with other subsidiaries of Edison 

International in circumstances where domestic tax losses are incurred. The right of EME and Edison Capital to receive and 

the amount of and timing of tax-allocation payments are dependent on the inclusion of EME and Edison Capital in the 

consolidated income tax returns of Edison International and its subsidiaries and other factors, including the consolidated 

taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EMG's 

subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state taxes. EMG 

received net tax-allocation payments of $241 million in 2011 and made net tax-allocation payments of $371 million and 

$1.1 billion in 2010 and 2009, respectively. EMG expects to make tax-allocation payments to Edison International during 

2012 of approximately $185 million as a result of the reallocation of tax obligations from an expected Edison International 

consolidated net operating loss in 2011.

Debt Covenants and Dividend Restrictions

Dividend Restrictions in Major Financings

Each of EMG's direct or indirect subsidiaries is organized as a legal entity separate and apart from EMG and its other 

subsidiaries. Except for certain of EMG's wind projects in portfolio financings, assets of EMG's subsidiaries are not available 

to satisfy EMG's obligations or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that 
65

are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be 

advanced, loaned, paid as dividends or otherwise distributed or contributed to EMG or to its subsidiary holding companies.

Key Ratios of EMG's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EMG's principal subsidiaries required by financing arrangements at December 31, 2011 or 

for the 12 months ended December 31, 2011:

Subsidiary

Midwest Generation (Midwest

Generation plants)

Homer City (Homer City plant)

Financial Ratio

Debt to Capitalization

Ratio

Senior Rent Service

Coverage Ratio

Covenant

Less than or equal to

0.60 to 1

Greater than 1.7 to 1

Actual

0.15 to 1

1.18 to 1

As indicated above, the actual senior rent service coverage ratio of Homer City was below the covenant threshold for the 

12 months ended December 31, 2011, and Homer City also did not meet the threshold for the prospective two 12-month 

periods, which currently precludes Homer City from making distributions, including repayment of certain intercompany 

loans and from paying the equity portion of the rent payment. For additional information, see "Edison International Overview

—Management Overview of EMG—Homer City Lease."

Midwest Generation Financing Restrictions on Distributions

Midwest Generation is bound by the covenants in its credit agreement and certain covenants under the Powerton-Joliet lease 

documents with respect to Midwest Generation making payments under the leases. These covenants include restrictions on 

the ability to, among other things, incur debt, create liens on its property, merge or consolidate, sell assets, make investments, 

engage in transactions with affiliates, make distributions, make capital expenditures, enter into agreements restricting its 

ability to make distributions, engage in other lines of business, enter into swap agreements, or engage in transactions for any

speculative purpose. In order for Midwest Generation to make a distribution, it must be in compliance with the covenants 

specified under its credit agreement, including maintaining a debt-to-capitalization ratio of no greater than 0.60 to 1.

Homer City Sale-Leaseback Restrictions on Distributions

Homer City completed a sale-leaseback of the Homer City plant in December 2001. In order to make a distribution, Homer 

City must be in compliance with the covenants specified in the lease agreements, including the following financial 

performance requirements measured on the date of distribution.

At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid and the senior rent 

service coverage ratio for the prior 12-month period (taken as a whole and projected for each of the prospective two 12-

month periods) must be greater than 1.7 to 1 in order to make the equity portion of the rent payment and other restricted 

payments. Homer City would be permanently restricted in its ability to make distributions if a failure to pay equity rent when 

due was not cured within nine months, or even if cured, occurred more than one additional time during the term of the lease. 

EME has not guaranteed Homer City's obligations under the leases. Homer City believes it is unlikely to meet the covenant 

requirements of its sale-leaseback agreements relating to the payment of equity rent at April 1, 2012, and will be unable to 

make the required equity rent payment. There is no assurance that subsequent rent payments will be made. For additional 

information, see "Edison International Overview—Management Overview of EMG—Homer City Lease."

EME's Senior Notes and Guaranty of Powerton-Joliet Leases

EME is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the 

aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of 

consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter 

preceding the sale or disposition in question. At December 31, 2011, the maximum permissible sale or disposition of EME 

assets was $778 million.

This limitation does not apply if the proceeds are invested in assets in similar or related lines of business of EME. 

Furthermore, EME may sell or otherwise dispose of assets in excess of such 10% limitation if the proceeds from such sales or 

dispositions, which are not reinvested as provided above, are retained as cash or cash equivalents or are used to repay debt.
66

Contractual Obligations, Commercial Commitments and Contingencies

Contractual Obligations

EMG has contractual obligations and other commercial commitments that represent prospective cash requirements. The 

following table summarizes EMG's significant consolidated contractual obligations as of December 31, 2011.

(in millions)

Long-term debt1

Power plant and other operating lease 

obligations2

Purchase obligations3:

Midwest Generation fuel supply contracts

Midwest Generation coal transportation 

agreements4

Homer City fuel supply contracts

Gas transportation agreements

Capital expenditures

Other contractual obligations

Employee benefit plan contribution5

Total Contractual Obligations6,7

Total

$ 7,042

2,851

518

3,023

267

46

305

177

120

$ 14,349

Payments Due by Period

Less than

1 year

$ 363

337

223

386

214

7

286

93

21

$ 1,930

1 to 3

years

$ 1,594

637

295

659

53

14

19

65

48

$ 3,384

3 to 5

years

$ 1,123

320

—

630

—

15

—

17

51

$ 2,156

More than

5 years

$ 3,962

1,557

—

1,348

—

10

—

2

—

$ 6,879

1

 For additional details, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 5. Debt and 

Credit Agreements." Amount also includes interest payments totaling $2.1 billion over the applicable period of the debt. 

2

 At December 31, 2011, minimum operating lease payments were primarily related to long-term leases for the Powerton and 

Joliet Stations and the Homer City plant. For further discussion, see "—Off-Balance Sheet Transactions—Sale-Leaseback 

Transactions" and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and 

Contingencies."

3

 For additional details, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments 

and Contingencies."

4

 Years subsequent to 2012 represent contracts for minimum volumes without regard to payment of alternative liquidated 

damages or plant closures.

5

 Amount includes estimated contribution for pension plans and postretirement benefits other than pensions. The estimated 

contributions beyond 2016 are not available. For more information, see "Item 8. Edison International Notes to Consolidated 

Financial Statements—Note 8. Compensation and Benefit Plans—Pension Plans and Postretirement Benefits Other than 

Pensions."

6

 At December 31, 2011, EMG had a total net liability recorded for uncertain tax positions of $240 million, which is excluded 

from the table. EMG cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of 

resolving these open tax issues with the Internal Revenue Service. For more information, see "Item 8. Edison International 

Notes to Consolidated Financial Statements—Note 7. Income Taxes."

7

 The contractual obligations table does not include derivative obligations and AROs, which are discussed in "Item 8. Edison 

International Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities," and 

"—Note 2. Property, Plant and Equipment," respectively.

Commercial Commitments

Standby Letters of Credit

As of December 31, 2011, standby letters of credit under EMG and its subsidiaries' credit facilities aggregated $177 million 

and were scheduled to expire as follows: $146 million in 2012 and $3 million in 2013, $10 million in 2017, and $18 million 

in 2018. Certain letters of credit are subject to automatic annual renewal provisions.
67

Contingencies

EMG has contingencies related to the Midwest Generation NSR and other litigation, Homer City NSR and other litigation, 

and environmental remediation which are discussed in "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 9. Commitments and Contingencies."

Off-Balance Sheet Transactions

EMG has off-balance sheet transactions in three principal areas: investments in projects accounted for under the equity 

method, operating leases resulting from sale-leaseback transactions and leveraged leases.

Investments Accounted for under the Equity Method

EMG has a number of investments in power projects that are accounted for under the equity method. For further discussion, 

see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities."

Subsidiaries of EMG have invested in affordable housing projects utilizing partnership or limited liability companies in 

which EMG is a passive investor. With a few exceptions, an unrelated general partner or managing member exercises 

operating control of these projects and partnerships. The debt of those partnerships and limited liability companies is secured

by real property. At December 31, 2011, entities that EMG has accounted for under the equity method had indebtedness of 

approximately $1.2 billion, of which approximately $318 million is proportionate to EMG's ownership interest in these 

projects. Substantially all of this debt is nonrecourse to EMG.

Sale-Leaseback Transactions

EMG has entered into sale-leaseback transactions related to the Powerton Station and Units 7 and 8 of the Joliet Station in 

Illinois and the Homer City plant in Pennsylvania. For further discussion, see "Edison International Overview—Management 

Overview of EMG—Homer City Lease" and "Item 8. Edison International Notes to Consolidated Financial Statements—

Note 9. Commitments and Contingencies—Power Plant and Other Lease Commitments."

The lessor equity and lessor debt associated with the sale-leaseback transactions for the Powerton, Joliet and Homer City 

assets are summarized in the following table:

Power Station(s)

Powerton/Joliet

Homer City

Acquisition

Price

(in millions)

$ 1,367

$ 1,591

Equity Investor

PSEG/Citigroup, Inc.

GECC/Metropolitan Life

Insurance Company

Original Equity

Investment in

Owner-Lessor

(in millions)

$ 238

$ 798

Amount of Lessor

Debt at

December 31, 2011

(in millions)

$ 460

$ 183

$ 477

Series B

Series A

Series B

Maturity 

Date

of

Lessor Debt

2016

2019

2026

PSEG – PSEG Resources, Inc.

GECC – General Electric Capital Corporation

The operating lease payments to be made by each of EMG's subsidiary lessees are structured to service the lessor debt and 

provide a return to the owner-lessor's equity investors. Neither the value of the leased assets nor the lessor debt is reflected on 

EMG's consolidated balance sheet.

MARKET RISK EXPOSURES

Introduction

EMG's primary market risk exposures are associated with the sale of electricity and capacity from, and the procurement of 

fuel for, its merchant power plants. These market risks arise from price fluctuations of electricity, capacity, fuel, emission 

allowances, and transmission rights. Additionally, EMG's financial results can be affected by fluctuations in interest rates. 

EMG manages these risks in part by using derivative instruments in accordance with established policies and procedures.

Derivative Instruments

EMG uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, 

capacity, fuel, emission allowances, and transmission rights. For derivative instruments recorded at fair value, changes in fair 

value are recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting. 
68

For derivatives that qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive 

income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that 

qualifies for cash flow hedge accounting is recognized currently in earnings.

Unrealized Gains and Losses

EMG classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that 

qualify for hedge accounting) as part of operating revenues or fuel costs. The following table summarizes unrealized gains 

(losses) from non-trading activities:

(in millions)

Midwest Generation plants

Non-qualifying hedges

Ineffective portion of cash flow hedges

Homer City plant

Non-qualifying hedges

Ineffective portion of cash flow hedges

Total unrealized gains (losses)

Years ended December 31,

2011

$ (2)

1

(1)

6

$ 4

2010

$ (11)

(2)

(1)

(19)

$ (33)

2009

$ 40

5

1

14

$ 60

At December 31, 2011, cumulative unrealized gains of $7 million were recognized from non-qualifying hedge contracts or 

the ineffective portion of cash flow hedges related to 2012.

Fair Value Disclosures

In determining the fair value of EMG's derivative positions, EMG uses third-party market pricing where available. For 

further explanation of the fair value hierarchy and a discussion of EMG's derivative instruments, see "Item 8. Edison 

International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements" and "—Note 6. Derivative 

Instruments and Hedging Activities," respectively.

The net fair value of commodity derivatives used for non-trading purposes at December 31, 2011 was $42 million. A 10% 

change in the market price of the underlying commodity at December 31, 2011 would increase or decrease the net fair value 

of non-trading commodity derivatives by approximately $26 million.

The net fair value of derivatives used for trading purposes at December 31, 2011 was $107 million. A 10% change in the 

market price of the underlying commodity at December 31, 2011 would increase or decrease the net fair value of trading 

contracts by approximately $19 million. The impact of changes to the various inputs used to determine the fair value of 

Level 3 derivatives would not be anticipated to be material to EME's results of operations as such changes would be offset by 

similar changes in derivatives classified within Level 3 as well as other levels. Level 3 assets and liabilities are 56% and 11%, 

respectively, of derivative assets and liabilities measured at fair value before the impact of offsetting collateral and netting as 

of December 31, 2011.

Commodity Price Risk

Introduction

EMG's merchant operations are exposed to commodity price risk, which reflects the potential impact of a change in the 

market value of a particular commodity. Commodity price risks are actively monitored, with oversight provided by a risk 

management committee, to ensure compliance with EMG's risk management policies. Despite this, there can be no assurance 

that all risks have been accurately identified, measured and/or mitigated.

Energy Price Risk

Energy and capacity from the coal plants are sold under terms, including price, duration and quantity, arranged by EMMT 

with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy 

sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Energy from 

428 MW of merchant renewable energy projects is sold in the energy markets, primarily at spot prices in PJM and ERCOT.
69

The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated:

Midwest Generation plants

Northern Illinois Hub

Homer City plant

PJM West Hub

Homer City Busbar

24-Hour Average Historical Market Prices1

2011

$ 33.21

$ 43.57

39.58

2010

$ 33.12

$ 46.56

39.18

2009

$ 28.68

$ 38.75

34.27

1 Energy prices were calculated at the Northern Illinois Hub and Homer City Busbar delivery points and the PJM 

West Hub using historical hourly day-ahead prices as published by PJM or provided on the PJM web-site.

The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern 

Illinois Hub and PJM West Hub at December 31, 2011:

2012 calendar "strip"2

2013 calendar "strip"2

24-Hour Forward Energy Prices1

Northern

Illinois Hub

$ 29.75

$ 31.41

PJM West

Hub

$ 38.85

$ 41.26

1 Energy prices were determined by obtaining broker quotes and information from other public sources 

relating to the Northern Illinois Hub and PJM West Hub delivery points.

2 Market price for energy purchases for the entire calendar year.

Power prices at the Northern Illinois Hub fell in the fourth quarter of 2011 and continued to fall in 2012 due to an abundance 

of low-priced natural gas and the sales volume from the Midwest Generation plants has been correspondingly affected. 

Forward market prices at the Northern Illinois Hub and PJM West Hub fluctuate as a result of a number of factors, including 

natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather,

economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant 

capacity. The actual spot prices for electricity delivered by the coal plants into these markets may vary materially from the 

forward market prices set forth in the preceding table.
70

EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The 

following table summarizes the hedge positions (including load requirements services contracts and forward contracts 

accounted for on the accrual basis) as of December 31, 2011 for electricity expected to be generated in 2012 and 2013:

Midwest Generation plants2

Homer City plant3,4

PJM West Hub

Total

2012

MWh (in

thousands)

7,185

432

7,617

Average

price/

MWh1

$ 38.76

52.34

2013

MWh (in

thousands)

1,020

—

1,020

Average

price/

MWh1

$ 40.43

—

1 The above hedge positions include forward contracts for the sale of power and futures contracts during different 

periods of the year and the day. Market prices tend to be higher during on-peak periods and during summer months, 

although there is significant variability of power prices during different periods of time. Accordingly, the above 

hedge positions are not directly comparable to the 24-hour Northern Illinois Hub or PJM West Hub prices set forth 

above.

2 Includes hedging transactions primarily at the Northern Illinois Hub and to a lesser extent the AEP/Dayton Hub, both 

in PJM, and the Indiana Hub in MISO.

3 Includes hedging transactions primarily at the PJM West Hub and to a lesser extent at other trading locations. 2012 

includes hedging activities entered into by EMMT for the Homer City plant that are not designated under the 

intercompany agreements with Homer City due to limitations under the sale- leaseback transaction documents.

4

 The average price/MWh includes 172 MW of capacity for periods ranging from January 1, 2012 to May 31, 2012 at 

Homer City sold in conjunction with load requirements services contracts.

In January 2012, EMMT entered into 14.7 billion cubic feet of natural gas futures contracts (equivalent to approximately 

1,610 GWh of energy only contracts using a ratio of 9.12 MMBtu to 1 MWh) for the Midwest Generation plants to 

economically hedge energy price risks through December 2012 at an average price of $24.88/MWh. 

Capacity Price Risk

Under the RPM, capacity commitments are made in advance to provide a long-term pricing signal for construction of 

capacity resources. 
71

The following table summarizes the status of capacity sales for Midwest Generation and Homer City at December 31, 2011:

January 1, 2012 to

May 31, 2012

Midwest Generation

Homer City

June 1, 2012 to

May 31, 2013

Midwest Generation

Homer City

June 1, 2013 to

May 31, 2014

Midwest Generation

Homer City

June 1, 2014 to

May 31, 2015

Midwest Generation

Homer City

Installed

Capacity

MW

5,477

1,884

5,477

1,884

5,477

1,884

5,477

1,884

Unsold

Capacity1

MW

(555)

(163)

(773)

(232)

(827)

(104)

(852)

(190)

Capacity

Sold2

MW

4,922

1,721

4,704

1,652

4,650

1,780

4,625

1,694

RPM Capacity

Sold in Base

Residual Auction

MW

4,582

1,771

4,704

1,736

4,650

1,780

4,625

1,694

Price per

MW-day

$ 110.00

110.00

16.46

133.37

27.73

226.15

125.99

136.50

Other Capacity Sales,

Net of Purchases3

MW

340

(50)

—

(84)

—

—

—

—

Average

Price per

MW-day

$ 98.92

30.00

—

16.46

—

—

—

—

Aggregate

Average

Price per

MW-day

$ 109.23

112.32

16.46

139.31

27.73

221.03

125.99

136.50

4

1 Capacity not sold arises from: (i) capacity retained to meet forced outages under the RPM auction guidelines, and 

(ii) capacity that PJM does not purchase at the clearing price resulting from the RPM auction.

2 Excludes 172 MW of capacity for periods ranging from January 1, 2012 to May 31, 2012 at Homer City sold in conjunction 

with load requirements services contracts.

3 Other capacity sales and purchases, net includes contracts executed in advance of the RPM base residual auction to hedge 

the price risk related to such auction, participation in RPM incremental auctions and other capacity transactions entered into 

to manage capacity risks.

4 Includes the impact of a 100 MW capacity swap transaction executed prior to the base residual auction at $135 per MW-day.

The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 and June 1, 2013 to May 31, 2014 

varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the prices of $16.46 per 

MW-day and $27.73 per MW-day were substantially lower than other areas' capacity prices. The impact of lower capacity 

prices for these periods compared to previous years will have an adverse effect on Midwest Generation's revenues unless 

such lower capacity prices are offset by an unavailability of competing resources and increased energy prices.

Revenues from the sale of capacity from Midwest Generation and Homer City beyond the periods set forth above will depend 

upon the amount of capacity available and future market prices either in PJM or nearby markets if EME has an opportunity to 

capture a higher value associated with those markets. 

For additional information regarding capacity sold by Homer City, see "Edison International Overview—Management 

Overview of EMG—Homer City Lease."

Basis Risk

Sales made from the coal plants in the real-time or day-ahead market receive the actual real-time or day-ahead prices, as the 

case may be, at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in forward

spot prices at the individual plant busbars, EMG may enter into cash settled futures contracts as well as forward contracts 

with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at 

the individual plant busbars does not exist. A liquid market does exist for a settlement point at the PJM West Hub in the case 

of the Homer City plant and for settlement points at the Northern Illinois Hub and the AEP/Dayton and Indiana Hubs in the 

case of the Midwest Generation plants. EMG's hedging activities use these settlement points (and, to a lesser extent, other 
72

similar trading hubs) to enter into hedging contracts. To the extent that, on the settlement date of a hedge contract, spot prices 

at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge 

contract are effectively reduced by the difference. This is referred to as "basis risk." During 2011, day-ahead prices at the 

Homer City busbar were lower than those at the PJM West Hub by an average of 9%, compared to 16% during 2010 and 12% 

during 2009, due to transmission congestion in PJM. During 2011, day-ahead prices at the individual busbars of the Midwest 

Generation plants were lower than the AEP/Dayton Hub, Cinergy Hub and Northern Illinois Hub by an average of 14%, 4% 

and less than 1%, respectively, compared to 13%, 6% and less than 1%, respectively, during 2010, due to transmission 

congestion in PJM.

In order to mitigate basis risk, EMG may purchase financial transmission rights and basis swaps in PJM for Homer City and 

Midwest Generation. A financial transmission right is a financial instrument that entitles the holder to receive the difference

between actual day-ahead prices for two delivery points in exchange for a fixed amount.

Coal and Transportation Price Risk

The Midwest Generation plants and Homer City plant purchase coal primarily from the Southern PRB of Wyoming and from 

mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. 

The following table summarizes the amount of coal under contract at December 31, 2011 for the following three years:

Midwest Generation plants

Homer City plant

Amount of Coal Under Contract

in Millions of Equivalent Tons1

2012

16

3.3

2013

9.8

0.8

2014

9.8

—

1

 The amount of coal under contract in equivalent tons is calculated based on contracted tons and 

applying an 8,800 Btu equivalent for the Midwest Generation plants and 13,000 Btu equivalent for the 

Homer City plant.

EMG is subject to price risk for purchases of coal that are not under contract. Market prices of NAPP coal, which are related 

to the price of coal purchased for the Homer City plant, increased during the past two years. The market price of NAPP coal 

based on 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content was $73.30 per ton at 

December 30, 2011, compared to a price of $70 per ton and $52.50 per ton at December 31, 2010 and 2009, respectively, as 

reported by the EIA. In 2011, the price of NAPP coal ranged from $70 per ton to $78.20 per ton, as reported by the EIA. The 

2011 increase in NAPP coal prices was primarily driven by the export market demand and global coal pricing. 

Market prices of PRB coal based on 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content 

fluctuated between $12.35 per ton and $15.10 per ton during 2011, as reported by EIA. The December 30, 2011 price of 

$12.75 per ton compared to a price of $13.60 per ton and $9.25 per ton at December 31, 2010 and 2009, respectively, as 

reported by the EIA. The 2011 fluctuations in PRB coal prices were in line with normal market price volatility with the 

higher PRB prices reflecting the impact of the CSAPR before it was stayed. 

Midwest Generation contracts with rail carriers to transport coal to its facilities. In anticipation of the expiration on 

December 31, 2011 of its existing rail transportation contracts, during the fourth quarter of 2011, Midwest Generation entered 

into new multi-year transportation contracts with Union Pacific Railroad and two short-haul carriers for a specified minimum 

and maximum amount of tons effective January 1, 2012. The estimated minimum annual costs of transportation of coal under 

these contracts, based on tonnage commitments, are $386 million during 2012, $326 million in 2013, and $333 million in 

2014. However, all of the contracts have provisions that address the financial exposure of Midwest Generation related to a 

plant closure under certain circumstances as specified in the agreements. The contracts provide for quarterly and annual cost 

adjustments based on a number of factors that may increase the minimum payments. 

EMG believes Midwest Generation is fully contracted in 2012 based on its anticipated coal requirements for Midwest 

Generation. Based on Homer City's anticipated coal requirements in excess of the amount under contract, Homer City 

expects that a 10% change in the price of coal at December 31, 2011 would increase or decrease 2012 pre-tax income by 

approximately $4 million. 

Emission Allowances Price Risk

If CSAPR becomes effective as issued, the amount of SO2 that a plant emits in its operation will need to be matched by a 

sufficient amount of SO2 allowances designated under this program (CSAPR SO2 allowances) that are either allocated to the 
73

plant under the CSAPR program or purchased in the open market. SO2 allowances under the federal Acid Rain Program 

cannot be used to satisfy the requirements under CSAPR. For additional information on CSAPR, see "Item 8. Edison 

International Notes to Consolidated Financial Statements—Note 10. Environmental Developments—Cross-State Air 

Pollution Rule."

Credit Risk

For further information related to credit risk and how EMG manages credit risk, see "Item 8. Edison International Notes to 

Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."

The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net 

receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EMG's subsidiaries

enter into master agreements and other arrangements in conducting such activities which typically provide for a right of 

setoff in the event of bankruptcy or default by the counterparty. At December 31, 2011, the balance sheet exposure as 

described above, by the credit ratings of EMG's counterparties, was as follows:

(in millions)

Credit Rating1

A or higher

ABBB+

BBB

BBBBelow investment grade

Total

December 31, 2011

Exposure2

$ 99

3

4

—

13

51

$ 170

Collateral

$ (2)

—

—

—

—

(50)

$ (52)

Net

Exposure

$ 97

3

4

—

13

1

$ 118

1

 EMG 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 purchase and sales and non-derivative 

contractual commitments that are not recorded on the consolidated balance sheet, except for any related 

accounts receivable.

The credit risk exposure set forth in the above table is composed of $82 million of net accounts receivable and payables and 

$88 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the 

related counterparties. Credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set

forth in the above table, EMG's subsidiaries have posted a $41 million cash margin in the aggregate with PJM, NYISO, 

MISO, clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these 

activities also exposes EMG to credit risk of the related entities.

The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or 

transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 69% of EMG's 

consolidated operating revenues in 2011. At December 31, 2011, EMG's account receivable due from PJM was $62 million.

EMG's wind turbine supply agreements contain significant suppliers' obligations related to the manufacturing and delivery of 

turbines, and payments, for delays in delivery and for failure to meet performance obligations and warranty agreements. 

EMG's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the 

turbine manufacturer. A material adverse development with respect to EMG's turbine suppliers may have a material impact on 

EMG's wind projects and development efforts.
74

Interest Rate Risk

Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power 

projects. EMG mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing

with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. A 10% 

change in market interest rates at December 31, 2011 would increase or decrease the fair value of the interest rate swap 

agreements by approximately $21 million. The fair market values of fixed interest rate obligations are subject to interest rate

risk. The fair market value of EMG's consolidated long-term debt (including current portion) was $3.7 billion at 

December 31, 2011, compared to the carrying value of $4.9 billion. A 10% increase in market interest rates at December 31, 

2011 would result in a decrease in the fair value of total long-term debt by approximately $155 million. A 10% decrease in 

market interest rates at December 31, 2011 would result in an increase in the fair value of total long-term debt by 

approximately $172 million.
75

EDISON INTERNATIONAL PARENT AND OTHER

RESULTS OF OPERATIONS

Results of operations for Edison International Parent and Other includes amounts from other Edison International subsidiaries 

that are not significant as a reportable segment, as well as intercompany eliminations.

Edison International Parent and Other earnings (loss) from continuing operations were $(33) million, $(8) million and 

$18 million for 2011, 2010 and 2009, respectively. Income tax benefits in 2011 included a cumulative deferred tax adjustment 

related to employee benefits and a consolidated tax expense (benefit) of $7 million, $(25) million and $(42) million in 2011, 

2010 and 2009 respectively, representing differences in the allocation of state income taxes to subsidiaries under tax 

allocation agreements.

LIQUIDITY AND CAPITAL RESOURCES

Edison International Parent liquidity and its ability to pay operating expenses and dividends to common shareholders is 

dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and 

access to bank and capital markets.

At December 31, 2011, Edison International (parent) had approximately $28 million of cash and equivalents on hand. Edison 

International (parent) has a $1.4 billion revolving credit facility with various banks that terminates in February 2013. The 

following table summarizes the status of the Edison International (parent) credit facility at December 31, 2011:

(in millions)

Commitment

Outstanding borrowings

Outstanding letters of credit

Amount available

Edison

International

(parent)

$ 1,426

(10)

—

$ 1,416

Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of 

less than or equal to 0.65 to 1. At December 31, 2011, Edison International's consolidated debt to total capitalization ratio was 

0.56 to 1.

Historical Segment Cash Flows

The table below sets forth condensed historical cash flow information for Edison International Parent and Other.

(in millions)

Net cash used by operating activities

Net cash provided (used) by financing activities

Net cash provided (used) by investing activities

Net increase (decrease) in cash and cash equivalents

2011

$ (13)

30

1

$ 18

2010

$ (218)

214

11

$ 7

2009

$ (32)

(273)

(2)

$ (307)

Net Cash Used by Operating Activities

Net cash used by operating activities primarily relate to interest, operating costs and income taxes of Edison International 

(parent). During 2010, Edison International received $134 million in state tax refunds related to Global Settlement and made 

tax-allocation payments to SCE of $295 million, resulting in a use of operating cash flows. Edison International funded a 

portion of the 2010 tax-allocation payments due by Edison Capital in consideration for repayment of intercompany loans.

See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes" for further discussion 

of the Global Settlement.

Net Cash Provided (Used) by Financing Activities

Financing activities for 2011 were as follows:

• Paid $417 million of dividends to Edison International common shareholders.
76

• Received $461 million of dividend payments from SCE.

Financing activities for 2010 were as follows:

• Issued $400 million of senior notes due in 2017. The proceeds from these bonds were used to repay short-term 

borrowings under the revolving credit facility and the remainder for corporate liquidity purposes.

• Paid $411 million of dividends to Edison International common shareholders.

• Received $300 million of dividend payments from SCE.

• Repaid a net $66 million of short-term debt.

Financing activities for 2009 were as follows:

• Paid $404 million of dividends to Edison International common shareholders.

• Repaid a net $165 million of short-term debt, primarily due to the improvement in economic conditions that occurred 

during the second half of 2008.

• Received $300 million of dividend payments from SCE.

Contractual Obligations

As of December 31, 2011, Edison International Parent and Other had outstanding debt of $400 million which matures in 

2017. Interest in the amount of $15 million is payable annually in years 2012 through 2016 and $10.3 million is due in 2017.

MARKET RISK EXPOSURES

Interest Rate Risk

At December 31, 2011, the fair market value of Edison International Parent and Other's long-term debt (including current 

portion of long-term debt) was $416 million, compared to a carrying value of $399 million. A 10% increase in market interest 

rates would have resulted in a $6 million decrease in the fair market value of the long-term debt. A 10% decrease in market 

interest rates would have resulted in a $6 million increase in the fair market value of the long-term debt.
77

EDISON INTERNATIONAL (CONSOLIDATED)

LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations

Edison International's contractual obligations as of December 31, 2011, for the years 2012 through 2016 and thereafter are 

estimated below.

(in millions)

Long-term debt maturities and interest1

Power purchase agreements2

Renewable energy contracts

Qualifying facility contracts

Other power purchase agreements

Power plant and other operating lease 

obligations3

Purchase obligations:4

Nuclear fuel supply contract payments

Other fuel supply contract payments

Coal transportation agreements5

Gas transportation agreements

Capital expenditures

Other contractual obligations6

Employee benefit plans contributions7

Total8,9

Total

$ 23,949

16,578

3,677

6,298

3,492

1,068

1,053

3,023

46

305

500

1,677

$ 61,666

Less than

1 year

$ 812

561

439

624

410

190

479

386

7

286

114

352

$ 4,660

1 to 3 years

$ 3,652

1,328

875

1,640

772

213

445

659

14

19

116

694

$ 10,427

3 to 5 years

$ 2,564

1,503

794

1,181

429

206

129

630

15

56

631

$ 8,138

More than

5 years

$ 16,921

13,186

1,569

2,853

1,881

459

—

1,348

10

214

—

$ 38,441

1 For additional details, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 5. Debt and 

Credit Agreements." Amount includes interest payments totaling $10.2 billion over applicable period of the debt.

2 Certain power purchase agreements entered into with independent power producers are treated as operating or capital 

leases. At December 31, 2011, minimum operating lease payments for power purchase agreements were $839 million in 

2012, $966 million in 2013, $930 million in 2014, $916 million in 2015, $815 million in 2016, and $11.5 billion for the 

thereafter period. At December 31, 2011, minimum capital lease payments for power purchase agreements were 

$33 million in 2012, $33 million 2013, $72 million for 2014, $109 million for 2015, $109 million for 2016, and 

$1.8 billion for the thereafter period (amounts include executory costs and interest of $445 million and $773 million, 

respectively). For further discussion, see "Item 8. Edison International Notes to Consolidated Financial Statements—

Note 9. Commitments and Contingencies."

3 At December 31, 2011, minimum operating lease payments were primarily related to long-term leases for the Powerton 

and Joliet stations and Homer City facilities and vehicles, office space and other equipment. For further discussion, see 

"Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

4 For additional details, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. 

Commitments and Contingencies."

5 Years subsequent to 2012 represent contracts for minimum volumes without regard to payment of alternative liquidated 

damages or plant closures.

6 For additional details, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. 

Commitments and Contingencies." In addition, at December 31, 2011, other commitments also related to maintaining 

reliability and expanding SCE's transmission and distribution system. 

7 Amount includes estimated contributions to the pension and PBOP plans for Edison International through 2016. The 

estimated contributions are not available beyond 2016. These amounts represent estimates that are based on assumptions 

that are subject to change. In addition, funding of future contributions for SCE could be impacted by the final 2012 GRC 

decision. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 8. Compensation and 

Benefit Plans" for further information.
78

8 At December 31, 2011, Edison International had a total net liability recorded for uncertain tax positions of $479 million, 

which is excluded from the table. Edison International 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.

9 The contractual obligations table does not include derivative obligations and asset retirement obligations, which are 

discussed in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 6. Derivative Instruments 

and Hedging Activities," and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. 

Property, Plant and Equipment," respectively.

Critical Accounting Estimates and Policies

The accounting policies described below are considered critical to obtaining an understanding of Edison International'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, that 

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 "Item 8. Edison International 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 

a 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.

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 in California, 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 in California and is subject to change in the future.

Effect if Different Assumption 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, 2011, the consolidated balance sheets included 

regulatory assets of $6.0 billion and regulatory liabilities of $5.3 billion. If different judgments were reached on recovery of 

costs and timing of income recognition, SCE's earnings may vary from the amounts reported.

Impairment of Long-Lived Assets

Nature of Estimates Required. Long-lived assets, including intangible assets, are evaluated for impairment in accordance 

with applicable authoritative guidance. Authoritative guidance requires that if the undiscounted expected future cash flow 

from a company's assets or group of assets (without interest charges) is less than its carrying value, asset impairment must be 

recognized on the financial statements. The impairment charges, if applicable, are calculated as the excess of the asset's 

carrying value over its fair value, which represents the discounted expected future cash flows attributable to the asset or, in

the case of assets expected to be sold, at fair value less costs to sell. Long-lived assets are evaluated for impairment whenever 

indicators exist or when there is a commitment to sell or dispose of the asset. These evaluations may result from significant 

decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used

in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of 

an asset, as well as economic or operational analyses.

Key Assumptions and Approach Used. The assessment of impairment requires significant management judgment to 

determine: (1) if an indicator of impairment has occurred, (2) how assets should be grouped, (3) the forecast of undiscounted 

expected future cash flow over the asset's estimated useful life to determine if an impairment exists, and (4) if an impairment
79

exists, the fair value of the asset or asset group. Factors that are considered important, which could trigger an impairment, 

include operating losses from a project, projected future operating losses, the financial condition of counterparties, or 

significant negative industry or economic trends. The determination of fair value requires management to apply judgment in: 

(1) estimating future prices of energy and capacity in wholesale energy markets and fuel prices that are susceptible to 

significant change, (2) environmental and maintenance expenditures, and (3) the time period due to the length of the 

estimated remaining useful lives.

In preparing long-term cash forecasts, EMG includes assumptions about future prices for electricity, capacity, fuel and related

products and services, as applicable, future operations and maintenance costs and future capital expenditure requirements 

under different scenarios. As appropriate, EME uses a probability weighted approach when determining whether impairment 

indicators exist. Assumptions included in the long-term cash flow forecasts for merchant projects include:

• Observable market prices for electricity, fuel and related products and services to the extent available and long-term 

prices developed based on a fundamental price model;

• Long-term capacity prices based on the assumption that capacity markets would continue consistent with their current 

structure, with expected increases in revenues as a result of declines in reserve margins beyond the price of the latest 

auctions;

• Trends for additions and retirements for generation resources; and

• Plans for compliance with both existing and possible future environmental regulations.

EMG includes allocated acquired emission allowances as part of each power plant asset group. In the case of the Powerton 

and Joliet Stations and Homer City, EMG also includes prepaid rent in the respective asset group. EMG's unit of account is at 

the plant level and, accordingly, the closure of a unit at a multi-unit site would not result in an impairment of property, plant 

and equipment unless such condition were to affect an impairment assessment on the entire plant.

Effect if Different Assumptions Used. The estimates and assumptions used to determine whether an impairment exists are 

subject to a high degree of uncertainty. The estimated fair value of an asset would change materially if different estimates and 

assumptions were used to determine the amounts or timing of future revenues, environmental compliance costs or operating 

expenditures.

Application to EMG's Homer City Plant

As described in "Management Overview of EMG," Homer City failed to obtain sufficient interest from market participants to 

fund the capital improvements during the process undertaken in the fourth quarter of 2011, and Homer City is currently 

engaged in discussions with the owner-lessors regarding the potential for such funding. EMG expects that the outcome of any 

such discussions, if successful in providing funding for the Homer City plant, will likely result in EMG's loss of substantially 

all beneficial economic interest in and material control of the Homer City plant. Failure to resolve the source of funding of 

necessary capital expenditures for the Homer City plant could result in Homer City's default under the lease agreements 

giving rise to remedies for the owner-lessors and secured lease obligation bondholders, which could include foreclosing on 

the leased assets, the general partner of Homer City, or both. In connection with the preparation of its year end financial 

statements, EMG concluded that these events combined with the current and projected financial condition of Homer City 

were indicators of impairment. The long-lived asset group subject to the impairment evaluation was determined to include the 

Homer City lease, leasehold improvements and prepaid rent. In assessing impairment, EMG concluded that the future 

undiscounted cash flows through the period in which EMG expects to continue to have significant economic interest and 

control of the Homer City plant were insufficient to recover the carrying amount of the asset group. To measure the amount 

of impairment loss, the market and income approaches were considered the most appropriate and resulted in a zero fair value. 

EMG viewed the lack of interest from market participants to provide sufficient funding for the capital improvements as 

indicative that the fair value of the asset group is zero. Furthermore, discounted cash flow analysis based on estimates of 

future energy, capacity and coal prices, operations and maintenance costs and operating lease payments along with the 

estimated costs of constructing the environmental control equipment also indicated a fair value of zero. Accordingly, EMG 

recorded an impairment charge of $1.03 billion for the fourth quarter of 2011.

Application to EMG's Midwest Generation Stations

A significant decline in power prices from September 30, 2011, combined with new environmental regulations and public 

policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants. In 

connection with the preparation of its year end financial statements, EMG concluded, based on the current energy price 

environment, it is less likely that Midwest Generation will install environmental controls required by the CPS at its Fisk, 
80

Crawford and Waukegan Stations; and such assessment was an indicator that these stations were impaired. Management 

updated the probability weighted future undiscounted cash flows expected to be received at these stations and concluded that 

such amounts did not recover the respective station's carrying amounts. As part of these alternative cash flow scenarios, 

management considered a shortened estimated useful life of each station if environmental improvements were not made and a 

forecasted reduction in generation from lower forward power prices. In February 2012, Midwest Generation decided to shut 

down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014.

To measure the amount of the impairment loss, the income approach was considered the most relevant, but market data 

obtained prior to the significant decline in power prices was used to corroborate the income approach. The discounted cash 

flow analysis assumptions that have the most significant impact on fair value are forecasted energy and capacity prices. The 

discounted cash flow analysis indicated a fair value of zero. EMG also concluded it was unlikely that a third party would 

consummate the purchase of the Fisk, Crawford or Waukegan Stations in the current economic and regulatory environment 

resulting in a determination that the fair value of each of these stations is zero. This resulted in an impairment charge of 

$115 million, $186 million and $339 million for Fisk, Crawford and Waukegan Stations, respectively. Environmental and 

other remediation or ongoing maintenance costs are expected to be offset by the salvage value of the asset groups. 

The following table summarizes the net book value of the merchant coal-fired asset groups at December 31, 2011:

(in millions)

Joliet Station

Powerton Station

Will County Station

$ 732

757

523

Application to Selected EMG Wind Projects

In connection with the preparation of its year end financial statements, management has reviewed the Storm Lake project and 

four small wind projects in Minnesota for impairment in the fourth quarter of 2011 based on an expected future increase in 

operating costs and declines in long-term power prices that the projects could potentially realize following the term of the 

power purchase agreements. The probability weighted future undiscounted cash flows of each project are not expected to be 

sufficient to recover the respective carrying value of each of these long-lived assets ($53 million in aggregate). The income 

approach was utilized to determine fair value for these asset groups. The most significant assumptions used in determining 

fair value were discount rates, future wind generation, the future availability of the project to generate energy and future plant 

operations expense. The asset groups at each project consisted of property, plant and equipment and, where appropriate, 

deferred revenue. In aggregate, the fair value of these five asset groups was determined to be $23 million, resulting in an 

impairment charge of $30 million.

EMG's Merchant Wind Projects

In light of the decline in forecasted power prices since September 30, 2011, EMG reviewed the long-term cash forecasts for 

the merchant wind projects in a manner consistent with the Key Assumptions and Approach Used described above. The 

expected future undiscounted cash flows of these projects recovered the carrying amount of these asset groups and, 

accordingly, no impairments were recorded. The expected future cash flows for these merchant wind projects are dependent 

upon a number of assumptions, the most significant of which are expected future power prices and operating costs. A decline 

in the forecasted cash flows in future periods could result in impairment, requiring a write-down of the carrying amount to 

fair value. The carrying values of the Goat Wind, Big Sky and Lookout asset groups at December 31, 2011 were 

$200 million, $344 million and $64 million, respectively.

Derivatives

Nature of Estimates Required. As described in "Item 8. Edison International Notes to Consolidated Financial Statements—

Note 6. Derivative Instruments and Hedging Activities," SCE and EMG use derivative instruments to manage exposure to 

changes in electricity and fuel prices and interest rates. Derivative instruments are recorded at fair value unless certain 

exceptions are met in which case the derivative is recorded on an accrual basis.

SCE records derivative instruments that do not meet the normal purchases and sales exception at fair value with an offsetting 

regulatory asset or liability due to application of principles for rate-regulated enterprises. As a result, changes in fair value of 

SCE derivative instruments have no impact on earnings, but may temporarily affect cash flows. SCE has not elected to use 

hedge accounting for these transactions due to the regulatory accounting treatment.

EMG records derivative instruments that do not meet the normal purchases and sales exception at fair value, with changes in 
81

the derivative's fair value recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives

that qualify for cash flow hedge accounting treatment, the effective portion of the changes in the derivative's fair value is 

recognized in other comprehensive income until the hedged item is recognized in earnings. EMG records derivative 

instruments used for trading at fair value with changes in fair value recognized in income.

Management's judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether 

the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. 

Management's judgment is also required to determine the fair value of derivative transactions.

Key Assumptions and Approach Used. SCE and EMG determine the fair value of derivative instruments based on forward 

market prices in active markets adjusted for nonperformance risk. If quoted market prices are not available, internally 

developed models are used to determine the fair value. When actual market prices, or relevant observable inputs are not 

available, it is appropriate to use unobservable inputs which reflect management assumptions, including extrapolating limited 

short-term observable data and developing correlations between liquid and non-liquid trading hubs. In assessing 

nonperformance risks, SCE and EMG review credit ratings of counterparties (and related default rates based on such credit 

ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a

counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not 

directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of 

nonperformance.

In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. 

For further information, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value 

Measurements."

Effect if Different Assumptions Used. As described above, fair value is determined using a combination of market 

information or observable data and unobservable inputs which reflect management's assumptions. Changes in observable data 

would impact results. In addition, unobservable inputs could have an impact on results. Fair value for Level 3 derivatives is 

derived using observable and unobservable inputs. As of December 31, 2011, the net fair value of EMG's Level 3 derivatives 

was an asset of $83 million. While it is difficult to determine the impact of a change in any one input, if the fair value of 

EMG's Level 3 derivatives were increased or decreased by 10%, the impact would be a $21 million increase or decrease to 

operating revenues. For EMG's derivative instruments that are measured at fair value using quantitative pricing models, a 

significant change in estimate could affect EMG's results of operations. As of December 31, 2011, the net fair value of SCE's 

Level 3 derivatives was a liability of $754 million. SCE recovers its hedging related costs through the energy resource 

recovery account ("ERRA") balancing account, and as a result, exposure to commodity price risk is not expected to impact 

earnings, but may impact cash flows. For further sensitivities in Edison International's assumptions used to calculate fair 

value, see "EMG: Results of Operations—Fair Value Disclosures" and "SCE: Market Risk Exposures—Fair Value of 

Derivative Instruments." For further information on derivative instruments, see "Item 8. Edison International Notes to 

Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."

Nuclear Decommissioning–ARO

Nature of Estimate Required. Regulations by the NRC require SCE to decommission its nuclear power plants which is 

expected to begin after the plants' operating licenses expire. In accordance with authoritative guidance, SCE is required to 

record an obligation to decommission its nuclear facilities. Nuclear decommissioning costs are recovered in utility rates 

through contributions that are reviewed every three years by the CPUC. Due to regulatory accounting treatment, nuclear 

decommissioning activities are not expected to affect SCE earnings.

Key Assumptions and Approach Used. The liability to decommission SCE's nuclear power facilities is based on site-specific 

studies performed in 2008 and 2007 for San Onofre and Palo Verde, respectively, which estimate that SCE will spend 

approximately $8.6 billion through 2053 to decommission its active nuclear facilities. Decommissioning cost estimates are 

updated in each Nuclear Decommissioning Triennial Proceeding. The current estimate is based on the following assumptions 

from the 2008 and 2007 site-specific studies:

• Decommissioning Costs. The estimated costs for labor, dismantling and disposal costs, 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, 

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 1.8% to 6.9% (depending on the cost 

element) annually.
82

• Timing. Cost estimates are based on an assumption that decommissioning will commence promptly after the NRC 

operating licenses expire. The operating licenses currently expire in 2022 for San Onofre Units 2 and 3. When the sitespecific study was completed, the licenses for the Palo Verde units were set to expire in 2025, 2026 and 2027. Effective 

April 2011, the licenses were extended to 2045, 2046 and 2047 for the Palo Verde units.

• Spent Fuel Dry Storage Costs. Cost estimates are based on an assumption that the DOE will begin to take spent fuel in 

2015, and will remove the last spent fuel from the San Onofre and Palo Verde sites by 2051 and 2053, respectively. Costs 

for spent fuel monitoring are included until 2051 and 2053, 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 active nuclear facilities was $2.5 billion and 

$2.4 billion at December 31, 2011 and 2010, respectively. 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 and related regulatory

asset. The following table illustrates the increase to the ARO and regulatory asset if the escalation rate was adjusted while 

leaving all other assumptions constant:

(in millions)

Uniform increase in escalation rate of 25 basis points

Increase to ARO and

regulatory asset at

December 31, 2011

$ 146

Pensions and Postretirement Benefits Other than Pensions

Nature of Estimate Required. Authoritative accounting guidance requires companies to recognize the overfunded or 

underfunded status of defined benefit pension and other postretirement plans as assets and liabilities in the balance sheet; the 

assets and/or liabilities are normally offset through other comprehensive income (loss). In accordance with authoritative 

guidance for rate-regulated enterprises, regulatory assets and liabilities are recorded instead of charges and credits to other

comprehensive income (loss) for its postretirement benefit plans that are recoverable in utility rates. Edison International has 

a fiscal year-end measurement date for all of its postretirement plans.

Key Assumptions of Approach Used. Pension and other postretirement obligations and the related effects on results of 

operations are calculated using actuarial models. Two critical assumptions, discount rate and expected return on assets, are 

important elements of plan expense and 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 retirement, mortality and turnover, are evaluated periodically and 

updated to reflect actual experience.

As of December 31, 2011, Edison International's pension plans had a $4.5 billion benefit obligation and total expense for 

these plans was $144 million for 2011. As of December 31, 2011, Edison International's PBOP plans had a $2.6 billion 

benefit obligation and total expense for these plans was $44 million for 2011. 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.
83

The following are critical assumptions used to determine expense for pension and other postretirement benefit for 2011:

(in millions)

Discount rate1

Expected long-term return on plan assets2

Assumed health care cost trend rates3

Pension

Plans

5.25%

7.5%

—

Postretirement

Benefits Other

than Pensions

5.5%

7.0%

9.75%

1 The discount rate enables Edison International to state expected future cash flows at a present value on 

the measurement date. Edison International selects 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. Two corporate yield curves were considered, Citigroup and AONHewitt.

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 7.5% 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 2.2%, 2.0% 

and 5.9% for the one-year, five-year and ten-year periods ended December 31, 2011, respectively. Actual 

time-weighted, annualized returns on the PBOP plan assets were 1.2%, 0.8%, and 4.2% over these same 

periods. Accounting principles provide that differences between expected and actual returns are 

recognized over the average future service of employees.

3 The health care cost trend rate gradually declines to 5.5% for 2019 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 will, over time, be recovered from or returned to customers. As of December 31, 2011, this cumulative 

difference amounted to a regulatory asset of $105 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, 2011, Edison International had unrecognized pension costs of $1.1 billion and unrecognized PBOP costs 

of $749 million which 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, $989 million of pension costs and $714 million of PBOP costs are recorded as regulatory assets, an offset to the 

underfunded liabilities of these plans, and will be amortized to expense over the average expected future service of 

employees.

Edison International'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 and competitive power 

generation PBOP 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. Earnings could be impacted if the CPUC eliminates or modifies the current approved 

SCE regulatory recovery mechanism. 

The following table summarizes the increase or (decrease) to the projected benefit obligation for pension and the accumulated 

benefit obligation for PBOP if the discount rate were changed while leaving all other assumptions constant:

(in millions)

Change to projected benefit obligation for pension

Change to accumulated benefit obligation for PBOP

Increase in

discount rate

by 1%

$ (402)

(339)

Decrease in

discount rate

by 1%

$ 435

394
84

A one percentage point increase in the expected rate of return on pension plan assets would decrease current year expense by 

$32 million and a one percentage point increase in the expected rate of return on PBOP plan assets would decrease current 

year expense by $16 million.

The following table summarizes the increase or (decrease) to the 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: 

(in millions)

Change to accumulated benefit obligation for PBOP

Change to annual aggregate service and interest costs

Increase in

health care

cost trend rate

by 1%

$ 297

16

Decrease in

health care

cost trend rate

by 1%

$ (247)

(13)

Income Taxes

Nature of Estimates Required. As part of the process of preparing its consolidated financial statements, Edison International 

is required to estimate its income taxes for each jurisdiction in which it operates. 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's consolidated balance sheets.

Edison International takes certain tax positions it believes are applied 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 

determines its uncertain tax positions in accordance with the authoritative guidance.

Key Assumptions and Approach Used. Accounting for tax obligations requires management judgment. Management uses 

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 its uncertain tax 

positions Edison International considers, 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. 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 continues 

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. A tax liability has been recorded 

with respect to tax positions in which the outcome is uncertain and the effect is estimable. 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. See "Item 8. Edison 

International Notes to Consolidated Financial Statements—Note 7. Income Taxes" for a further discussion on income taxes.

Accounting for Contingencies, Guarantees and Indemnities

Nature of Estimates Required. Edison International records loss contingencies when it determines that the outcome of 

future events is probable of occurring and when the amount of the loss can be reasonably estimated. When a guarantee or 

indemnification subject to authoritative guidance is entered into, Edison International records a liability for the estimated fair 

value of the underlying guarantee or indemnification. 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 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 provides disclosures for material contingencies when there is a 

reasonable possibility that a loss or an additional loss may be incurred. Some guarantees and indemnifications could have a 
85

significant financial impact under certain circumstances, and management also considers the probability of such 

circumstances occurring when estimating the fair value.

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. In addition, for guarantees and indemnities actual results may differ from the amounts 

recorded and disclosed and could have a significant impact on Edison International's consolidated financial statements. For a 

discussion of contingencies, guarantees and indemnities, see "Item 8. Edison International Notes to Consolidated Financial 

Statements—Note 9. Commitments and Contingencies."

NEW ACCOUNTING GUIDANCE

New accounting guidance is discussed in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 1. 

Summary of Significant Accounting Policies—New Accounting Guidance."

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A is included in the MD&A under the headings "SCE: Market Risk Exposures" and "EMG: 

Market Risk Exposures."

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONSOLIDATED FINANCIAL STATEMENTS
(This page has been left blank intentionally.)

86
87

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and 

Shareholders of Edison International

In our opinion, the consolidated balance sheets and related consolidated statements of income, comprehensive income, cash 

flows and changes in equity present fairly, in all material respects, the financial position of Edison International (the 

"Company") and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for 

each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in 

the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing 

under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the 

related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective 

internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - 

Integrated Framework 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.

As discussed in Note 3 to the consolidated financial statements, the Company changed the manner in which it accounts for 

variable interest entities as of January 1, 2010.

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 29, 2012
The accompanying notes are an integral part of these consolidated financial statements.

88

Consolidated Statements of Income

(in millions, except per-share amounts)

Electric utility

Competitive power generation

Total operating revenue

Fuel

Purchased power

Operations and maintenance

Depreciation, decommissioning and amortization

Asset impairments, lease terminations and other

Total operating expenses

Operating income

Interest and dividend income

Equity in income from unconsolidated affiliates – net

Other income

Interest expense

Other expenses

Income (loss) from continuing operations before income taxes

Income tax expense (benefit)

Income from continuing operations

Income (loss) from discontinued operations, net of tax

Net income

Dividends on preferred and preference stock of utility

Other noncontrolling interests

Net income (loss) attributable to Edison International common

shareholders

Amounts attributable to Edison International common shareholders:

Income (loss) from continuing operations, net of tax

Income (loss) from discontinued operations, net of tax

Net income (loss) attributable to Edison International common

shareholders

Basic earnings (loss) per common share attributable to Edison

International common shareholders:

Weighted-average shares of common stock outstanding

Continuing operations

Discontinued operations

Total

Diluted earnings (loss) per common share attributable to Edison

International common shareholders:

Weighted-average shares of common stock outstanding, including effect of

dilutive securities

Continuing operations

Discontinued operations

Total

Dividends declared per common share

Edison International

Years ended December 31,

2011

$ 10,574

2,186

12,760

1,166

2,989

4,776

1,737

1,772

12,440

320

37

86

156

(808)

(55)

(264)

(288)

24

(3)

21

59

(1)

$ (37)

$ (34)

(3)

$ (37)

326

$ (0.10)

(0.01)

$ (0.11)

326

$ (0.10)

(0.01)

$ (0.11)

$ 1.285

2010

$ 9,980

2,429

12,409

1,172

2,930

4,612

1,522

47

10,283

2,126

31

106

148

(703)

(51)

1,657

354

1,303

4

1,307

52

(1)

$ 1,256

$ 1,252

4

$ 1,256

326

$ 3.83

0.01

$ 3.84

329

$ 3.81

0.01

$ 3.82

$ 1.265

2009

$ 9,962

2,399

12,361

1,517

2,751

4,387

1,418

890

10,963

1,398

32

42

171

(732)

(57)

854

(98)

952

(7)

945

51

45

$ 849

$ 856

(7)

$ 849

326

$ 2.61

(0.02)

$ 2.59

327

$ 2.60

(0.02)

$ 2.58

$ 1.245
The accompanying notes are an integral part of these consolidated financial statements.

89

Consolidated Statements of Comprehensive Income

(in millions)

Net income

Other comprehensive income (loss), net of tax:

Foreign currency translation adjustments – net

Pension and postretirement benefits other than pensions:

Net loss arising during the period, net of income tax benefit of $14, $22

and $3 for 2011, 2010 and 2009, respectively

Amortization of net loss included in net income, net of income tax

expense of $5, $4 and $8 for 2011, 2010 and 2009, respectively

Prior service credit arising during the period, net of income tax expense

of $4 for 2010

Amortization of prior service credit, net of income tax expense

Unrealized gain (loss) on derivatives qualified as cash flow hedges:

Unrealized holding gain (loss) arising during the period, net of income

tax expense (benefit) of $(7), $37 and $36 for 2011, 2010 and 2009,

respectively

Reclassification adjustments included in net income, net of income tax

benefit of $25, $96 and $124 for 2011, 2010 and 2009, respectively

Other comprehensive loss

Comprehensive income (loss)

Less: Comprehensive income attributable to noncontrolling interests

Comprehensive income (loss) attributable to Edison International

Edison International

Years ended December 31,

2011

$ 21

—

(21)

8

—

—

(12)

(38)

(63)

(42)

58

$ (100)

2010

$ 1,307

—

(23)

6

(6)

(1)

55

(144)

(113)

1,194

51

$ 1,143

2009

$ 945

4

(13)

13

—

1

43

(178)

(130)

815

96

$ 719
The accompanying notes are an integral part of these consolidated financial statements.

90

Consolidated Balance Sheets

(in millions)

ASSETS

Cash and cash equivalents

Receivables, less allowances of $75 and $85 for uncollectible accounts at respective dates

Accrued unbilled revenue

Inventory

Prepaid taxes

Derivative assets

Restricted cash and cash equivalents

Margin and collateral deposits

Regulatory assets

Other current assets

Total current assets

Nuclear decommissioning trusts

Investments in unconsolidated affiliates

Other investments

Total investments

Utility property, plant and equipment, less accumulated depreciation of $6,894

and $6,319 at respective dates

Competitive power generation and other property, plant and equipment, less accumulated

depreciation of $1,408 and $1,865 at respective dates

Total property, plant and equipment

Derivative assets

Restricted deposits

Rent payments in excess of levelized rent expense under plant operating leases

Regulatory assets

Other long-term assets

Total long-term assets

Total assets

Edison International

December 31,

2011

$ 1,469

908

519

624

88

106

103

58

494

115

4,484

3,592

525

211

4,328

27,569

4,547

32,116

128

51

760

5,466

706

7,111

$ 48,039

2010

$ 1,389

931

442

568

390

133

2

65

378

124

4,422

3,480

559

223

4,262

24,778

5,406

30,184

437

47

1,187

4,347

644

6,662

$ 45,530
The accompanying notes are an integral part of these consolidated financial statements.

91

Consolidated Balance Sheets

(in millions, except share amounts)

LIABILITIES AND EQUITY

Short-term debt

Current portion of long-term debt

Accounts payable

Accrued taxes

Accrued interest

Customer deposits

Derivative liabilities

Regulatory liabilities

Other current liabilities

Total current liabilities

Long-term debt

Deferred income taxes

Deferred investment tax credits

Customer advances

Derivative liabilities

Pensions and benefits

Asset retirement obligations

Regulatory liabilities

Other deferred credits and other long-term liabilities

Total deferred credits and other liabilities

Total liabilities

Commitments and contingencies (Note 9)

Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued

and outstanding at each date)

Accumulated other comprehensive loss

Retained earnings

Total Edison International's common shareholders' equity

Preferred and preference stock of utility

Other noncontrolling interests

Total noncontrolling interests

Total equity

Total liabilities and equity

Edison International

December 31,

2011

$ 429

57

1,419

52

205

199

268

670

1,049

4,348

13,689

5,396

89

138

547

2,912

2,688

4,670

2,476

18,916

36,953

2,360

(139)

7,834

10,055

1,029

2

1,031

11,086

$ 48,039

2010

$ 115

48

1,362

52

205

217

217

738

998

3,952

12,371

5,625

122

112

468

2,260

2,561

4,524

2,041

17,713

34,036

2,331

(76)

8,328

10,583

907

4

911

11,494

$ 45,530
The accompanying notes are an integral part of these consolidated financial statements.

92

Consolidated Statements of Cash Flows

(in millions)

Cash flows from operating activities:

Net income

Less: Income (loss) from discontinued operations

Income from continuing operations

Adjustments to reconcile to net cash provided by operating activities:

Depreciation, decommissioning and amortization

Regulatory impacts of net nuclear decommissioning trust earnings

Other amortization

Asset impairments, lease terminations and other

Stock-based compensation

Equity in income from unconsolidated affiliates

Distributions from unconsolidated affiliates

Deferred income taxes and investment tax credits

Income from leveraged leases

Proceeds from U.S. treasury grants

Changes in operating assets and liabilities:

Receivables

Inventory

Margin and collateral deposits – net of collateral received

Prepaid taxes

Other current assets

Rent payments in excess of levelized rent expense

Accounts payable

Accrued taxes

Other current liabilities

Derivative assets and liabilities – net

Regulatory assets and liabilities – net

Other assets

Other liabilities

Operating cash flows from discontinued operations

Net cash provided by operating activities

Cash flows from financing activities:

Long-term debt issued

Long-term debt issuance costs

Long-term debt repaid

Bonds purchased

Preference stock issued – net

Short-term debt financing – net

Borrowing held in escrow pending completion of project construction

Settlements of stock-based compensation – net

Cash contributions from noncontrolling interests

Dividends and distributions to noncontrolling interests

Dividends paid

Net cash provided (used) by financing activities

Edison International

Years ended December 31,

2011

$ 21

(3)

24

1,737

146

152

1,759

30

(86)

82

(188)

(5)

388

19

(56)

25

302

(85)

(136)

56

—

(33)

383

(1,080)

(120)

595

(3)

3,906

1,376

(35)

(67)

(86)

123

389

(97)

(20)

—

(59)

(417)

$ 1,107

2010

$ 1,307

4

1,303

1,522

189

118

47

30

(106)

92

1,139

(5)

92

(155)

(49)

63

(357)

(24)

(149)

(3)

(135)

13

(44)

278

(71)

(315)

4

3,477

1,936

(38)

(396)

—

—

30

—

(16)

—

(52)

(411)

$ 1,053

2009

$ 945

(7)

952

1,418

158

120

888

22

(42)

31

(1,457)

(14)

—

80

20

30

178

(45)

(160)

152

(402)

31

(581)

1,457

62

154

(7)

3,045

939

(25)

(1,044)

(219)

—

(2,058)

—

(3)

2

(117)

(404)

$ (2,929)
The accompanying notes are an integral part of these consolidated financial statements.

93

Consolidated Statements of Cash Flows

(in millions)

Cash flows from investing activities:

Capital expenditures

Purchase of interest in acquired companies

Proceeds from termination of leases

Proceeds from sale of nuclear decommissioning trust investments

Purchases of nuclear decommissioning trust investments and other

Proceeds from partnerships and unconsolidated subsidiaries, net of investment

Investments in other assets

Effect of consolidation and deconsolidation of variable interest entities

Net cash used by investing activities

Net increase (decrease) in cash and cash equivalents

Cash and cash equivalents, beginning of year

Cash and cash equivalents, end of year

Edison International

Years ended December 31,

2011

$ (4,808)

(3)

—

2,773

(2,940)

41

4

—

(4,933)

80

1,389

$ 1,469

2010

$ (4,543)

(4)

—

1,432

(1,651)

44

(1)

(91)

(4,814)

(284)

1,673

$ 1,389

2009

$ (3,282)

(22)

1,420

2,217

(2,416)

11

(287)

—

(2,359)

(2,243)

3,916

$ 1,673
The accompanying notes are an integral part of these consolidated financial statements.

94

Consolidated Statements of Changes in Equity

(in millions)

Balance at December 31, 2008

Net income

Other comprehensive loss

Common stock dividends

declared ($1.245 per share)

Dividends, distributions to

noncontrolling interests and

other

Stock-based compensation – net

Noncash stock-based

compensation and other

Balance at December 31, 2009

Net income (loss)

Other comprehensive loss

Deconsolidation of variable

interest entities

Cumulative effect of a change in

accounting principle, net of

tax

Common stock dividends

declared ($1.265 per share)

Dividends, distributions to

noncontrolling interests and

other

Stock-based compensation – net

Noncash stock-based

compensation and other

Balance at December 31, 2010

Net income (loss)

Other comprehensive loss

Common stock dividends

declared ($1.285 per share)

Dividends, distributions to

noncontrolling interests and

other

Stock-based compensation and

other

Noncash stock-based

compensation and other

Purchase of noncontrolling

interests

Issuance of preference stock

Balance at December 31, 2011

Equity Attributable to Edison International

Common

Stock

$ 2,272

—

—

—

—

9

23

$ 2,304

—

—

—

—

—

—

8

19

$ 2,331

—

—

—

—

14

30

(15)

—

$ 2,360

Accumulated

Other

Comprehensive

Income (Loss)

$ 167

—

(130)

—

—

—

—

$ 37

—

(113)

—

—

—

—

—

—

$ (76)

—

(63)

—

—

—

—

—

—

$ (139)

Retained

Earnings

$ 7,078

849

—

(406)

—

(12)

(9)

$ 7,500

1,256

—

—

15

(412)

—

(24)

(7)

$ 8,328

(37)

—

(419)

—

(34)

(4)

—

—

$ 7,834

Subtotal

$ 9,517

849

(130)

(406)

—

(3)

14

$ 9,841

1,256

(113)

—

15

(412)

—

(16)

12

$ 10,583

(37)

(63)

(419)

—

(20)

26

(15)

—

$ 10,055

Noncontrolling

Interests

Other

$ 285

45

—

—

(72)

—

—

$ 258

(1)

—

(249)

—

—

(4)

—

—

$ 4

(1)

—

—

(1)

—

—

—

—

$ 2

Edison International

Preferred

and

Preference

Stock

$ 907

51

—

—

(51)

—

—

$ 907

52

—

—

—

—

(52)

—

—

$ 907

59

—

—

(59)

—

(1)

—

123

$ 1,029

Total

Equity

$ 10,709

945

(130)

(406)

(123)

(3)

14

$ 11,006

1,307

(113)

(249)

15

(412)

(56)

(16)

12

$ 11,494

21

(63)

(419)

(60)

(20)

25

(15)

123

$ 11,086
95

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

Edison International has two business segments for financial reporting purposes: an electric utility segment (SCE) and a 

competitive power generation segment (EMG). SCE is an investor-owned public utility primarily engaged in the business of 

supplying electricity to an approximately 50,000 square mile area of southern California. EMG is the holding company for its 

principal wholly owned subsidiary, EME. EME is a holding company with subsidiaries and affiliates engaged in the business 

of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production 

facilities. EME also engages in hedging and energy trading activities in competitive power markets through its Edison 

Mission Marketing & Trading, Inc. ("EMMT") subsidiary.

Basis of Presentation

The consolidated financial statements included Edison International and its wholly owned subsidiaries. Edison International 

consolidates subsidiaries in which it has a controlling interest and Variable Interest Entities ("VIEs") in which it is the 

primary beneficiary. In addition, Edison International generally uses the equity method to account for significant interests in

(1) partnerships and subsidiaries in which it owns a significant but less than controlling interest and (2) VIEs in which it is

not the primary beneficiary. Intercompany transactions have been eliminated, except EMG's profits from energy sales to SCE 

which are allowed in utility rates.

Edison International's accounting policies conform to accounting principles generally accepted in the United States of 

America, including the accounting principles for rate-regulated enterprises, which reflect the ratemaking policies of the 

California Public Utility Commission ("CPUC") and the Federal Energy Regulatory Commission ("FERC"). SCE applies 

authoritative guidance for rate-regulated enterprises to the portion of its operations in which regulators set rates at levels 

intended to recover the estimated costs of providing service, plus a return on capital. Regulators may also impose certain 

penalties or grant certain incentives. Due to timing and other differences in the collection of electric utility revenue, these

principles require an incurred cost that would otherwise be charged to expense by a nonregulated entity to be capitalized as a 

regulatory asset if it is probable that the cost is recoverable through future rates; and conversely the principles require 

recording of a regulatory liability for amounts collected in rates to recover costs expected to be incurred in the future or 

amounts collected in excess of costs incurred. SCE assesses, at the end of each reporting period, whether regulatory assets are 

probable of future recovery. See Note 14 for composition of regulatory assets and liabilities.

The preparation of financial statements in conformity with United States generally accepted accounting principles requires 

management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of 

contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses 

during the reported period. Actual results could differ from those estimates.

Cash Equivalents

Cash equivalents included investments in money market funds totaling $1.3 billion and $1.1 billion at December 31, 2011 

and 2010, respectively. Generally, the carrying value of cash equivalents equals the fair value, as these investments have 

maturities of three months or less.

Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for 

check clearing. Edison International reclassified $220 million and $197 million of checks issued, but not yet paid by the 

financial institution, from cash to accounts payable at December 31, 2011 and 2010, respectively.

Restricted Cash and Cash Equivalents, and Restricted Deposits

Restricted deposits consisted of cash balances that are restricted to pay amounts required for lease payments, debt service or 

to provide collateral. Included in restricted deposits was $51 million and $47 million at December 31, 2011 and 2010, 

respectively, related to lease payments, debt service, collateral reserves, or other. The restricted cash and cash equivalents at 

December 31, 2011 included $97 million of cash proceeds received from a wind financing that was held in escrow at 

December 31, 2011 and is expected to be released in the first quarter of 2012 when the Pinnacle project achieves certain 

completion milestones.

Allowance for Uncollectible Accounts

SCE records an allowance for uncollectible accounts, based upon a variety of factors, including historical amounts writtenoff, current economic conditions and assessment of customer collectability.
96

Inventory

Inventory is stated at the lower of cost or market, cost being determined by the weighted-average cost method for fuel, and 

the average cost method for materials and supplies. Inventory consisted of the following:

(in millions)

Coal, gas, fuel oil and other raw materials

Spare parts, materials and supplies

Total inventory

December 31,

2011

$ 211

413

$ 624

2010

$ 184

384

$ 568

Purchased Emission Allowances, Exemptions and Offsets

Purchased emission allowances are stated at the lower of weighted-average cost or market. Purchased emission allowances 

are recorded at cost when purchased and then expensed at weighted-average cost as used. Cost is reduced to market value if 

the market value of emission allowances has declined and it is probable that revenues earned from the generation of power 

will not cover the amounts recorded in the ordinary course of business. Purchased emission allowances are classified as 

current or long-term assets based on the time the allowances are expected to be used. The following table summarizes the 

amount of current and noncurrent purchased emission allowances, exemptions and offsets and the line item on the 

consolidated balance sheets.

(in millions)

Purchased emission allowances

Current (included in other current assets)

Noncurrent(included in other long-term assets)

December 31,

2011

$ 20

92

2010

$ 29

31

Renewable Energy Credits

Renewable energy certificates or credits ("RECs") represent property rights established by governmental agencies for the 

environmental, social, and other nonpower qualities of renewable electricity generation. A REC, and its associated attributes 

and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation 

source in certain markets. 

Retail sellers of electricity obtain RECs through renewable power purchase agreements, internal generation or separate 

purchases in the market to comply with renewable portfolio standards established in certain such governmental agencies. 

RECs are the mechanism used to verify renewable portfolio standards compliance and are recognized at the lower of 

weighted-average cost or market when amounts purchased are in excess of the amounts needed to comply with RPS 

requirements. The cost of RECs is recoverable as part of the cost of purchased power by SCE. 

Property, Plant and Equipment

Utility Property, Plant and Equipment

Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor 

and indirect costs such as construction overhead, administrative and general costs, pension and benefits, and property taxes. 

The CPUC authorizes a rate for each of the indirect costs which are allocated to each project based on either labor or total 

costs. In addition, allowance for funds used during construction ("AFUDC") is capitalized for certain projects.
97

Estimated useful lives (authorized by the CPUC) and weighted-average useful lives of SCE's property, plant and equipment, 

are as follows:

Generation plant

Distribution plant

Transmission plant

General and Other plant

Estimated Useful Lives

25 years to 70 years

30 years to 60 years

35 years to 65 years

5 years to 60 years

Weighted-Average

Useful Lives

40 years

40 years

46 years

22 years

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation 

expense stated as a percent of average original cost of depreciable utility plant was, on a composite basis, 4.3%, 4.1% and 

4.2% for 2011, 2010 and 2009, respectively. Replaced or retired property costs are charged to the accumulated provision for 

depreciation. Cash payments for removal costs less salvage reduce the liability for asset retirement obligations ("AROs").

Nuclear fuel is recorded as utility plant (nuclear fuel in the fabrication and installation phase is recorded as construction in 

progress) in accordance with CPUC ratemaking procedures. Nuclear fuel is amortized using the units of production method.

AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction and is capitalized during 

certain plant construction. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset.

AFUDC equity represents a method to compensate SCE for the estimated cost of equity used to finance utility plant additions 

and is recorded as part of construction in progress. AFUDC equity was $96 million, $100 million and $116 million in 2011, 

2010 and 2009, respectively. AFUDC debt was $42 million, $41 million and $32 million in 2011, 2010 and 2009, 

respectively.

The FERC issued an order granting return on equity ("ROE") incentive adders, recovery of the return on rate base including 

incentive adders during the construction phase (referred to as CWIP) and recovery of abandoned plant costs, if needed, for 

several of SCE's transmission projects. In addition, the FERC granted an ROE incentive to SCE for California Independent 

System Operator ("CAISO") participation. The order permits SCE to include 100% of prudently-incurred capital 

expenditures in rate base during construction of the projects and earn a return on equity, rather than capitalizing AFUDC.

Competitive Power Generation and Other Property

Property, plant and equipment, including leasehold improvements and construction in progress, are capitalized at cost and are 

principally comprised of EMG's majority-owned subsidiaries' plants and related facilities and, prior to January 1, 2010, the 

plant and related facilities of VIEs consolidated by SCE. Depreciation and amortization are computed using the straight-line 

method over the estimated useful life of the property, plant and equipment and over the shorter of the lease term or estimated 

useful life for leasehold improvements. Gains and losses from sale of assets are recognized at the time of the transaction.

As part of the acquisition of the Midwest Generation plants and Homer City plant, EMG acquired emission allowances under 

the United States Environmental Protection Agency's (US EPA's) Acid Rain Program. EMG uses these emission allowances 

in the normal course of its business to generate electricity and has classified them as part of property, plant and equipment. 

Acquired emission allowances will be amortized on a straight-line basis.

Estimated useful lives for property, plant and equipment are as follows:

Power plant facilities

Leasehold improvements

Emission allowances

Equipment, furniture and fixtures

3 to 35 years

Shorter of life of lease or estimated useful life

25 to 33.75 years

3 to 10 years

Interest incurred on funds borrowed by EMG is capitalized during the construction period. Such capitalized interest is 

included in property, plant and equipment. Capitalized interest is amortized over the depreciation period of the major plant 

and facilities for the respective project. Capitalized interest was $27 million, $54 million and $19 million in 2011, 2010 and 

2009, respectively.
98

Major Maintenance

Certain of Edison International's power plant facilities and equipment require periodic major maintenance. These costs are 

expensed as incurred.

Asset Retirement Obligations

The fair value of a liability for an ARO is recorded in the period in which it is incurred, including a liability for the fair value 

of a conditional ARO, if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or 

method of settlement. When an ARO liability is initially recorded, the entity capitalizes the cost by increasing the carrying 

amount of the related long-lived asset. Over time, the liability is increased for accretion expense each period and the 

capitalized cost is depreciated over the useful life of the related asset. Settlement of an ARO liability for an amount other than 

its recorded amount results in an increase or decrease in expense. AROs related to decommissioning of SCE's nuclear power 

facilities are based on site-specific studies. Those site-specific studies are updated as part of each Nuclear Decommissioning 

Cost Triennial Proceeding ("NDCTP"). The initial establishment of a nuclear-related ARO is at fair value. Subsequent layers 

of an ARO are established for updated site-specific decommissioning cost estimates as approved by the CPUC on the 

NDCTP. For further discussion, see "Nuclear Decommissioning" below and Notes 4 and 15. A reconciliation of the changes 

in the ARO liability is as follows:

(in millions)

Beginning balance

Accretion expense

Revisions1

Liabilities added

Liabilities settled

Transfers in or out2

Ending balance

2011

$ 2,561

68

41

19

(1)

—

$ 2,688

2010

$ 3,241

198

(867)

9

(1)

(19)

$ 2,561

1 Revisions in 2010 represent the most recent site-specific studies approved by the CPUC.

2 Transfers in or out consist of the deconsolidation of the Big 4 projects (Kern River, Midway-Sunset, 

Sycamore and Watson) effective January 1, 2010. For further discussion, see Note 3.

In 2003, SCE recorded the fair value of its liability for AROs related to the decommissioning of its nuclear power facilities. 

At that time, SCE adjusted its nuclear decommissioning obligation, capitalized the initial costs of the ARO into a nuclearrelated ARO regulatory asset and also recorded an ARO regulatory liability as a result of timing differences between the 

recognition of costs and the recovery of costs through the ratemaking process. Once a Commission decision is rendered, a 

revised ARO layer reflecting the updated cost estimate is established and accreted over the lives of San Onofre and Palo 

Verde. The ARO liability related to San Onofre and Palo Verde was $2.5 billion at both December 31, 2011 and 2010.

Impairment of Long-Lived Assets

Edison International evaluates the impairment of its investments in projects and other long-lived assets based on a review of 

estimated future cash flows expected to be generated whenever events or changes in circumstances indicate that the carrying 

amount of such investments or assets may not be recoverable. Edison International's unit of account is at the plant level and, 

accordingly, the closure of a unit at a multi-unit site would not result in an impairment of property, plant and equipment 

unless such condition were to affect an impairment assessment on the entire plant. If the carrying amount of a long-lived asset

exceeds expected future cash flows, undiscounted and without interest charges, an impairment loss is recognized in the 

amount of the excess of fair value over the carrying amount. Fair value is determined via market, cost and income based 

valuation techniques, as appropriate. SCE's impaired assets are recorded as a regulatory asset if it is deemed probable that 

such amounts will be recovered from customers. For further discussion, see Note 16.

Project Development Costs

Edison International capitalizes project development costs incurred in the assessment, design and construction of generating 

projects once it is probable that the project will be completed. Edison International determines it is probable that the project 

will be completed based upon management's determination that the project is economically and operationally feasible and 

appropriate management and regulatory approvals have been obtained or are probable. Project development costs consist of 

professional fees, permits and other directly related development costs incurred by Edison International. The capitalized costs
99

are recorded in other long-term assets on Edison International's consolidated balance sheets until the start of construction, at 

which time the costs are transferred to construction in progress, a component of property, plant and equipment. The 

capitalized costs are amortized over the life of the projects once operational or charged to expense if management determines 

the costs to be unrecoverable.

Leases

SCE and EMG enter into power purchase agreements that may contain leases, as discussed under "Power Purchase 

Agreements" below. EMG leases the Homer City, Powerton and a portion of the Joliet power plants under sales leaseback 

arrangements as described in Note 9. Both SCE and EMG have entered into a number of agreements to lease property and 

equipment in the normal course of business. Minimum lease payments under operating leases for property, plant and 

equipment are levelized (total minimum lease payments divided by the number of years of the lease) and recorded as rent 

expense over the terms of the leases. Lease payments in excess of the minimum are recorded as rent expense in the year 

incurred.

Capital leases are reported as long-term obligations on the consolidated balance sheets in "Other deferred credits and other 

long-term liabilities." As a rate-regulated enterprise, SCE's capital lease amortization expense and interest expense are 

reflected in "Purchased power" on the consolidated statements of income.

Nuclear Decommissioning

SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by the NRC. 

Decommissioning is expected to begin after expiration of the plants' operating licenses. The plants' operating licenses are 

currently set to expire in 2022 for San Onofre Units 2 and 3, unless license renewal proves feasible, and 2045, 2046 and 2047 

for Palo Verde units 1, 2 and 3, respectively. Decommissioning costs, which are recovered through nonbypassable customer 

rates over the term of each nuclear facility's operating license, are recorded as a component of depreciation expense, with a 

corresponding credit to the ARO regulatory liability. Amortization of the ARO asset (included within the unamortized nuclear 

investment) and accretion of the ARO liability are deferred as increases to the ARO regulatory liability account, resulting in 

no impact on earnings.

SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in 

independent trusts. The cost of removal amounts, in excess of fair value collected for assets not legally required to be 

removed, are classified as regulatory liabilities.

Due to regulatory recovery of SCE's nuclear decommissioning expense, nuclear decommissioning activities do not affect 

SCE's earnings. SCE's nuclear decommissioning trust investments primarily consist of debt and equity investments that are 

classified as available-for-sale. Due to regulatory mechanisms, earnings and realized gains and losses (including other-thantemporary impairments) have no impact on electric utility revenue. Unrealized gains and losses on decommissioning trust 

funds increase or decrease the trust assets and the related regulatory asset or liability and have no impact on electric utility 

revenue or decommissioning expense. SCE reviews each security for other-than-temporary impairment on the last day of 

each month. If the fair value on the last day of two consecutive months is less than the cost for that security, SCE recognizes

a loss for the other-than-temporary impairment. If the fair value is greater or less than the cost for that security at the time of 

sale, SCE recognizes a related realized gain or loss, respectively.

Deferred Financing Costs

Debt premium, discount and issuance expenses incurred in connection with obtaining financing are deferred and amortized 

on a straight-line basis for SCE and on a basis which approximates the effective interest rate method for EMG as interest 

expense over the term of the related debt. Under CPUC ratemaking procedures, debt reacquisition expenses are amortized 

over the remaining life of the reacquired debt or, if refinanced, the life of the new debt. SCE had unamortized losses on 

reacquired debt of $249 million and $268 million at December 31, 2011 and 2010, respectively, reflected in "Regulatory 

assets" in the long-term section of the consolidated balance sheets. Edison International had unamortized debt issuance costs 

of $134 million and $114 million at December 31, 2011 and 2010, respectively, reflected in "Other long-term assets" on the 

consolidated balance sheets. Amortization of deferred financing costs charged to interest expense was $49 million, 

$35 million and $31 million in 2011, 2010 and 2009, respectively.
100

Revenue Recognition

Electric Utility Revenue

Electric utility revenue is recognized when electricity is delivered and includes amounts for services rendered but unbilled at

the end of each reporting period. Rates charged to customers are based on CPUC and FERC-authorized revenue 

requirements. CPUC rates are implemented upon final approval, and beginning in 2012 FERC rates are based on a forecasted 

revenue requirement, subject to refund and settlement procedures, and will be trued-up annually based on actual amounts.

CPUC rates decouple authorized revenue from the volume of electricity sales, so that SCE earns revenue equal to amounts 

authorized. Differences between amounts collected and authorized levels are either collected from or refunded to customers, 

and therefore, such differences do not impact operating revenue.

SCE remits to the California Department of Water Resources ("CDWR"), and does not recognize as revenue the amounts that 

SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, as well as 

CDWR-bond-related costs and a portion of direct access exit fees. Power purchased by the CDWR for these long-term 

contracts are not considered a cost to SCE because SCE is acting as a limited agent to CDWR for these transactions. The 

amounts collected and remitted to CDWR were $1.1 billion, $1.2 billion, and $1.8 billion for the years ended December 31, 

2011, 2010 and 2009, respectively. All power contracts that CDWR allocated to SCE had expired by the end of 2011. The 

bond-related charges and direct access exit fees continue until 2022.

Competitive Power Generation Revenue

Generally, revenues and related costs are recognized when electricity is generated, or services are provided, unless the 

transaction is accounted for as a derivative and does not qualify for the normal purchases and sales exception. EMG's 

subsidiaries enter into power and fuel hedging, optimization transactions and energy trading contracts, all subject to market 

conditions. One of EMG's subsidiaries executes these transactions primarily through the use of physical forward commodity 

purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, EMG's 

subsidiaries generally act as the principal, take title to the commodities, and assume the risks and rewards of ownership. 

EMG's subsidiaries record the settlement of non-trading physical forward contracts on a gross basis. EMG nets the cost of 

purchased power against related third-party sales in markets that use locational marginal pricing, currently PJM. Financial 

swap and option transactions are settled net and, accordingly, EMG's subsidiaries do not take title to the underlying 

commodity. Therefore, gains and losses from settlement of financial swaps and options are recorded net in operating revenues 

in the accompanying consolidated statements of operations.

Revenues under certain long-term power sales contracts are recognized based on the output delivered at the lower of the 

amount billable or the average rate over the contract term. The excess of the amounts billed over the portion recorded as 

revenues is reflected in deferred revenues on the consolidated balance sheets.

EMG accounts for grant income on the deferred method and, accordingly, will recognize operating revenues related to such 

income over the estimated useful life of the projects. In 2011, EMG received a total of $388 million of U.S. Treasury grants 

(cash grants, under the American Recovery and Reinvestment Act of 2009). 

Power Purchase Agreements

Both SCE, generally as the purchaser, and EMG, generally as the seller, enter into power purchase agreements in the normal 

course of business. A power purchase agreement may be considered a variable interest in a variable interest entity. Under this 

classification, the power purchase agreement is evaluated to determine if SCE or EMG is the primary beneficiary in the 

variable interest entity, in which case, such entity would be consolidated. None of SCE's or EMG's power purchase 

agreements resulted in consolidation of a variable interest entity at December 31, 2011. See Note 3 for further discussion of 

power purchase agreements that are considered variable interests.

A power purchase agreement may also contain a lease for accounting purposes. This generally occurs when a power purchase 

agreement (signed or modified after June 30, 2003) designates a specific power plant in which the buyer purchases 

substantially all of the output and does not otherwise meet a fixed price per unit of output exception. SCE and EMG have a 

number of power purchase agreements that contain leases. EMG's revenue from these power sales agreements were 

$109 million, $81 million and $83 million in 2011, 2010 and 2009, respectively. SCE's recognition of lease expense conforms 

to the ratemaking treatment for SCE's recovery of the cost of electricity and are recorded in purchased power. These 

agreements are classified as operating leases as electricity is delivered at rates defined in power sales agreements. See Note 9 

for further discussion of SCE's power purchase agreements, including agreements that are classified as capital leases for 

accounting purposes.
101

A power purchase agreement that does not contain a lease may be classified as a derivative subject to a normal purchase and 

sale exception, in which case the power purchase agreement is classified as an executory contract and accounted for on an 

accrual basis. Most of SCE's QF contracts are not required to be recorded on the consolidated balance sheets because they 

either do not meet the definition of a derivative or meet the normal purchase and sale exception. However, SCE purchases 

power from certain QFs in which the contract pricing is based on a natural gas index, but the power is not generated with 

natural gas. These contracts are not eligible for the normal purchase and sale exception and are recorded as a derivative on 

the consolidated balance sheets at fair value. See Note 6 for further information on derivatives and hedging activities.

Power purchase agreements that do not meet the above classifications are accounted for on an accrual basis.

Derivative Instruments and Hedging Activities

Edison International records derivative instruments on its consolidated balance sheets as either assets or liabilities measured

at fair value unless otherwise exempted from derivative treatment as normal purchases or sales. The normal purchases and 

sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable 

period in the normal course of business. Changes in the fair value of SCE's derivative instruments are expected to be 

recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no 

impact on purchased-power expenses or earnings. SCE does not use hedge accounting for derivative transactions due to 

regulatory accounting treatment.

 The accounting guidance for cash flow hedges provides that the effective portion of gains or losses on derivative instruments 

designated and qualifying as cash flow hedges be reported as a component of other comprehensive income and be reclassified 

into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gains or 

losses on the derivative instruments, if any, must be recognized currently in earnings.

Where Edison International's derivative instruments are subject to a master netting agreement and certain criteria are met, 

Edison International presents its derivative assets and liabilities on a net basis on its consolidated balance sheets. In addition, 

derivative positions are offset against margin and cash collateral deposits. The results of derivative activities are recorded as 

part of cash flows from operating activities on the consolidated statements of cash flows. See Note 6 for further information 

on derivative and hedging activities.

Sales and Use Taxes

SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use 

taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to 

operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate.

These franchise fees, which are required to be paid regardless of SCE's ability to collect from the customer, are accounted for

on a gross basis and reflected in electric utility revenue and other operation and maintenance expense. SCE's franchise fees 

billed to customers and recorded as electric utility revenue were $101 million, $102 million and $102 million for the years 

ended December 31, 2011, 2010 and 2009, respectively. When SCE acts as an agent and when the tax is not required to be 

remitted as not having been collected from the customer, the taxes are accounted for on a net basis. Amounts billed to and 

collected from customers for these taxes are remitted to the taxing authorities and are not recognized as electric utility 

revenue.

Stock-Based Compensation

Stock options, performance shares, deferred stock units and restricted stock units have been granted under Edison 

International's long-term incentive compensation programs. Generally, Edison International does not issue new common 

stock for settlement of equity awards. Rather, a third party is used to purchase shares from the market and delivery for 

settlement of option exercises, performance shares and restricted stock units. Performance shares earned are settled half in 

cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half 

subject to cash settlement in common stock. Deferred stock units granted to management are settled in cash and represent a 

liability. Restricted stock units are settled in common stock; however, Edison International will substitute cash awards to the

extent necessary to pay tax withholding or any government levies.

Edison International recognizes stock-based compensation expense on a straight-line basis over the requisite service period. 

Edison International recognizes stock-based compensation expense for awards granted to retirement-eligible participants on a 

prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes 

eligible for retirement.
102

Dividend Restrictions

The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. In SCE's most recent 

cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component 

of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital 

structure remains at or above the 48% authorized level on a 13-month weighted average basis. At December 31, 2011, SCE's 

13-month weighted-average common equity component of total capitalization was 50.4% resulting in the capacity to pay 

$436 million in additional dividends.

Earnings Per Share

Edison International computes earnings per share ("EPS") using the two-class method, which is an earnings allocation 

formula that determines EPS for each class of common stock and participating security. Edison International's participating 

securities are stock-based compensation awards payable in common shares, including stock options, performance shares and 

restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during 

the period 2003 through 2006 received dividend equivalents. EPS attributable to Edison International common shareholders 

was computed as follows:

(in millions)

Basic earnings per share – continuing operations:

Income from continuing operations attributable to common

shareholders, net of tax

Participating securities dividends

Income from continuing operations available to common

shareholders

Weighted average common shares outstanding

Basic earnings per share – continuing operations

Diluted earnings per share – continuing operations:

Income from continuing operations available to common

shareholders

Income impact of assumed conversions

Income from continuing operations available to common

shareholders and assumed conversions

Weighted average common shares outstanding

Incremental shares from assumed conversions

Adjusted weighted average shares – diluted

Diluted earnings per share – continuing operations

Years ended December 31,

2011

$ (34)

—

$ (34)

326

$ (0.10)

$ (34)

—

$ (34)

326

—

326

$ (0.10)

1

1

2010

$ 1,252

(5)

$ 1,247

326

$ 3.83

$ 1,247

5

$ 1,252

326

3

329

$ 3.81

2

2009

$ 856

(6)

$ 850

326

$ 2.61

$ 850

1

$ 851

326

1

327

$ 2.60

2

1 Due to a loss for the period, there are no incremental shares in the computation because such shares would be 

considered antidilutive. 

2

 Stock-based compensation awards to purchase 5,981,090, and 8,547,090 shares of common stock for the years 

ended December 31, 2010 and 2009, respectively, were outstanding, but were not included in the computation of 

diluted earnings per share because the exercise price of the awards was greater than the average market price of 

the common shares during the respective periods and, therefore, the effect would have been antidilutive.

Income Taxes

Edison International estimates its income taxes for each jurisdiction in which it operates. This involves estimating current 

period tax expense along with assessing temporary differences resulting from differing treatment of items (such as 

depreciation) for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are 

included within Edison International's consolidated balance sheets. Income tax expense includes the current tax liability from 

operations and the change in deferred income taxes during the year. Investment tax credits are deferred and amortized to 

income tax expense over the lives of the properties or the term of the power purchase agreement of the respective project 

while production tax credits are recognized in income tax expense in the period in which they are earned. EMG's investments 

in wind-powered electric generation projects qualify for federal production tax credits. Such credits are allowable for 
103

production during the 10-year period after a qualifying wind energy facility is placed into service. Certain of EMG's wind 

projects also qualify for state tax credits, which are accounted for similarly to federal production tax credits.

Interest income, interest expense and penalties associated with income taxes are reflected in "Income tax expense" on the 

consolidated statements of income. 

Edison International's eligible subsidiaries are included in Edison International's consolidated federal income tax and 

combined state tax returns. Edison International has tax-allocation and payment agreements with certain of its subsidiaries. 

For subsidiaries other than SCE, the right of a participating subsidiary to receive or make a payment and the amount and 

timing of tax-allocation payments are dependent on the inclusion of the subsidiary in the consolidated income tax returns of 

Edison International and other factors including the consolidated taxable income of Edison International and its includible 

subsidiaries, the amount of taxable income or net operating losses and other tax items of the participating subsidiary, as well

as the other subsidiaries of Edison International. There are specific procedures regarding allocations of state taxes. Each 

subsidiary is eligible to receive tax-allocation payments for its tax losses or credits only at such time as Edison International 

and its subsidiaries generate sufficient taxable income to be able to utilize the participating subsidiary's losses in the 

consolidated income tax return of Edison International. Pursuant to an income tax-allocation agreement approved by the 

CPUC, SCE's tax liability is computed as if it filed its federal and state income tax returns on a separate return basis.

Related Party Transactions

Four EMG subsidiaries have 49% to 50% ownership in partnerships that sell electricity generated by their project facilities to 

SCE under long-term power purchase agreements with terms and pricing approved by the CPUC. Sales by these partnerships 

to SCE under these agreements amounted to $277 million, $367 million and $366 million in 2011, 2010 and 2009, 

respectively.

An indirect wholly owned affiliate of EMG has entered into operation and maintenance agreements with partnerships in 

which EMG has a 50% or less ownership interest. EMG recorded power generation revenue under these agreements of 

$23 million, $23 million and $26 million in 2011, 2010 and 2009, respectively. EMG's accounts receivable with this affiliate 

totaled $3 million and $5 million at December 31, 2011 and 2010, respectively.

New Accounting Guidance

Accounting Guidance Adopted in 2011 

Revenue-Multiple-Deliverables

In October 2009, the Financial Accounting Standards Board ("FASB") issued amended guidance for identifying separate 

deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and 

recognizing revenues based on those separate deliverables. This update also requires additional disclosure related to the 

significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is required to 

be applied prospectively to new or significantly modified revenue arrangements. Edison International adopted this guidance 

effective January 1, 2011. The adoption of this accounting standards update did not have a material impact on Edison 

International's consolidated income statements, financial position or cash flows.

Fair Value Measurements and Disclosures

The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements. 

Under these requirements, purchases and settlements for Level 3 fair value measurements are presented on a gross basis, 

rather than net. Edison International adopted this guidance effective January 1, 2011.

Accounting Guidance Not Adopted in 2011

Fair Value Measurement

In May 2011, the FASB issued an accounting standards update modifying the fair value measurement and disclosure 

guidance. This guidance prohibits grouping of financial instruments for purposes of fair value measurement and requires the 

value be based on the individual security. This amendment also results in new disclosures primarily related to Level 3 

measurements including quantitative disclosure about unobservable inputs and assumptions, a description of the valuation 

processes and a narrative description of the sensitivity of the fair value to changes in unobservable inputs. Edison 

International will adopt this guidance in the first quarter of 2012. The adoption of this accounting standards update is not 

expected to have a material impact on Edison International's consolidated financial position.
104

Presentation of Comprehensive Income

In June 2011 and December 2011, the FASB issued an accounting standards update on the presentation of comprehensive 

income. An entity can elect to present items of net income and other comprehensive income in one continuous statement, 

referred to as the statement of comprehensive income, or in two separate but consecutive statements. Edison International 

will adopt this guidance in the first quarter of 2012. Edison International currently presents the statement of comprehensive 

income immediately following the statement of income and will continue to do so. The adoption of this accounting standards 

update will not change the items that constitute net income and other comprehensive income.

Offsetting Assets and Liabilities

In December 2011, the FASB issued an accounting standards update modifying the disclosure requirements about the nature 

of an entity's rights of offsetting assets and liabilities in the statement of financial position under master netting agreements 

and related arrangements associated with financial and derivative instruments. The guidance requires increased disclosure of 

the gross and net recognized assets and liabilities, collateral positions and narrative descriptions of setoff rights. Edison 

International will adopt this guidance effective January 1, 2013. Edison International does not expect the adoption of this 

standard to have a material impact on Edison International's consolidated statements of income, financial position or cash 

flows.

Note 2. Property, Plant and Equipment

Utility Property, Plant and Equipment

Utility property, plant and equipment included on the consolidated balance sheets is composed of the following:

(in millions)

Transmission

Distribution

Generation

General plant and other

Accumulated depreciation

Construction work in progress

Nuclear fuel, at amortized cost

Total utility property, plant and equipment

December 31,

2011

$ 6,109

15,938

4,063

3,951

(6,894)

23,167

3,922

480

$ 27,569

2010

$ 5,811

14,878

3,371

3,377

(6,319)

21,118

3,291

369

$ 24,778

Capitalized Software Costs

SCE capitalizes costs incurred during the application development stage of internal use software projects to property, plant, 

and equipment. SCE amortizes capitalized software costs ratably over the expected lives of the software, ranging from 5 to 

15 years and commencing upon operational use. At December 31, 2011 and 2010, capitalized software costs were $1.4 billion 

and $1.1 billion and accumulated amortization was $491 million and $393 million, respectively. Amortization expense for 

capitalized software was $156 million, $129 million and $88 million in 2011, 2010 and 2009, respectively. At December 31, 

2011, amortization expense is estimated to be approximately $174 million annually for 2012 through 2016.

Jointly Owned Utility Projects

SCE owns interests in several generating stations and transmission systems for which each participant provides its own 

financing. SCE's proportionate share of these projects is reflected in the consolidated balance sheets and included in the 

above table. SCE's proportionate share of expenses for each project is reflected in the consolidated statements of income. All 

of the investments in the Mohave generating station and a portion of the investments in San Onofre and Palo Verde 

generating stations are included in regulatory assets on the consolidated balance sheets—see Note 14. 
105

The following is SCE's investment in each project as of December 31, 2011:

(in millions)

Transmission systems:

Eldorado

Pacific Intertie

Generating stations:

Four Corners Units 4 and 5 (coal)

Mohave (coal)

Palo Verde (nuclear)

San Onofre (nuclear)

Total

Plant in

Service

$ 71

189

589

327

1,803

5,198

$ 8,177

Construction

Work in

Progress

$ 4

2

17

24

54

370

$ 471

Accumulated

Depreciation

$ 13

68

519

287

1,465

4,111

$ 6,463

Nuclear Fuel 

(at amortized 

cost)

$ —

—

—

—

138

342

$ 480

Net Book

Value

$ 62

123

87

64

530

1,799

$ 2,665

Ownership

Interest

60%

50%

48%

56%

16%

78%

In addition to the projects above, SCE has ownership interests in jointly owned power poles with other companies.

On November 8, 2010, SCE entered into an agreement to sell its ownership interest in Units 4 and 5 of the Four Corners coalfired electric generating facility to the operator of the facility, Arizona Public Service Company. The sale price is 

$294 million, subject to certain adjustments. The closing of the sale is contingent upon the receipt of regulatory approvals and 

other specified closing conditions and is estimated to occur in the second half of 2012. Any gain on sale will be for the 

benefit of SCE's customers and, therefore, will not affect SCE's earnings.

Competitive Power Generation and Other Property, Plant and Equipment

Competitive power generation and other property included on the consolidated balance sheets was composed of the plant and 

related facilities of EMG:

(in millions)

Building, plant and equipment

Emission allowances

Leasehold improvements

Furniture and equipment

Land (including easements)

Construction work in progress1

Accumulated depreciation

Competitive power generation and other property – net

December 31,

2011

$ 4,708

672

4

130

64

377

5,955

(1,408)

$ 4,547

2010

$ 4,572

1,305

177

97

84

1,036

7,271

(1,865)

$ 5,406

1 Construction work in progress consisted of $357 million and $888 million at December 31, 2011 and 

2010, respectively, for new gas and wind projects under construction.

EMG recorded $1.7 billion of impairment charges in 2011. For additional information on these charges, see Note 16.

The power sales agreements of certain wind projects are classified as operating leases. The carrying amount and related 

accumulated depreciation of the property of these wind projects totaled $1.6 billion and $203 million, respectively, at 

December 31, 2011.

Note 3. Variable Interest Entities

Effective January 1, 2010, Edison International adopted the FASB's new guidance regarding VIEs. A VIE is defined as a legal 

entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk 

lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive 

the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both 
106

the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the 

obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The 

primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that 

most significantly impact the economic performance of VIEs in which Edison International has a variable interest. 

Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and 

compliance with regulatory and contractual requirements.

Description of Use of Variable Interest Entities

EMG and its subsidiaries and affiliates have used VIEs as part of joint development agreements and constructing or acquiring 

full or partial interests in power generation facilities and ancillary facilities, referred to by EMG as a project. EMG's 

subsidiaries and affiliates have financed the development and construction or acquisition of its projects by capital 

contributions from EMG and the incurrence of debt or lease obligations by its subsidiaries and affiliates owning the operating 

facilities. These project level debt or lease obligations are generally secured by project specific assets and structured as nonrecourse to EMG, with several exceptions, including EMG's guarantee of the Powerton and Joliet leases as part of a 

refinancing of indebtedness incurred by its project subsidiary to purchase the Midwest Generation plants.

Categories of Variable Interest Entities

Projects or Entities that are Consolidated

At December 31, 2011 and 2010, EMG consolidated 13 and 14 projects, respectively, with a total generating capacity of 

570 MW and 580 MW, respectively, that have minority interests held by others. In April 2011, EMG sold its 75% ownership 

interest in a Minnesota wind project.

The following table presents summarized financial information of the projects that were consolidated by EMG:

(in millions)

Current assets

Net property, plant and equipment

Other long-term assets

Total assets

Current liabilities

Long-term debt net of current portion

Deferred revenues

Other long-term liabilities

Total liabilities

Noncontrolling interests

December 31,

2011

$ 36

675

5

$ 716

$ 28

57

69

22

$ 176

$ 2

December 31,

2010

$ 26

739

6

$ 771

$ 25

71

71

21

$ 188

$ 4

Assets serving as collateral for the debt obligations had a carrying value of $136 million and $163 million at December 31, 

2011 and 2010, respectively, and primarily consist of property, plant and equipment. Effective January 1, 2010, EMG 

prospectively consolidated the Ambit project (a 50% interest in American Bituminous Power Partners, L.P.) and 

deconsolidated the Elkhorn Ridge and San Juan Mesa wind projects.

During 2011, EMG purchased the remaining interests in Pinnacle Wind Force, LLC and Broken Bow I, LLC and all assets of 

the Crofton Bluffs project. During 2010, EMG purchased a noncontrolling interest in Laredo Ridge. All these projects are 

now 100% owned by EMG. The purchases of the noncontrolling interest were accounted for as equity transactions between 

controlling and noncontrolling interest holders.

Capistrano Wind Equity Capital - 2012

As part of its plan to obtain third-party equity capital to finance the development of a portion of EMG's wind portfolio, on 

February 13, 2012, Edison Mission Wind sold its indirect equity interests in the Cedro Hill wind project (150 MW in Texas), 

the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in Wyoming) to 

a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. Capistrano Wind Partners 

also agreed to acquire the Broken Bow I wind project (80 MW in Nebraska) and the Crofton Bluffs wind project (40 MW in 

Nebraska) for consideration expected to include $141 million from the same outside investors upon the satisfaction of 
107

specified conditions, including commencement of commercial operation and completion of project debt financing. The 

proceeds from outside investors, net of costs on the projects to be completed, are expected to be distributed to EMG and 

available for general corporate purposes.

An indirect subsidiary of EME, Edison Mission Wind, and EME's parent company, Mission Energy Holding Company 

(MEHC), own 100% of the Class A equity interests in Capistrano Wind Partners, and the Class B preferred equity interests 

are held by outside investors. Under the terms of the formation documents, preferred equity interests receive 100% of the 

cash available for distribution, up to a scheduled amount to target a return and thereafter cash distributions are shared. Cash

available for distribution includes 90% of the tax benefits realized by MEHC and contributed to Capistrano Wind Partners. 

Edison Mission Wind retains indirect beneficial ownership of the common equity in the projects, net of a $4 million preferred 

investment made by MEHC, and retains responsibilities for managing the operations of Capistrano Wind Holdings and its 

projects, and accordingly, EMG will continue to consolidate these projects. The amount contributed by the third-party 

interests will be reflected as a noncontrolling interest in the consolidated financial statements. Edison Mission Wind plans to

distribute to EMG the amounts received from the sale of the projects, net of costs on the projects to be completed, which will 

then be available to EMG for general corporate purposes.

Variable Interest in VIEs that are not Consolidated

Power Purchase Contracts

SCE has 16 power purchase agreements ("PPAs") that have variable interests in VIEs, including 6 tolling agreements through 

which SCE provides the natural gas to fuel the plants and 10 contracts with qualifying facilities ("QFs") (including the Big 4 

projects) that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the 

primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In 

general, because payments for capacity are the primary source of income, the most significant economic activity for SCE's 

VIEs is the operation and maintenance of the power plants. 

As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its 

involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. Under these 

contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-approved long-term power 

procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, 

liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase 

commitments described in Note 9. As a result, there is no significant potential exposure to loss as a result of SCE's 

involvement with these VIEs. The aggregate capacity dedicated to SCE for these VIE projects was 3,820 MW at 

December 31, 2011 and the amounts that SCE paid to these projects were $477 million and $534 million for the years ended 

December 31, 2011 and 2010, respectively. These amounts are recoverable in customer rates.

Equity Interests

EMG accounts for the majority of its investments in domestic gas and wind energy projects in which it has less than a 100% 

ownership interest, and does not have both the right to direct the commercial and operating activities and the obligation to 

absorb losses or receive benefits from the VIEs, under the equity method. As of December 31, 2011 and 2010, EMG had 

significant variable interests in five natural gas projects that are not consolidated, consisting of the Big 4 projects and the

Sunrise project. A subsidiary of EMG operates three of the four Big 4 projects and the Sunrise project and EMG's partner 

provides the fuel management services for the Big 4 projects. In addition, the executive director of these gas projects is 

provided by EMG's partner. Commercial and operating activities of these gas projects are jointly controlled by a management 

committee of each VIE. Accordingly, EMG accounts for its variable interests in these projects under the equity method.

At December 31, 2011, EMG also accounted for its interest in the Community Wind North wind project, which achieved 

commercial operation on May 28, 2011, under the equity method. The commercial and operating activities of this entity are 

jointly directed by representatives of each partner. Thus EMG is not the primary beneficiary of this project.
108

The following table presents the carrying amount of EMG's investments in unconsolidated VIEs and the maximum exposure 

to loss for each investment:

(in millions)

Natural gas-fired projects

Wind projects

December 31, 2011

Investment

$ 315

208

Maximum

Exposure

$ 315

208

EMG's exposure to loss in its VIEs accounted for under the equity method is generally limited to its investment in these 

entities. At December 31, 2011 and 2010, outstanding debt for projects that are not consolidated consisted of long-term debt 

that was secured by a pledge of project entity assets, but does not provide for recourse to EMG. At December 31, 2011, such 

outstanding indebtedness was $62 million, of which $16 million was proportionate to EMG's ownership in the project. At 

December 31, 2010, such outstanding indebtedness was $116 million, of which $41 million was proportionate to EMG's 

ownership interest in the projects.

EMG has also invested in affordable housing projects utilizing partnership or limited liability companies. With a few 

exceptions, an unrelated general partner or managing member exercises operating control of these projects. At December 31, 

2011, projects that EMG has accounted for under the equity method had indebtedness of approximately $1.2 billion, of which 

approximately $318 million is proportionate to its ownership interest in these projects. At December 31, 2010, projects that 

EMG has accounted for under the equity method had indebtedness of approximately $1.3 billion, of which approximately 

$451 million is proportionate to its ownership interest in these projects. Substantially all of this debt is nonrecourse to Edison 

Capital.

The following table presents summarized financial information of the investments in unconsolidated affiliates accounted for 

by the equity method:

(in millions)

Revenues

Expenses

Net income

Years Ended December 31,

2011

$ 971

839

$ 132

2010

$ 1,043

934

$ 109

2009

$ 581

506

$ 75

(in millions)

Current assets

Noncurrent assets

Total assets

Current liabilities

Noncurrent liabilities

Equity

Total liabilities and equity

December 31,

2011

$ 337

2,098

$ 2,435

$ 144

1,230

1,061

$ 2,435

2010

$ 352

2,437

$ 2,789

$ 227

1,312

1,250

$ 2,789

The difference between the carrying value of these equity investments and the underlying equity in the net assets was 

$10 million at December 31, 2011. The difference is being amortized over the life of the projects. The majority of noncurrent 

liabilities are composed of project financing arrangements that are nonrecourse to EMG. The undistributed earnings of equity 

method investments were $19 million and $28 million at December 31, 2011 and 2010, respectively.
109

The following table presents, as of December 31, 2011, the investments in unconsolidated affiliates accounted for by the 

equity method that represent at least 5% of EMG's loss before tax, excluding asset impairment charges, or in which EMG has 

an investment balance greater than $50 million:

Unconsolidated

Affiliates

San Juan Mesa

Elkhorn Ridge

Sunrise

Sycamore

Kern River

Watson

Location

Elida, NM

Bloomfield, NE

Fellows, CA

Bakersfield, CA

Bakersfield, CA

Carson, CA

Investment at

December 31,

2011

(in millions)

$ 84

81

173

34

21

42

Ownership

Interest at

December 31,

2011

75%

67%

50%

50%

50%

49%

Operating Status

Operating wind-powered facility

Operating wind-powered facility

Operating gas-fired facility

Operating cogeneration facility

Operating cogeneration facility

Operating cogeneration facility

The following table presents summarized financial information of the investments in unconsolidated affiliates:

(in millions)

Investments in Unconsolidated Affiliates

Equity investments

Cost investments

Total

December 31,

2011

$ 517

8

$ 525

2010

$ 550

9

$ 559

Note 4. Fair Value Measurements

Recurring Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction 

between market participants at the measurement date, referred to as an exit price. Fair value of an asset or liability should 

consider assumptions that market participants would use in pricing the asset or liability, including assumptions about 

nonperformance risk.

Edison International categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to

determine fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for 

identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
110

The following table sets forth assets and liabilities that were accounted for at fair value by level within the fair value 

hierarchy:

(in millions)

Assets at Fair Value

Money market funds2

Derivative contracts:

Electricity

Natural gas

Fuel oil

Tolling

Subtotal of commodity contracts

Long-term disability plan

Nuclear decommissioning trusts:

Stocks3

Municipal bonds

U.S. government and agency securities

Corporate bonds4

Short-term investments, primarily cash 

equivalents5

Subtotal of nuclear decommissioning trusts

Total assets6

Liabilities at Fair Value

Derivative contracts:

Electricity

Natural gas

Tolling

Subtotal of commodity contracts

Interest rate contracts

Total liabilities

Net assets (liabilities)

As of December 31, 2011

Level 1

$ 1,321

—

4

4

—

8

8

1,899

—

433

—

—

2,332

3,669

—

—

—

—

—

—

$ 3,669

Level 2

$ —

66

5

—

—

71

—

—

756

147

317

15

1,235

1,306

13

234

—

247

90

337

$ 969

Level 3

$ —

218

—

—

10

228

—

—

—

—

—

—

—

228

77

23

451

551

—

551

$ (323)

Netting

and

Collateral1

$ —

(62)

(7)

(4)

—

(73)

—

—

—

—

—

—

—

(73)

(21)

(52)

—

(73)

—

(73)

$ —

Total

$ 1,321

222

2

—

10

234

8

1,899

756

580

317

15

3,567

5,130

69

205

451

725

90

815

$ 4,315
111

(in millions)

Assets at Fair Value

Money market funds2

Derivative contracts:

Electricity

Natural gas

Fuel oil

Tolling

Subtotal of commodity contracts

Long-term disability plan

Nuclear decommissioning trusts:

Stocks3

Municipal bonds

Corporate bonds4

U.S. government and agency securities

Short-term investments, primarily cash 

equivalents5

Subtotal of nuclear decommissioning trusts

Total assets6

Liabilities at Fair Value

Derivative contracts:

Electricity

Natural gas

Tolling

Coal

Subtotal of commodity contracts

Interest rate contracts

Total liabilities

Net assets (liabilities)

As of December 31, 2010

Level 1

$ 1,100

—

1

8

—

9

9

2,029

—

—

215

1

2,245

3,363

—

—

—

—

—

—

—

$ 3,363

Level 2

$ —

70

69

—

—

139

—

—

790

346

73

31

1,240

1,379

13

286

—

1

300

16

316

$ 1,063

Level 3

$ —

363

11

—

118

492

—

—

—

—

—

—

—

492

40

11

344

—

395

—

395

$ 97

Netting

and

Collateral1

$ —

(61)

(1)

(8)

—

(70)

—

—

—

—

—

—

—

(70)

(21)

(4)

—

(1)

(26)

—

(26)

$ (44)

Total

$ 1,100

372

80

—

118

570

9

2,029

790

346

288

32

3,485

5,164

32

293

344

—

669

16

685

$ 4,479

1 Represents the netting of assets and liabilities under master netting agreements and cash collateral across the levels of the fair 

value hierarchy. Netting among positions classified within the same level is included in that level.

2 Money market funds are included in cash and cash equivalents and restricted cash and cash equivalents on Edison International's

consolidated balance sheets.

3 Approximately 70% and 67% of the equity investments were located in the United States at December 31, 2011 and 2010, 

respectively.

4

 At December 31, 2011 and 2010, corporate bonds were diversified and included collateralized mortgage obligations and other 

asset backed securities of $22 million and $27 million, respectively. 

5

 Excludes net receivables of $25 million and net liabilities of $5 million at December 31, 2011 and 2010, respectively, of interest 

and dividend receivables and receivables related to pending securities sales and payables related to pending securities purchases.

6

 Excludes $31 million at both December 31, 2011 and 2010, of cash surrender value of life insurance investments for deferred 

compensation.
112

The following table sets forth a summary of changes in the fair value of Level 3 assets and liabilities:

(in millions)

Fair value, net assets at beginning of period

Total realized/unrealized gains (losses):

Included in earnings1

Included in regulatory assets and liabilities2

Included in accumulated other comprehensive income

Purchases

Settlements

Transfers in or out of Level 3

Fair value, net assets (liabilities) at end of period

Change during the period in unrealized gains (losses) related to assets and liabilities 

held at the end of the period4

December 31,

2011

$ 97

(19)

(458)

1

81

(23)

(2)

$ (323)

$ (644)

3

2010

$ 62

64

58

2

66

(166)

11

$ 97

$ 143

1 Reported in "Competitive power generation" revenue on Edison International's consolidated statements of income.

2 Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and 

liabilities.

3 Includes the elimination of the fair value of derivatives with SCE's consolidated affiliates.

4 Amounts reported in "Competitive power generation" revenue on Edison International's consolidated statements of income 

were $16 million and $13 million for the years ended December 31, 2011 and 2010, respectively. The remainder of the 

unrealized losses relate to SCE. See 2 above.

Edison International determines the fair value for transfers in and transfers out of each level at the end of each reporting 

period. There were no significant transfers between levels during 2011 and 2010.

Valuation Techniques Used to Determine Fair Value

Level 1

Includes financial assets and liabilities where fair value is determined using unadjusted quoted prices in active markets that 

are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 

include exchange-traded equity securities, exchange traded derivatives, U.S. treasury securities and money market funds.

Level 2

Pricing inputs include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the 

asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument. Financial assets and 

liabilities utilizing Level 2 inputs include fixed-income securities and over-the-counter derivatives.

Derivative contracts that are over-the-counter traded are valued using pricing models to determine the net present value of 

estimated future cash flows and are generally classified as Level 2. Inputs to the pricing models include forward published or 

posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar 

instruments and discount rates. A primary source that best represents traded activity for each market is used to develop 

observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are 

used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) 

and are obtained from sources believed to provide the most liquid market for the commodity. Broker quotes are incorporated 

when corroborated with other information which may include a combination of prices from exchanges, other brokers and 

comparison to executed trades.

Level 3

Includes financial assets and liabilities where fair value is determined using techniques that require significant unobservable

inputs. Over-the-counter options, bilateral contracts, capacity contracts, QF contracts, derivative contracts that trade 

infrequently (such as congestion revenue rights ("CRRs") in the California market), long-term power agreements, and 
113

derivative contracts with counterparties that have significant nonperformance risks are generally valued using pricing models 

that incorporate unobservable inputs and are classified as Level 3. Assumptions are made in order to value derivative 

contracts in which observable inputs are not available. In circumstances where Edison International cannot verify fair value 

with observable market transactions, it is possible that a different valuation model could produce a materially different 

estimate of fair value. As markets continue to develop and more pricing information becomes available, Edison International 

continues to assess valuation methodologies used to determine fair value.

For derivative contracts that trade infrequently (illiquid financial transmission rights and CRRs), changes in fair value are 

based on models forecasting the value of those contracts. The models' inputs are reviewed and the fair value is adjusted when 

it is concluded that a change in inputs would result in a new valuation that better reflects the fair value of those derivative

contracts. For illiquid long-term power agreements, fair value is based upon the discounting of future electricity and natural 

gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit 

risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for

illiquid forward periods. The fair value of the majority of SCE's derivatives that are classified as Level 3 is determined using 

uncorroborated non-binding broker quotes and models which may require SCE to extrapolate short-term observable inputs in 

order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for 

reasonableness.

Nonperformance Risk

The fair value of the derivative assets and liabilities are adjusted for nonperformance risk. To assess nonperformance risks, 

SCE considers the probability of and the estimated loss incurred if a party to the transaction were to default. SCE also 

considers collateral, netting agreements, guarantees and other forms of credit support when assessing nonperformance. EMG 

reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default 

swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer 

the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks 

of derivative contracts, but provides market information of the related risk of nonperformance. The nonperformance risk 

adjustment represented an insignificant amount at both December 31, 2011 and 2010.

Nuclear Decommissioning Trusts

SCE's nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed-income 

securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in

active or highly liquid and transparent markets. The remaining fixed-income securities are classified as Level 2. The fair 

value of these financial instruments is based on evaluated prices that reflect significant observable market information such as 

reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, 

offers and relevant credit information.

SCE's investment policies and CPUC requirements place limitations on the types and investment grade ratings of the 

securities that may be held by the nuclear decommissioning trust funds. These policies restrict the trust funds from holding 

alternative investments and limit the trust funds' exposures to investments in highly illiquid markets. Except for Level 3 

investments, valuation is based on observable market inputs and assumptions used by market participants. With respect to 

equity and fixed income securities, the trustee obtains prices from third-party pricing services which SCE is able to 

independently corroborate as described below. A primary price source is identified by the trustee based on asset type, class or

issue for each security. The trustee monitors prices supplied by pricing services and may use a supplemental price source or 

change the primary price source of a given security if the trustee or SCE's investment managers challenge an assigned price 

and determine that another price source is considered to be preferable. The trustee “scrubs” prices against defined parameters 

at established times throughout the day. Variances that do not meet the parameters are researched and resolved. Unpriced and 

stale priced securities, as well as any unusual variations in market price or overall market value are investigated. Price 

variance reports are reviewed on the basis of predetermined tolerances. Variances identified outside of tolerance are then 

researched and resolved. Parameters and predetermined tolerance thresholds are established by asset class based on past 

experience and an understanding of valuation process techniques. Questionable prices are reported to the vendor who 

provided the price and pricing specialists then follow-up with the vendors. If the prices are validated, the primary price source 

is used. If not, a secondary source price which has passed the applicable tolerance check is used. The trustee monitors and 

grades the performance of pricing vendors. SCE reviewed the process/procedures of both the pricing services and the trustee 

to gain an understanding of the inputs/assumptions and valuation techniques used to price each asset type/class and to reach a 

conclusion that their pricing controls are satisfactory. This consisted of SCE's review of their written detailed process/

procedures and service organization control (SOC 1-formerly SAS 70) reports, as well as follow-up conversations based on 

our written questions. This assists SCE in determining if the valuations represent exit price fair value and that investments are 

appropriately classified in the fair value hierarchy. Additionally, SCE corroborates the fair values of securities by comparison 
114

to other market-based price sources obtained by SCE's investment managers. Differences outside established thresholds are 

followed-up with the trustee and resolved. The results of this process have demonstrated that vendor and trustee pricing 

controls are satisfactory. For each reporting period, SCE reviews the trustee determined fair value hierarchy and overrides the

trustee level classification when appropriate. Due to its regulatory treatment, SCE's fair value transactions are recovered in 

rates. 

Non-Recurring Fair Value Measurements

For a discussion on non-recurring fair value measurements, see Note 16.

Fair Value of Long-Term Debt Recorded at Carrying Value

The carrying value and fair value of long-term debt are:

(in millions)

Long-term debt, including current portion

December 31, 2011

Carrying

Value

$ 13,746

Fair

Value

$ 14,264

December 31, 2010

Carrying

Value

$ 12,419

Fair

Value

$ 12,360

Fair values of long-term debt are based on evaluated prices that reflect significant observable market information such as 

reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and

relevant credit information. The fair value of long-term debt is classified as Level 2.

The carrying value of trade receivables, payables and short-term debt approximates fair value.
115

Note 5. Debt and Credit Agreements

Long-Term Debt

The following table summarizes long-term debt (rates and terms are as of December 31, 2011):

(in millions)

First and refunding mortgage bonds:

2014 – 2041 (3.875% to 6.05% and floating)

Pollution-control bonds:

2028 – 2035 (2.875% to 5.0% and variable)

Bonds repurchased

Debentures and notes:

2013 – 2053 (5.06% to 7.625%)

Wind project financings:

Tapestry Wind, LLC

Term Loan (LIBOR plus 2.5%)

Big Sky Wind, LLC

Vendor financing loan due 2014 (LIBOR plus 3.5%)

Viento Funding II, Inc.

Term Loan due 2020 (LIBOR plus 2.75%)

Walnut Creek Energy and WCEP Holdings, LLC

 Construction Loans due 2013 (LIBOR plus 2.25% ; LIBOR plus 4%)

Cedro Hill Wind, LLC

Term Loan due 2025 (LIBOR plus 3.0%)

Laredo Ridge

 Term Loan due 2026 (LIBOR plus 2.75%)

High Lonesome Mesa, LLC

 Bonds Series 2010A and 2010B due 2017 (6.85%)

Other wind project financings

Other long-term debt

Long-term debt due within one year

Unamortized debt discount – net

Total

December 31,

2011

$ 7,375

939

(161)

4,407

214

211

207

187

131

74

72

55

65

(57)

(30)

$ 13,689

2010

$ 6,475

1,196

(324)

4,410

—

190

150

—

135

—

75

23

117

(48)

(28)

$ 12,371

Long-term debt maturities for the next five years are: 2012 – $57 million; 2013 – $755 million; 2014 – $1.5 billion; 2015 – 

$372 million; and 2016 – $966 million.

Liens and Security Interests

Almost all SCE properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage bonds as 

collateral for borrowed funds obtained from certain pollution-control bonds issued by government agencies. SCE has a debt 

covenant that requires a debt to total capitalization ratio be met. At December 31, 2011, SCE was in compliance with this 

debt covenant.

In connection with Midwest Generation's financing activities, a first priority security interest was provided in substantially all 

the coal-fired generating plants owned by Midwest Generation and the assets relating to those plants, the receivables of 

EMMT directly related to Midwest Generation's hedging activities and the pledge of the intercompany notes from EME 

(approximately $1.3 billion at December 31, 2011). The net book value of assets pledged or mortgaged was $2.3 billion at 

December 31, 2011. In addition to these assets, Midwest Generation's membership interests and the capital stock of Edison 

Mission Midwest Holdings were pledged.

In connection with the wind financings, payment obligations are generally secured by pledges of its direct and indirect 

ownership interests in the projects, project agreements and reserve accounts, if applicable. In connection with the Big Sky 
116

turbine financing, the loan is secured by a leasehold mortgage on the project's real property assets, a pledge of all other 

collateral of the Big Sky wind project, as well as a cash reserve account into which one-third of distributable cash flow, if 

any, of the Big Sky wind project is to be deposited on a monthly basis. For further details regarding consolidated assets 

pledged as security for debt obligations, see Note 3—Variable Interest Entities.

EME Senior Notes

EME has $3.7 billion of senior notes due 2013 through 2027. The senior notes are redeemable by EME at any time at a price 

equal to 100% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, of the senior notes 

plus a "make-whole" premium. The senior notes are EME's senior unsecured obligations, ranking equal in right of payment to 

all of EME's existing and future senior unsecured indebtedness, and will be senior to all of EME's future subordinated 

indebtedness. EME's secured debt and its other secured obligations are effectively senior to the senior notes to the extent of 

the value of the assets securing such debt or other obligations. None of EME's subsidiaries have guaranteed the senior notes 

and, as a result, all the existing and future liabilities of EME's subsidiaries are effectively senior to the senior notes.

Credit Agreements and Short-Term Debt

Edison International (parent) has a $1.4 billion revolving credit facility with various banks that terminates in February 2013.

Edison International's (parent) short-term debt is generally used for liquidity purposes. At December 31, 2011, Edison 

International (parent)'s outstanding short-term debt was $10 million at a weighted-average interest rate of 0.66%. At 

December 31, 2010, the outstanding short-term debt was $19 million at a weighted-average interest rate of 0.63%.

SCE has two revolving credit facilities with various banks; a $2.4 billion five-year credit facility that matures in February 

2013, and a $500 million three-year credit facility that matures in March 2013. Commercial paper issued under these credit 

facilities are generally used to finance fuel inventories, balancing accounts undercollections and general, temporary cash 

requirements including power purchase payments. At December 31, 2011, the outstanding commercial paper was 

$419 million at a weighted-average interest rate of 0.44%. At December 31, 2011, letters of credit issued under SCE's credit 

facilities aggregated $81 million and were scheduled to expire in twelve months or less.

At December 31, 2011, EMG's subsidiaries, EME and Midwest Generation, had credit facilities of $564 million and 

$500 million, respectively, maturing in June 2012. At December 31, 2011, EMG had no borrowings outstanding and 

$69 million of letters of credit outstanding under these credit facilities. Subsequent to the end of the fiscal year EME 

terminated its secured credit facility.

The following table summarizes the status of the credit facilities at December 31, 2011:

(in millions)

Commitment

Outstanding borrowings

Outstanding letters of credit

Amount available

SCE

$ 2,894

(419)

(81)

$ 2,394

EMG

$ 1,064

—

(69)

$ 995

Edison

International

(parent)

$ 1,426

(10)

—

$ 1,416

Letters of Credit

Letters of credit under EME's and its subsidiaries' credit facilities aggregated $177 million and were scheduled to expire as 

follows: $146 million in 2012, $3 million in 2013, $10 million in 2017, and $18 million in 2018. Standby letters of credit 

include $40 million issued in connection with the power purchase agreement with SCE, under the Walnut Creek credit 

facility. Certain letters of credit are subject to automatic annual renewal provisions.

Note 6. Derivative Instruments and Hedging Activities

Electric Utility

SCE uses derivative financial instruments to manage exposure to commodity price risk. SCE manages these risks in part by 

entering into forward commodity transactions, including options, swaps and futures. SCE is exposed to credit loss in the 

event of nonperformance by counterparties. To mitigate credit risk from counterparties, master netting agreements are used 

whenever possible and counterparties may be required to pledge collateral depending on the creditworthiness of each 

counterparty and the risk associated with the transaction.
117

Commodity Price Risk

SCE is exposed to commodity price risk which represents the potential impact that can be caused by a change in the market 

value of a particular commodity. SCE's hedging program reduces customer exposure to variability in market prices related to 

SCE's power and gas activities. As part of this program, SCE enters into options, swaps, forwards, tolling arrangements and 

CRRs. These transactions are approved by the CPUC or executed in compliance with CPUC-approved procurement plans. 

SCE recovers its related hedging costs through the energy resource recovery account ("ERRA") balancing account, and as a 

result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.

SCE's electricity price exposure arises from energy purchased from and sold to wholesale markets as a result of differences 

between SCE's load requirements and the amount of energy delivered from its generating facilities and power purchase 

agreements.

SCE's natural gas price exposure arises from natural gas purchased for the Mountainview power plant and peaker plants, QF 

contracts where pricing is based on a monthly natural gas index and power purchase agreements in which SCE has agreed to 

provide the natural gas needed for generation, referred to as tolling arrangements.

Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging activities:

Commodity

Electricity options, swaps and forwards

Natural gas options, swaps and forwards

Congestion revenue rights

Tolling arrangements

Unit of

Measure

GWh

Bcf

GWh

GWh

Economic Hedges

December 31,

2011

30,881

300

166,163

104,154

December 31,

2010

32,138

250

181,291

114,599

Fair Value of Derivative Instruments

The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2011:

(in millions)

Non-trading activities

Economic hedges

Netting and collateral

Total

Derivative Assets

Short-Term

$ 86

(21)

$ 65

Long-Term

$ 85

(15)

$ 70

Subtotal

$ 171

(36)

$ 135

Derivative Liabilities1

Short-Term

$ 303

(37)

$ 266

Long-Term

$ 856

(51)

$ 805

Subtotal

$ 1,159

(88)

$ 1,071

Net

Liability

$ 988

(52)

$ 936

1

 Includes the fair value of derivatives with SCE's consolidated affiliates; however, in Edison International’s consolidated financial 

statements, the fair value of such derivatives is eliminated.

The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2010:

(in millions)

Non-trading activities

Economic hedges

Netting and collateral

Total

Derivative Assets

Short-Term

$ 87

—

$ 87

Long-Term

$ 367

—

$ 367

Subtotal

$ 454

—

$ 454

Derivative Liabilities

Short-Term

$ 216

(4)

$ 212

Long-Term

$ 449

—

$ 449

Subtotal

$ 665

(4)

$ 661

Net

Liability

$ 211

(4)

$ 207

Income Statement Impact of Derivative Instruments

SCE recognizes realized gains and losses on derivative instruments as purchased power expense and expects that such gains 

or losses will be part of the purchase power costs recovered from customers. As a result, realized gains and losses are not 

reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from customers, unrealized 
118

gains and losses are recorded as regulatory assets and liabilities and therefore are also not reflected in earnings. The results of 

derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated 

statements of cash flows

The following table summarizes the components of economic hedging activity:

(in millions)

Realized gains/(losses)

Unrealized gains/(losses)

Years ended December 31,

2011

$ (165)

(768)

2010

$ (156)

36

2009

(344)

470

Contingent Features/Credit Related Exposure

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities 

contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the 

benefit of counterparties. These requirements can vary depending upon the level of unsecured credit extended by 

counterparties, changes in market prices relative to contractual commitments and other factors.

Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from 

each of the major credit rating agencies, referred to as a credit-risk-related contingent feature. If SCE's credit rating were to 

fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate 

fair value of all derivative liabilities with these credit-risk-related contingent features was $216 million and $67 million as of 

December 31, 2011 and 2010, respectively, for which SCE has posted no collateral and $4 million of collateral to its 

counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were 

triggered on December 31, 2011, SCE would be required to post $36 million of collateral.

Counterparty Default Risk Exposure

As part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, 

and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, 

SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, 

SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and 

realized gains on derivative instruments. Substantially all of the contracts that SCE has executed with counterparties are 

either entered into under SCE's procurement plan which has been pre-approved by the CPUC, or the contracts are approved 

by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not 

expected to affect earnings, but may temporarily affect cash flows.

To manage credit risk, SCE looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that

would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. To mitigate credit 

risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge 

collateral when deemed necessary.

Competitive Power Generation

EMG uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, 

capacity, fuel, emission allowances, transmission rights and interest rates. The derivative financial instruments vary in 

duration, ranging from a few days to several years, depending upon the instrument. To the extent that EMG does not use 

derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot 

market price movements.

Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not 

designated as cash flow hedges. Economic hedges are accounted for at fair value on EMG's consolidated balance sheets as 

derivative assets or liabilities with offsetting changes recorded on the consolidated statements of operations. For derivative 

instruments that qualify for hedge accounting treatment, the fair value is recognized on EMG's consolidated balance sheets as 

derivative assets or liabilities with offsetting changes in fair value, to the extent effective, recognized in accumulated other 

comprehensive loss until reclassified into earnings when the related forecasted transaction occurs. The portion of a cash flow 

hedge that does not offset the change in the fair value of the transaction being hedged, which is commonly referred to as the 

ineffective portion, is immediately recognized in earnings.

Derivative instruments that are utilized for trading purposes are measured at fair value and included on the consolidated 
119

balance sheets as derivative assets or liabilities, with offsetting changes recognized in operating revenues on the consolidated 

statements of operations.

The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash 

flows.

Where EMG's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are 

met, EMG presents its derivative assets and liabilities on a net basis on its consolidated balance sheets.

Notional Volumes of Derivative Instruments

The following table summarizes the notional volumes of derivatives used for hedging and trading activities:

December 31, 2011

Commodity

Electricity

Electricity

Electricity

Electricity

Electricity

Natural gas

Fuel oil

Instrument

Forwards/Futures

Forwards/Futures

Capacity

Capacity

Congestion

Forwards/Futures

Forwards/Futures

Classification

Sales, net

Purchases, net

Sales, net

Purchases, net

Purchases, net

Sales, net

Purchases, net

Unit of

Measure

GWh

GWh

MW-Day

(in thousands)

MW-Day

(in thousands)

GWh

bcf

barrels

Hedging Activities

Cash Flow

Hedges

8,320

—

89

—

—

—

—

1

2

Economic

Hedges

425

—

—

—

2,528

—

240,000

3

4

Trading

Activities

—

2,926

—

184

230,798

0.2

—

2

4

At December 31, 2011, EME had interest rate contracts with notional values totaling $644 million that converted floating rate 

LIBOR-based debt to fixed rates ranging from 0.79% to 4.29%. These contracts expire May 2013 through March 2026. In 

addition, EME had forward starting interest rate contracts with notional values totaling $506 million that will convert floating 

rate LIBOR-based debt to fixed rates of 3.5429% and 4.0025%. These contracts have effective dates of June 2013 and 

December 2021 and expire May 2023 and December 2029.

December 31, 2010

Commodity

Electricity

Electricity

Electricity

Electricity

Electricity

Natural gas

Fuel oil

Coal

Instrument

Forwards/Futures

Forwards/Futures

Capacity

Capacity

Congestion

Forwards/Futures

Forwards/Futures

Forwards/Futures

Classification

Sales, net

Purchases, net

Sales, net

Purchases, net

Purchases, net

Purchases, net

Purchases, net

Purchases, net

Unit of

Measure

GWh

GWh

MW-Day

(in thousands)

MW-Day

(in thousands)

GWh

bcf

barrels

tons

Hedging Activities

Cash Flow

Hedges

16,391

—

182

—

—

—

—

—

1

2

Economic

Hedges

—

475

—

—

1,007

—

240,000

—

3

4

Trading

Activities

—

3,039

—

283

175,669

3.7

—

15,000

2

4

1

 EMG's hedge products include forward and futures contracts that qualify for hedge accounting. This category excludes power 

contracts for the coal plants which meet the normal purchases and sales exception and are accounted for on the accrual method.

2

 EMG's hedge transactions for capacity result from bilateral trades. Capacity sold in the PJM Reliability Pricing Model (RPM) 

auction is not accounted for as a derivative.

3

 These positions adjust financial and physical positions, or day-ahead and real-time positions, to reduce costs or increase gross 

margin. The net sales positions of these categories are primarily related to hedge transactions that are not designated as cash flow 

hedges.
120

4

 Congestion contracts include financial transmission rights, transmission congestion contracts or congestion revenue rights. These 

positions are similar to a swap, where the buyer is entitled to receive a stream of revenues (or charges) based on the hourly dayahead price differences between two locations.

At December 31, 2010, EME had interest rate contracts with notional values totaling $328 million that converted floating rate 

LIBOR-based debt to fixed rates ranging from 3.175% to 4.29%. These contracts expire June 2016 through March 2026.

Included in trading activities in the preceding table, EME shows net the volume of energy trading activities that are 

physically settled. Gross purchases and sales totaled 3,332 GWh, 3,944 GWh and 3,791 GWh during 2011, 2010 and 2009, 

respectively.

Fair Value of Derivative Instruments

The following table summarizes the fair value of derivative instruments reflected on EMG's consolidated balance sheets:

December 31, 2011

(in millions)

Non-trading activities

Cash flow hedges

Commodity contracts

Interest rate contracts

Economic hedges

Trading activities

Netting and collateral received1

Total

Derivative Assets

Short-term

$ 41

—

31

276

348

(308)

$ 40

Long-term

$ 1

—

1

142

144

(85)

$ 59

Subtotal

$ 42

—

32

418

492

(393)

$ 99

Derivative Liabilities

Short-term

$ 2

—

26

232

260

(259)

$ 1

Long-term

$ 3

90

1

79

173

(83)

$ 90

Subtotal

$ 5

90

27

311

433

(342)

$ 91

Net Assets

(Liabilities)

$ 37

(90)

5

107

59

(51)

$ 8

December 31, 2010

(in millions)

Non-trading activities

Cash flow hedges

Commodity contracts

Interest rate contracts

Economic hedges

Trading activities

Netting and collateral received1

Total

Derivative Assets

Short-term

$ 54

—

77

184

315

(269)

$ 46

Long-term

$ 2

—

2

103

107

(37)

$ 70

Subtotal

$ 56

—

79

287

422

(306)

$ 116

Derivative Liabilities

Short-term

$ 10

—

71

148

229

(223)

$ 6

Long-term

$ 9

16

—

29

54

(35)

$ 19

Subtotal

$ 19

16

71

177

283

(258)

$ 25

Net Assets

(Liabilities)

$ 37

(16)

8

110

139

(48)

$ 91

1 Netting of derivative receivables and derivative payables and the related cash collateral received and paid is permitted when a legally 

enforceable master netting agreement exists with a derivative counterparty.
121

Income Statement Impact of Derivative Instruments

The following table provides the cash flow hedge activity as part of accumulated other comprehensive loss:

(in millions)

Beginning of period derivative gains (losses)

Effective portion of changes in fair value

Reclassification to earnings

End of period derivative gains (losses)

Cash Flow Hedge Activity1

2011

Commodity

Contracts

$ 43

55

(63)

$ 35

Interest

Rate

Contracts

$ (16)

(74)

—

$ (90)

2010

Commodity

Contracts

$ 177

106

(240)

$ 43

Interest

Rate

Contracts

$ (2)

(14)

—

$ (16)

Income Statement

Location

Competitive power

generation revenue

1 Unrealized derivative gains (losses) are before income taxes. The after-tax amounts recorded in accumulated other 

comprehensive loss at December 31, 2011 and 2010 for commodity and interest rate contracts were $21 million and 

$(55) million and $26 million and $(10) million, respectively.

For additional information, see Note 11.

EMG recorded net gains (losses) of $11 million, $(4) million and $24 million in 2011, 2010 and 2009, respectively, in 

operating revenues on the consolidated statements of operations representing the amount of cash flow hedge ineffectiveness.

The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading 

purposes on the consolidated statements of operations is presented below:

(in millions)

Economic hedges

Trading activities

Income Statement Location

Competitive power generation revenue

Fuel

Competitive power generation revenue

December 31,

2011

$ 21

3

76

2010

$ 8

2

114

Energy Trading Derivative Instruments

 The change in the fair value of energy trading derivative instruments was as follows:

(in millions)

Fair value of trading contracts at beginning of year

Net gains from energy trading activities

Amount realized from energy trading activities

Other changes in fair value

Fair value of trading contracts at end of year

Years ended December 31,

2011

$ 110

76

(84)

5

$ 107

2010

$ 122

114

(131)

5

$ 110

Contingent Features

Certain derivative instruments contain margin and collateral deposit requirements. Since EME's and its subsidiaries' credit 

ratings are below investment grade, EME and its subsidiaries have provided collateral in the form of cash and letters of credit

for the benefit of derivative counterparties. Future increases in power prices could expose EME, Midwest Generation or 

EMMT to additional collateral postings. Furthermore, EMMT has hedge contracts that do not require margin, but contain the 

right of each party to request additional credit support in the form of adequate assurance of performance in the case of 

adverse development affecting the other party. 

Commodity Price Risk Management

EMG's merchant operations are exposed to commodity price risk, which reflects the potential impact of a change in the 
122

market value of a particular commodity. Commodity price risks are actively monitored, with oversight provided by a risk 

management committee, to ensure compliance with EMG's risk management policies. EMG uses estimates of the variability 

in gross margin to help identify, measure, monitor and control its overall market risk exposure and earnings volatility with 

respect to hedge positions at the coal plants and the merchant wind projects, and uses "value at risk" metrics to help identify, 

measure, monitor and control its overall risk exposure in respect to its trading positions. These measures allow management 

to aggregate overall commodity risk, compare risk on a consistent basis and identify changes in risk factors. Value at risk 

measures the possible loss, and variability in gross margin measures the potential change in value, of an asset or position, in

each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent 

limitations of these measures and reliance on a single type of risk measurement tool, EMG supplements these approaches 

with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers and volumetric 

exposure limits. When appropriate, EMG manages the spread between the electric prices and fuel prices, and uses forward 

contracts, swaps, futures, or options contracts to achieve those objectives.

Interest Rate Risk Management

Interest rate changes affect the cost of capital needed to operate EMG's projects. EMG mitigates the risk of interest rate 

fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or 

other hedging mechanisms for a number of EMG's project financings.

Credit Risk

In conducting EMG's hedging and trading activities, EMG enters into transactions with utilities, energy companies, financial 

institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its 

trade obligation, EMG would be exposed to the risk of possible loss associated with market price changes occurring since the 

original contract was executed if the nonperforming counterparty were unable to pay the resulting damages owed to EMG. 

Further, EMG would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the 

time a counterparty defaulted.

Credit risk is measured as the loss that EMG would expect to incur if a counterparty failed to perform pursuant to the terms 

of its contractual obligations. To manage credit risk, EMG evaluates the risk of potential defaults by counterparties. To 

mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be 

required to pledge collateral when deemed necessary.

The majority of EMG's consolidated wind projects and unconsolidated affiliates that own power plants sell power under 

power purchase agreements. Generally, each project or plant sells its output to one counterparty. A default by the 

counterparty, including a default as a result of a bankruptcy, would likely have a material adverse effect on the operations of

the project or plant.

The majority of the coal for the coal plants is purchased from suppliers under contracts which may be for multiple years. 

None of the coal suppliers to the coal plants have investment grade credit ratings and, accordingly, EMG may have limited 

recourse to collect damages in the event of default by a supplier.

The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or 

transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 69%, 66% and 48% of 

EMG's consolidated operating revenues for the years ended December 31, 2011, 2010 and 2009, respectively. Moody's 

Investors Service, Inc. (Moody's) rates PJM's debt Aa3. PJM, a regional transmission organization (RTO) with over 300 

member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade 

companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At 

December 31, 2011 and 2010, EMG's account receivable due from PJM was $62 million and $64 million, respectively.

For the years ended December 31, 2011 and 2010, a second customer, Constellation Energy Commodities Group, Inc. 

accounted for less than 10% and, in 2009, 16% of EMG's consolidated operating revenues. Sales to Constellation are 

primarily generated from the coal plants and consist of energy sales under forward contracts. The contract with Constellation 

is guaranteed by Constellation Energy Group, Inc., which has a senior unsecured debt rating of BBB- by Standard & Poor's 

Ratings Services (S&P) and Baa3 by Moody's. At December 31, 2011 and 2010, EMG's account receivable due from 

Constellation was $7 million and $32 million, respectively.

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers, and cash received from counterparties 

and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on 
123

changes in the fair value of the related positions. Edison International nets counterparty receivables and payables where 

balances exist under master netting agreements. Edison International presents the portion of its margin and collateral deposits

netted with its derivative positions on its consolidated balance sheets. The following table summarizes margin and collateral 

deposits provided to and received from counterparties:

(in millions)

Collateral provided to counterparties:

Offset against derivative liabilities

Reflected in margin and collateral deposits

Collateral received from counterparties:

Offset against derivative assets

December 31,

2011

$ 53

58

53

December 31,

2010

$ 8

65

52

Note 7. Income Taxes

Current and Deferred Taxes

The sources of income (loss) before income taxes are:

(in millions)

Income (loss) from continuing operations before

income taxes

Discontinued operations before income taxes

Income (loss) before income tax

Years ended December 31,

2011

$ (264)

1

$ (263)

2010

$ 1,657

13

$ 1,670

2009

$ 854

(7)

$ 847

The components of income tax expense (benefit) by location of taxing jurisdiction are:

(in millions)

Current:

Federal

State

Deferred:

Federal

State

Total continuing operations

Discontinued operations

Total

Years ended December 31,

2011

$ (223)

36

(187)

(9)

(92)

(101)

(288)

4

$ (284)

2010

$ (432)

(86)

(518)

892

(20)

872

354

9

$ 363

2009

$ 1,211

361

1,572

(1,638)

(32)

(1,670)

(98)

(2)

$ (100)
124

The components of net accumulated deferred income tax liability are:

(in millions)

Deferred tax assets:

Property and software related

Unrealized gains and losses

Loss and credit carryforwards

Regulatory balancing accounts

Pension and PBOPs

Other

Total

Deferred tax liabilities:

Property-related

Leveraged leases

Capitalized software costs

Regulatory balancing accounts

Unrealized gains and losses

Other

Total

Accumulated deferred income tax liability – net

Classification of accumulated deferred income taxes – net:

Included in deferred credits and other liabilities

Included in current liabilities

December 31,

2011

$ 728

385

689

89

179

1,028

$ 3,098

$ 7,140

150

324

301

374

296

$ 8,585

$ 5,487

$ 5,396

$ 91

2010

$ 655

400

97

230

183

890

$ 2,455

$ 6,637

177

293

293

389

315

$ 8,104

$ 5,649

$ 5,625

$ 24

As of December 31, 2011, Edison International had $217 million of federal tax credit carryforwards of which $194 million 

expire between 2029 and 2031 and the remainder has no expiration date. Additionally, there were $476 million of net 

operating loss carryforwards of which $20 million expire between 2015 and 2023, and the remainder expire in 2031.
125

Effective Tax Rate

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the 

income tax provision from continuing operations.

(in millions)

Income (loss) from continuing operations before income taxes

Net income attributable to noncontrolling interests in the Big 4 projects

Adjusted income (loss) from continuing operations before income taxes

Provision for income tax at federal statutory rate of 35%

Increase (decrease) in income tax from:

Items presented with related state income tax, net:

Global Settlement related1

Change in tax accounting method for asset removal costs2

State tax – net of federal benefit

Employee benefits

Health care legislation3

Production and housing credits

Property-related

Other

Total income tax expense from continuing operations

Effective tax rate

Years ended December 31,

2011

$ (264)

—

$ (264)

(92)

—

—

(19)

(16)

—

(68)

(76)

(17)

$ (288)

*

2010

$ 1,657

—

$ 1,657

580

(175)

(40)

60

—

39

(66)

(47)

3

$ 354

21.4%

2009

$ 854

(48)

$ 806

282

(318)

—

48

—

—

(63)

(57)

10

$ (98)

*

*

 Not meaningful

1 Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolved federal 

tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and 

affirmative claims for tax years 1986 through 2002. Pursuant to the Global Settlement, Edison Capital terminated its interests in the 

cross-border leases and received net proceeds of $1.385 billion. The Global Settlement and termination of the Edison Capital crossborder leases resulted in a consolidated after-tax earnings charge of $254 million recorded in 2009. During 2010, Edison International 

recognized a $175 million earnings benefit from the acceptance by the California Franchise Tax Board of the IRS tax positions 

finalized in 2009 and receipt of the final interest determination from the Franchise Tax Board.

2 During the second quarter of 2010, the IRS approved Edison International's request to change its tax accounting method for asset 

removal costs primarily related to SCE's infrastructure replacement program. As a result, Edison International recognized a 

$40 million earnings benefit (of which $28 million relates to asset removal costs incurred prior to 2010) from deducting asset removal 

costs earlier in the construction cycle. These deductions were recorded on a flow-through basis as required by the CPUC.

3 During the first quarter of 2010, Edison International recorded a $39 million non-cash charge to reverse previously recognized federal 

tax benefits eliminated by the federal health care legislation enacted in March 2010. The health care law eliminated the federal tax 

deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies.

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.

Accounting for Uncertainty in Income Taxes

Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its 

financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence 

indicates it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination. 

The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax 

positions on filed tax returns and the unrecognized portion of affirmative claims.
126

Unrecognized Tax Benefits

The following table provides a reconciliation of unrecognized tax benefits:

(in millions)

Balance at January 1,

Tax positions taken during the current year:

Increases

Tax positions taken during a prior year:

Increases

Decreases

Decreases for settlements during the period

Balance at December 31,

2011

$ 565

39

102

(75)

—

$ 631

2010

$ 664

42

273

(332)

(82)

$ 565

2009

$ 2,237

102

201

(224)

(1,652)

$ 664

As of December 31, 2011 and 2010, $532 million and $455 million, respectively, of the unrecognized tax benefits, if 

recognized, would impact the effective tax rate.

Edison International's federal income tax returns and its California combined franchise tax returns are currently open for 

years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 

2002 are currently under review by the Franchise Tax Board. The IRS examination phase of tax years 2003 through 2006 was 

completed in the fourth quarter of 2010, which included proposed adjustments for the following two items:

• A proposed adjustment increasing the taxable gain on the 2004 sale of EMG's international assets, which if sustained, 

would result in a federal tax payment of approximately $193 million, including interest and penalties through 

December 31, 2011 (the IRS has asserted a 40% penalty for understatement of tax liability related to this matter).

• A proposed adjustment to disallow a component of SCE's repair allowance deduction, which if sustained, would result in 

a federal tax payment of approximately $93 million, including interest through December 31, 2011.

Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011.

Accrued Interest and Penalties

The total amount of accrued interest and penalties related to Edison International's income tax liabilities was $242 million 

and $213 million as of December 31, 2011 and 2010, respectively.

The net after-tax interest and penalties recognized in income tax expense was $18 million in 2011, compared to a benefit of 

$153 million and $80 million in 2010 and 2009, respectively.

Repair Deductions

In 2009, Edison International made a voluntary election to change its tax accounting method for certain repair costs incurred 

on SCE's transmission, distribution and generation assets. The change in tax accounting method resulted in a $192 million 

cash benefit realized in the fourth quarter of 2009. In August of 2011 the IRS issued guidance on repair deductions and 

changes in accounting method related to transmission and distribution assets. Based on this guidance, SCE will include a 

second change in tax accounting method in its 2011 tax return. SCE does not expect any cash impact in 2011 due to its 

current net operating loss position. Regulatory treatment for the incremental deductions taken after the voluntary election to 

change SCE's tax accounting method for certain repair costs will be addressed in SCE's 2012 GRC. Due to the pending 

regulatory decision, SCE has not recognized an earnings benefit or regulatory asset related to this method change and 

incremental deductions taken in 2009, 2010 and 2011.

Note 8. Compensation and Benefit Plans

Employee Savings Plan

Edison International has a 401(k) defined contribution savings plan designed to supplement employees' retirement income. 

The plan received employer contributions of $99 million in 2011, $80 million in 2010 and $83 million in 2009.
127

Pension Plans and Postretirement Benefits Other Than Pensions

Pension Plans

Noncontributory defined benefit pension plans (some with cash balance features) cover most employees meeting minimum 

service requirements. SCE recognizes pension expense for its nonexecutive plan as calculated by the actuarial method used 

for ratemaking. The expected contributions (all by the employer) are approximately $286 million for the year ending 

December 31, 2012. Annual contributions made to most of SCE's pension plans are currently recovered through CPUCapproved regulatory mechanisms. Annual contributions to these plans are expected to be, at a minimum, equal to the related 

annual expense.

The funded position of Edison International's pension is very sensitive to changes in market conditions. Changes in overall 

interest rate levels significantly affect the company's liabilities, while assets held in the various trusts established to fund 

Edison International's long-term pension are affected by movements in the equity and bond markets. The market value of the 

investments (reflecting investment returns, contributions and benefit payments) within the plan trusts declined 35% during 

2008. This reduction in value of plan assets combined with increased liabilities has resulted in a change in the pension plan 

funding status from a surplus to a material deficit, which will result in increased future expense and cash contributions. The 

Edison International pension remains underfunded as liabilities have increased significantly as a result of steady declines in 

interest rates. Due to SCE's regulatory recovery treatment, the unfunded status is offset by a regulatory asset. In the 2009 

GRC, SCE requested recovery of and continued balancing account treatment for amounts contributed to these trusts. SCE 

requested the continuation of this approach in the 2012 GRC.
128

Information on plan assets and benefit obligations is shown below:

(in millions)

Change in projected benefit obligation

Projected benefit obligation at beginning of year

Service cost

Interest cost

Amendments

Actuarial loss

Benefits paid

Projected benefit obligation at end of year

Change in plan assets

Fair value of plan assets at beginning of year

Actual return on plan assets

Employer contributions

Benefits paid

Fair value of plan assets at end of year

Funded status at end of year

Amounts recognized in the consolidated balance sheets consist of:

Current liabilities

Long-term liabilities

Amounts recognized in accumulated other comprehensive loss consist of:

Prior service cost

Net loss

Amounts recognized as a regulatory asset:

Prior service cost

Net loss

Total not yet recognized as expense

Accumulated benefit obligation at end of year

Pension plans with an accumulated benefit obligation in excess of plan assets:

Projected benefit obligation

Accumulated benefit obligation

Fair value of plan assets

Weighted-average assumptions used to determine obligations at end of year:

Discount rate

Rate of compensation increase

Years ended December 31,

2011

$ 4,080

165

210

—

327

(289)

$ 4,493

$ 3,235

61

146

(289)

$ 3,153

$ (1,340)

$ (11)

(1,329)

$ (1,340)

$ 1

139

$ 140

$ 34

955

$ 989

$ 1,129

$ 4,157

$ 4,493

4,157

3,153

4.5%

4.5%

2010

$ 3,688

149

210

6

210

(183)

$ 4,080

$ 2,857

434

127

(183)

$ 3,235

$ (845)

$ (12)

(833)

$ (845)

$ 1

116

$ 117

$ 40

500

$ 540

$ 657

$ 3,736

$ 4,080

3,736

3,235

5.25%

5.0%
129

Expense components and other amounts recognized in other comprehensive income:

Expense components are:

(in millions)

Service cost

Interest cost

Expected return on plan assets

Amortization of prior service cost

Amortization of net loss

Expense under accounting standards

Regulatory adjustment – deferred

Total expense recognized

Years ended December 31,

2011

$ 165

210

(238)

7

28

$ 172

(28)

$ 144

2010

$ 149

210

(210)

8

22

$ 179

(52)

$ 127

2009

124

207

(169)

11

61

$ 234

(94)

140

Other changes in plan assets and benefit obligations recognized in other comprehensive income:

(in millions)

Net loss

Amortization of prior service cost

Amortization of net loss

Total recognized in other comprehensive loss

Total recognized in expense and other comprehensive income

Years ended December 31,

2011

$ 35

—

(13)

$ 22

$ 166

2010

$ 30

(1)

(10)

$ 19

$ 146

2009

$ 17

(1)

(11)

$ 5

$ 145

In accordance with authoritative guidance on rate-regulated enterprises, Edison International records regulatory assets and 

liabilities instead of charges and credits to other comprehensive income (loss) for the portion of SCE's postretirement benefit

plans that are recoverable in utility rates. The estimated net loss and prior service cost that will be amortized to expense in

2012 are $67 million and $4 million, respectively; $17 million of the net loss is expected to be reclassified from accumulated 

other comprehensive loss.

The following are weighted-average assumptions used to determine expense:

Discount rate

Rate of compensation increase

Expected return on plan assets

Years ended December 31,

2011

5.25%

5.0%

7.5%

2010

6.0%

5.0%

7.5%

2009

6.25%

5.0%

7.5%

The following benefit payments, which reflect expected future service, are expected to be paid:

(in millions)

2012

2013

2014

2015

2016

2017 – 2021

Years ended

December 31,

$ 302

310

316

329

338

1,738
130

Postretirement Benefits Other Than Pensions

Most non-union employees retiring at or after age 55 with at least 10 years of service may be eligible for postretirement 

medical, dental, vision and life insurance and other benefits. Eligibility for a company contribution toward the cost of these 

benefits in retirement depends on a number of factors, including the employee's hire date. The expected contributions (all by 

the employer) to the PBOP trust are $65 million for the year ending December 31, 2012. Annual contributions made to SCE 

plans are currently recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to 

the total annual expense for these plans.

The funded position of Edison International's PBOP is very sensitive to changes in market conditions. Changes in overall 

interest rate levels significantly affect the company's liabilities, while assets held in the various trusts established to fund 

Edison International's other postretirement benefits are affected by movements in the equity and bond markets. The market 

value of the investments (reflecting investment returns, contributions and benefit payments) within the plan trust declined 

33% during 2008. This reduction in the value of plan assets resulted in an increase in the plan's underfunded status and will 

also result in increased future expense and increased future contributions. Edison International's PBOP is underfunded as 

liabilities have increased significantly as a result of steady declines in interest rates. Due to SCE's regulatory recovery 

treatment, the unfunded status is offset by a regulatory asset. In the 2009 GRC, SCE requested recovery of and continued 

balancing account treatment for amounts contributed to this trust. SCE requested the continuation of this approach in the 

2012 GRC.
131

Information on plan assets and benefit obligations is shown below:

(in millions)

Change in benefit obligation

Benefit obligation at beginning of year

Service cost

Interest cost

Amendments

Actuarial loss

Plan participants' contributions

Medicare Part D subsidy received

Benefits paid

Benefit obligation at end of year

Change in plan assets

Fair value of plan assets at beginning of year

Actual return on assets

Employer contributions

Plan participants' contributions

Medicare Part D subsidy received

Benefits paid

Fair value of plan assets at end of year

Funded status at end of year

Amounts recognized in the consolidated balance sheets consist of:

Current liabilities

Long-term liabilities

Amounts recognized in accumulated other comprehensive loss (income)

consist of:

Prior service cost (credit)

Net loss

Amounts recognized as a regulatory asset (liability):

Prior service credit

Net loss

Total not yet recognized as expense

Weighted-average assumptions used to determine obligations at end of year:

Discount rate

Assumed health care cost trend rates:

Rate assumed for following year

Ultimate rate

Year ultimate rate reached

Years ended December 31,

2011

$ 2,425

43

121

—

47

18

5

(106)

$ 2,553

$ 1,606

11

36

18

5

(106)

$ 1,570

$ (983)

$ (19)

(964)

$ (983)

$ 8

27

$ 35

$ (125)

839

$ 714

$ 749

4.75%

9.50%

5.25%

2019

2010

$ 2,110

37

127

23

216

17

5

(110)

$ 2,425

$ 1,459

175

60

17

5

(110)

$ 1,606

$ (819)

$ (20)

(799)

$ (819)

$ 7

28

$ 35

$ (161)

718

$ 557

$ 592

5.5%

9.75%

5.5%

2019
132

Expense components and other amounts recognized in other comprehensive income:

Expense components are:

(in millions)

Service cost

Interest cost

Expected return on plan assets

Amortization of prior service credit

Amortization of net loss

Total expense

Years ended December 31,

2011

$ 43

121

(111)

(36)

27

$ 44

2010

$ 37

127

(101)

(38)

36

$ 61

2009

30

122

(81)

(34)

45

$ 82

Other changes in plan assets and benefit obligations recognized in other comprehensive income:

(in millions)

Net loss (gain)

Prior service cost (credit)

Amortization of prior service credit

Amortization of net loss

Total recognized in other comprehensive income

Total recognized in expense and other comprehensive income

Years ended December 31,

2011

$ (1)

—

1

(1)

$ (1)

$ 43

2010

$ 13

11

2

(1)

$ 25

$ 86

2009

$ (8)

(3)

2

(1)

$ (10)

$ 72

In accordance with authoritative guidance on rate-regulated enterprises, Edison International records regulatory assets and 

liabilities instead of charges and credits to other comprehensive income (loss) for the portion of SCE's postretirement benefit

plans that are recoverable in utility rates. The estimated net loss and prior service cost (credit) that will be amortized to 

expense in 2012 are $46 million and $(35) million, respectively, including $2 million and zero, respectively, expected to be 

reclassified from accumulated other comprehensive loss.

The following are weighted-average assumptions used to determine expense:

Discount rate

Expected long-term return on plan assets

Assumed health care cost trend rates:

Current year

Ultimate rate

Year ultimate rate reached

Years ended December 31,

2011

5.5%

7.0%

9.75%

5.5%

2019

2010

6.0%

7.0%

8.25%

5.5%

2016

2009

6.25%

7.0%

8.75%

5.5%

2016

Increasing the health care cost trend rate by one percentage point would increase the accumulated benefit obligation as of 

December 31, 2011 by $297 million and annual aggregate service and interest costs by $16 million. Decreasing the health 

care cost trend rate by one percentage point would decrease the accumulated benefit obligation as of December 31, 2011 by 

$247 million and annual aggregate service and interest costs by $13 million.
133

The following benefit payments are expected to be paid:

(in millions)

2012

2013

2014

2015

2016

2017 – 2021

Year ending December 31,

Before 

Subsidy1

$ 100

108

117

126

136

809

Net

$ 94

102

110

119

128

755

1 Medicare Part D prescription drug benefits

Plan Assets

Description of Pension and Postretirement Benefits Other than Pensions Investment Strategies

The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination 

of asset classes, and may have active and passive investment strategies within asset classes. Target allocations for pension 

plan assets are 30% for U.S. equities, 16% for non-U.S. equities, 35% for fixed income, 15% for opportunistic and/or 

alternative investments and 4% for other investments. Target allocations for PBOP plan assets are 41% for U.S. equities, 17% 

for non-U.S. equities, 34% for fixed income, 7% for opportunistic and/or alternative investments, and 1% for other 

investments. Edison International employs multiple investment management firms. Investment managers within each asset 

class cover a range of investment styles and approaches. Risk is managed through diversification among multiple asset 

classes, managers, styles and securities. Plan, asset class and individual manager performance is measured against targets. 

Edison International also monitors the stability of its investment managers' organizations.

Allowable investment types include:

• United States Equities: Common and preferred stocks of large, medium, and small companies which are predominantly 

United States-based.

• Non-United States Equities: Equity securities issued by companies domiciled outside the United States and in depository 

receipts which represent ownership of securities of non-United States companies.

• Fixed Income: Fixed income securities issued or guaranteed by the United States government, non-United States 

governments, government agencies and instrumentalities including municipal bonds, mortgage backed securities and 

corporate debt obligations. A portion of the fixed income positions may be held in debt securities that are below 

investment grade.

Opportunistic, Alternative and Other Investments:

• Opportunistic: Investments in short to intermediate term market opportunities. Investments may have fixed income and/

or equity characteristics and may be either liquid or illiquid.

• Alternative: Limited partnerships that invest in non-publicly traded entities.

• Other: Investments diversified among multiple asset classes such as global equity, fixed income currency and 

commodities markets. Investments are made in liquid instruments within and across markets. The investment returns are 

expected to approximate the plans' expected investment returns.

Asset class portfolio weights are permitted to range within plus or minus 3%. Where approved by the fiduciary investment 

committee, futures contracts are used for portfolio rebalancing and to reallocate portfolio cash positions. Where authorized, a

few of the plans' investment managers employ limited use of derivatives, including futures contracts, options, options on 

futures and interest rate swaps in place of direct investment in securities to gain efficient exposure to markets. Derivatives are 

not used to leverage the plans or any portfolios.
134

Determination of the Expected Long-Term Rate of Return on Assets

The overall expected long-term rate of return on assets assumption is based on the long-term target asset allocation for plan 

assets and capital markets return forecasts for asset classes employed. A portion of the PBOP trust asset returns are subject to 

taxation, so the expected long-term rate of return for these assets is determined on an after-tax basis.

Capital Markets Return Forecasts

Our capital markets return forecast methodologies primarily use a combination of historical market data, current market 

conditions, proprietary forecasting expertise, complex models to develop asset class return forecasts and a building block 

approach. The forecasts are developed using variables such as real risk-free interest, inflation, and asset class specific risk 

premiums. For equities, the risk premium is based on an assumed average equity risk premium of 6% over cash. The 

forecasted return on private equity and opportunistic investments are estimated at a 3% premium above public equity, 

reflecting a premium for higher volatility and liquidity. For fixed income, the risk premium is based off of a comprehensive 

modeling of credit spreads.

Fair Value of Plan Assets

The PBOP Plan and the Southern California Edison Company Retirement Plan Trust (Master Trust) assets include 

investments in equity securities, U.S. treasury securities, other fixed-income securities, common/collective funds, mutual 

funds, other investment entities, foreign exchange and interest rate contracts, and partnership/joint ventures. Equity securities, 

U.S. treasury securities, mutual and money market funds are classified as Level 1 as fair value is determined by observable, 

unadjusted quoted market prices in active or highly liquid and transparent markets. Common/collective funds are valued at 

the net asset value ("NAV") of shares held. Although common/collective funds are determined by observable prices, they are 

classified as Level 2 because they trade in markets that are less active and transparent. The fair value of the underlying 

investments in equity mutual funds and equity common/collective funds are based upon stock-exchange prices. The fair value 

of the underlying investments in fixed-income common/collective funds, fixed-income mutual funds and other fixed income 

securities including municipal bonds are based on evaluated prices that reflect significant observable market information such 

as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, 

offers and relevant credit information. Foreign exchange and interest rate contracts are classified as Level 2 because the 

values are based on observable prices but are not traded on an exchange. Futures contracts trade on an exchange and therefore 

are classified as Level 1. One of the partnerships is classified as Level 2 since this investment can be readily redeemed at 

NAV and the underlying investments are liquid, publicly traded fixed-income securities which have observable prices. The 

remaining partnerships/joint ventures are classified as Level 3 because fair value is determined primarily based upon 

management estimates of future cash flows. Other investment entities are valued similarly to common collective funds and 

are therefore classified as Level 2. The Level 1 registered investment companies are either mutual or money market funds. 

The remaining funds in this category are readily redeemable at NAV and classified as Level 2 and are discussed further at 

footnote 7 to the pension plan master trust investments table below.

Edison International reviews the process/procedures of both the pricing services and the trustee to gain an understanding of 

the inputs/assumptions and valuation techniques used to price each asset type/class. The trustee and Edison International's 

validation procedures for pension and PBOP equity and fixed income securities are the same as the nuclear decommissioning 

trusts. For further discussion see Note 4. The values of Level 1 mutual and money market funds are publicly quoted. The 

trustees obtain the values of common/collective and other investment funds from the fund managers. The values of 

partnerships are based on partnership valuation statements updated for cash flows. SCE's investment managers corroborate 

the trustee fair values.
135

Pension Plan

The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 2011 by 

asset class and level within the fair value hierarchy:

(in millions)

Corporate stocks1

Partnerships/joint ventures2

Common/collective funds3

Corporate bonds4

U.S. government and agency securities5

Other investment entities6

Registered investment companies7

Interest-bearing cash

Other

Total

Receivables and payables, net

Net plan assets available for benefits

Level 1

$ 642

—

—

—

104

—

79

5

(1)

$ 829

Level 2

$ —

140

582

497

351

247

29

—

69

$ 1,915

Level 3

$ —

448

—

—

—

—

—

—

—

$ 448

Total

$ 642

588

582

497

455

247

108

5

68

$ 3,192

(39)

$ 3,153

The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 2010 by 

asset class and level within the fair value hierarchy:

(in millions)

Corporate stocks1

Partnerships/joint ventures2

Common/collective funds3

Corporate bonds4

U.S. government and agency securities5

Other investment entities6

Registered investment companies7

Interest-bearing cash

Other

Total

Receivables and payables, net

Net plan assets available for benefits

Level 1

$ 786

—

—

—

84

—

84

5

2

$ 961

Level 2

$ —

155

600

555

316

236

92

—

30

$ 1,984

Level 3

$ —

345

—

—

—

—

—

—

—

$ 345

Total

$ 786

500

600

555

400

236

176

5

32

$ 3,290

(55)

$ 3,235

1 Corporate stocks are diversified. For 2011 and 2010, respectively, performance is primarily benchmarked against the Russell 

Indexes (60% and 63%) and Morgan Stanley Capital International (MSCI) index (40% and 37%).

2 Partnerships/joint venture Level 2 investments consist primarily of a partnership which invests in publicly traded fixed income

securities, primarily from the banking and finance industry and U.S. government agencies. At December 31, 2011 and 2010, 

respectively, approximately 55% and 60% of the Level 3 partnerships are invested in (1) asset backed securities, including 

distressed mortgages and (2) commercial and residential loans and debt and equity of banks. The remaining Level 3 partnerships 

are invested in small private equity and venture capital funds. Investment strategies for these funds include branded consumer 

products, early stage technology, California geographic focus, and diversified US and non-US fund-of-funds.

3 At December 31, 2011 and 2010, respectively, the common/collective assets were invested in equity index funds that seek to 

track performance of the Standard and Poor's (S&P 500) Index (29% and 29%), Russell 200 and Russell 1000 indexes (27% and 

28%) and the MSCI Europe, Australasia and Far East (EAFE) Index (10% and 11%). A non-index U.S. equity fund representing 

23% of this category for both 2011 and 2010 is actively managed. Another fund representing 8% of this category for both 2011 

and 2010 is a global asset allocation fund.

4 Corporate bonds are diversified. At December 31, 2011 and 2010, respectively, this category includes $53 million and 

$65 million for collateralized mortgage obligations and other asset backed securities of which $10 million and $17 million are 

below investment grade.
136

5 Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relates to the Federal 

National Mortgage Association and the Federal Home Loan Mortgage Corporation.

6 Other investment entities were primarily invested in (1) emerging market equity securities, (2) a hedge fund that invests through 

liquid instruments in a global diversified portfolio of equity, fixed income, interest rate, foreign currency and commodities 

markets, and (3) domestic mortgage backed securities.

7 Level 1 of registered investment companies consisted of a global equity mutual fund which seeks to outperform the MSCI World 

Total Return Index. Level 2 primarily consisted of short-term, emerging market, high yield bond funds and government inflationindexed bonds.

At both December 31, 2011 and 2010, approximately 69% of the publicly traded equity investments, including equities in the 

common/collective funds, were located in the United States.

The following table sets forth a summary of changes in the fair value of Level 3 investments for 2011 and 2010:

(in millions)

Fair value, net at beginning of period

Actual return on plan assets:

Relating to assets still held at end of period

Relating to assets sold during the period

Purchases

Dispositions

Transfers in and /or out of Level 3

Fair value, net at end of period

2011

$ 345

6

22

130

(55)

—

$ 448

2010

$ 240

42

24

108

(69)

—

$ 345

Postretirement Benefits Other than Pensions

The following table sets forth the PBOP Plan's financial assets that were accounted for at fair value as of December 31, 2011 

by asset class and level within the fair value hierarchy:

(in millions)

Common/collective funds1

Corporate stocks2

Corporate notes and bonds3

Partnerships4

U.S. government and agency securities5

Registered investment companies6

Interest bearing cash

Other7

Total

Receivables and payables, net

Combined net plan assets available for benefits

Level 1

$ —

319

—

—

100

80

12

4

$ 515

Level 2

$ 642

—

177

16

42

—

—

71

$ 948

Level 3

$ —

—

—

130

—

—

—

—

$ 130

Total

$ 642

319

177

146

142

80

12

75

$ 1,593

(23)

$ 1,570
137

The following table sets forth the PBOP Plan's financial assets that were accounted for at fair value as of December 31, 2010 

by asset class and level within the fair value hierarchy:

(in millions)

Common/collective funds1

Corporate stocks2

Corporate notes and bonds3

Partnerships4

U.S. government and agency securities5

Registered investment companies6

Interest bearing cash

Other7

Total

Receivables and payables, net

Combined net plan assets available for benefits

Level 1

$ —

344

—

—

50

144

12

4

$ 554

Level 2

$ 657

—

184

16

38

1

—

76

$ 972

Level 3

$ —

—

—

92

—

—

—

—

$ 92

Total

$ 657

344

184

108

88

145

12

80

$ 1,618

(12)

$ 1,606

1 At December 31, 2011 and 2010, respectively, 63% and 61% of the common/collective assets are invested in a large cap index fund

which seeks to track performance of the Russell 1000 index. 21% and 23% of the assets in this category are in index funds which seek 

to track performance in the MSCI Europe, Australasia and Far East (EAFE) Index. 6% and 7% of this category are invested in a 

privately managed bond fund and 6% and 6% in a fund which invests in equity securities the fund manager believes are undervalued.

2 Corporate stock performance is primarily benchmarked against the Russell Indexes (53% and 54%) and the MSCI All Country World 

(ACWI) index (47% and 46%) for 2011 and 2010, respectively.

3 Corporate notes and bonds are diversified and include approximately $14 million and $15 million for commercial collateralized 

mortgage obligations and other asset backed securities at December 31, 2011 and 2010, respectively.

4 At December 31, 2011 and 2010, respectively, 81% and 84% of the Level 3 partnerships category is invested in (1) asset backed 

securities including distressed mortgages, (2) distressed companies and (3) commercial and residential loans and debt and equity of 

banks.

5 Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relates to the Federal Home Loan 

Mortgage Corporation and the Federal National Mortgage Association.

6 Level 1 registered investment companies consist of an investment grade corporate bond mutual fund and a money market fund.

7 Other includes $60 million and $64 million of municipal securities at December 31, 2011 and 2010, respectively.

At December 31, 2011 and 2010, approximately 69% and 67%, respectively, of the publicly traded equity investments, 

including equities in the common/collective funds, were located in the United States.

The following table sets forth a summary of changes in the fair value of PBOP Level 3 investments for 2011 and 2010:

(in millions)

Fair value, net at beginning of period

Actual return on plan assets

Relating to assets still held at end of period

Relating to assets sold during the period

Purchases

Dispositions

Transfers in and /or out of Level 3

Fair value, net at end of period

2011

$ 92

(3)

6

48

(13)

—

$ 130

2010

$ 49

14

—

46

(17)

—

$ 92
138

Stock-Based Compensation

Edison International maintains a shareholder approved incentive plan (the 2007 Performance Incentive Plan) that includes 

stock-based compensation. The maximum number of shares of Edison International's common stock authorized to be issued 

or transferred pursuant to awards under the 2007 Performance Incentive Plan, as amended in 2009 and 2011, is 49.5 million 

shares, plus the number of any shares subject to awards issued under Edison International's prior plans and outstanding as of 

April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued ("carry-over shares"). As of 

December 31, 2011, Edison International had approximately 30 million shares remaining for future issuance under its stockbased compensation plans.

Stock Options

Under various plans, Edison International has granted stock options at exercise prices equal to the average of the high and 

low price and, beginning in 2007, at the closing price at the grant date. Edison International may grant stock options and 

other awards related to or with a value derived from its common stock to directors and certain employees. Options generally 

expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized 

evenly over the requisite service period, except for awards granted to retirement-eligible participants, as discussed in "StockBased Compensation" in Note 1. Stock options granted in 2003 through 2006 accrue dividend equivalents for the first five 

years of the option term. Stock options granted in 2007 and later have no dividend equivalent rights except for options 

granted to Edison International's Board of Directors in 2007. Unless transferred to nonqualified deferral plan accounts, 

dividend equivalents accumulate without interest. Dividend equivalents are paid in cash after the vesting date. Edison 

International has discretion to pay certain dividend equivalents in shares of Edison International common stock. Additionally, 

Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.

The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The 

Black-Scholes option-pricing model requires various assumptions noted in the following table:

Expected terms (in years)

Risk-free interest rate

Expected dividend yield

Weighted-average expected dividend yield

Expected volatility

Weighted-average volatility

Years ended December 31,

2011

7.0

1.4% – 3.1%

3.1% – 3.5%

3.4%

18.2% – 19.0%

18.9%

2010

7.3

2.0% – 3.2%

3.3% – 4.0%

3.8%

18.8% – 19.8%

19.8%

2009

7.4

2.8% – 3.5%

3.6% – 5.0%

4.9%

20% – 21%

20.6%

The expected term represents the period of time for which the options are expected to be outstanding and is primarily based 

on historical exercise and post-vesting cancellation experience and stock price history. The risk-free interest rate for periods 

within the contractual life of the option is based on a zero coupon U.S. Treasury issued STRIPS (separate trading of 

registered interest and principal of securities) whose maturity equals the option's expected term on the measurement date. 

Expected volatility is based on the historical volatility of Edison International's common stock for the length of the option's

expected term for 2011. The volatility period used was 84 months, 87 months and 84 months at December 31, 2011, 2010 and 

2009, respectively.
139

The following is a summary of the status of Edison International stock options:

Outstanding at December 31, 2010

Granted

Expired

Forfeited

Exercised

Outstanding at December 31, 2011

Vested and expected to vest at December 31, 2011

Exercisable at December 31, 2011

Stock

options

19,142,209

3,467,254

(200,075)

(387,284)

(2,307,890)

19,714,214

19,242,454

11,238,882

Weighted-Average

Exercise

Price

$ 33.28

38.02

48.85

33.16

25.59

34.86

34.88

35.52

Remaining

Contractual

Term (Years)

5.94

5.89

4.36

Aggregate

Intrinsic 

Value

(in millions)

$ 156

93

At December 31, 2011, there was $20 million of total unrecognized compensation cost related to stock options, net of 

expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately two years.

Performance Shares

A target number of contingent performance shares were awarded to executives in March 2009, March 2010 and March 2011, 

and vest at the end of December 2011, 2012 and 2013, respectively. Performance shares awarded contain dividend equivalent 

reinvestment rights. An additional number of target contingent performance shares will be credited based on dividends on 

Edison International common stock for which the ex-dividend date falls within the performance period. The vesting of 

Edison International's performance shares is dependent upon a market condition and three years of continuous service subject 

to a prorated adjustment for employees who are terminated under certain circumstances or retire, but payment cannot be 

accelerated. The market condition is based on Edison International's total shareholder return relative to the total shareholder

return of a specified group of peer companies at the end of a three-calendar-year period. The number of performance shares 

earned is determined based on Edison International's ranking among these companies. Performance shares earned are settled 

half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the 

half subject to cash settlement in common stock. Edison International also has discretion to pay certain dividend equivalents 

in Edison International common stock. Additionally, cash awards are substituted to the extent necessary to pay tax 

withholding or any government levies. The portion of performance shares that can be settled in cash is classified as a sharebased liability award. The fair value of these shares is remeasured at each reporting period and the related compensation 

expense is adjusted. The portion of performance shares payable in common stock is classified as a share-based equity award. 

Compensation expense related to these shares is based on the grant-date fair value. Performance shares expense is recognized 

ratably over the requisite service period based on the fair values determined, except for awards granted to retirement-eligible

participants.
140

The fair value of performance shares is determined using a Monte Carlo simulation valuation model. The Monte Carlo 

simulation valuation model requires various assumptions noted in the following table.

Equity awards

Grant date risk-free interest rate

Grant date expected volatility

Liability awards1

Expected volatility

Risk-free interest rate:

2011 awards

2010 awards

2009 awards

Years ended December 31,

2011

1.2%

20.4%

15.9%

0.3%

0.2%

—%

2010

1.3%

21.6%

20.6%

—%

0.6%

0.3%

2009

1.3%

21.4%

21.9%

—%

—%

1.1%

1 The portion of performance shares classified as share-based liability awards are revalued at each reporting period.

The risk-free interest rate is based on the daily spot rate on the grant or valuation date on U.S. Treasury zero coupon issue or 

STRIPS with terms nearest to the remaining term of the performance shares and is used as a proxy for the expected return for 

the specified group of peer companies. Expected volatility is based on the historical volatility of Edison International's (and

the specified group of peer companies') common stock for the most recent 36 months. Historical volatility for each company 

in the specified group is obtained from a financial data services provider.

The following is a summary of the status of Edison International nonvested performance shares:

Nonvested at December 31, 2010

Granted

Forfeited1

Nonvested at December 31, 2011

Equity Awards

Shares

415,028

156,765

(120,244)

451,549

WeightedAverage

Grant Date

Fair Value

$ 30.99

29.97

42.60

27.92

Liability Awards

Shares

415,028

156,765

(120,244)

451,549

WeightedAverage

Fair Value

$ 34.74

29.61

1

 Includes performance shares that expired with zero value as performance targets were not met.

The current portion of nonvested performance shares classified as liability awards is reflected in "Other current liabilities" 

and the long-term portion is reflected in "Pensions and benefits" on the consolidated balance sheets.

At December 31, 2011, there was $4 million (based on the December 31, 2011 fair value of performance shares classified as 

equity awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized 

over a weighted-average period of approximately two years. 

Restricted Stock Units

Restricted stock units were awarded to executives in March 2009, March 2010 and March 2011 and vest and become payable 

in January 2012, 2013 and 2014, respectively. Each restricted stock unit awarded is a contractual right to receive one share of

Edison International common stock, if vesting requirements are satisfied. Restricted stock units awarded contain dividend 

equivalent reinvestment rights. An additional number of restricted stock units will be credited based on dividends on Edison 

International common stock for which the ex-dividend date falls within the performance period. The vesting of Edison 

International's restricted stock units is dependent upon continuous service through the end of the three-calendar-year-plustwo-days vesting period. Vesting is subject to a pro-rated adjustment for employees who are terminated under certain 

circumstances or retire. Cash awards are substituted to the extent necessary to pay tax withholding or any government levies.
141

The following is a summary of the status of Edison International nonvested restricted stock units:

Nonvested at December 31, 2010

Granted

Forfeited

Paid Out

Nonvested at December 31, 2011

Restricted

Stock Units

644,796

256,208

(27,813)

(135,556)

737,635

WeightedAverage

Grant Date

Fair Value

$ 32.18

38.01

32.19

47.42

$ 32.20

The fair value for each restricted stock unit awarded is determined as the closing price of Edison International common stock 

on the grant date.

Compensation expense related to these shares, which is based on the grant-date fair value, is recognized ratably over the 

requisite service period, except for awards whose holders become eligible for retirement vesting during the service period, in 

which case recognition is accelerated into the year the holders become eligible for retirement vesting. At December 31, 2011, 

there was $8 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, 

which is expected to be recognized as follows: $3 million in 2012 and $5 million in 2013.

Supplemental Data on Stock Based Compensation

(in millions, except per award amounts)

Stock Based Compensation Expense1

Stock options

Performance shares

Restricted stock units

Other

Total stock based compensation expense

Income tax benefits related to stock compensation expense

Excess tax benefits2

Stock options

Weighted average grant date fair value per option granted

Fair value of options vested

Cash used to purchase shares to settle options

Cash from participants to exercise stock options

Value of options exercised

Tax benefits from options exercised

Performance Shares3

 Classified as Equity Awards

Weighted average grant date fair value per share granted

Fair value of shares vested

Restricted Stock units

Values of shares settled

Tax benefits realized from settlement of awards

Weighted average grant date fair value per unit granted

Years ended December 31,

2011

$ 16

6

8

7

$ 37

$ 15

13

$ 5.61

18

90

59

31

12

$ 29.97

4

$ 6

3

38.01

2010

$ 18

10

7

9

$ 44

$ 17

8

$ 4.89

18

61

38

23

9

$ 32.25

4

$ —

—

32.12

2009

$ 13

5

5

10

$ 33

$ 13

9

$ 3.05

14

25

13

12

5

$ 21.42

1

$ —

—

25.21

1 Reflected in "Operations and maintenance" on the consolidated statements of income.

2 Reflected in "Settlements of stock based compensation – net" in the financing section of the consolidated statements of 

cash flows.

3 There were no settlements of awards for performance shares in 2011, 2010 and 2009 as performance targets were not 

met.
142

Note 9. Commitments and Contingencies

Third-Party Power Purchase Agreements

SCE enters into various agreements to purchase power and electric capacity, including:

• Renewable Energy Contracts – California law requires retail sellers of electricity to comply with an RPS by delivering 

renewable energy, primarily through power purchase contracts. Renewable energy contract payments generally consist of 

payments based on a fixed price per megawatt hour. As of December 31, 2011, SCE had 68 renewable energy contracts 

that were approved by the CPUC and met critical contract provisions which expire at various dates between 2012 and 

2035.

• Qualifying Facility Power Purchase Agreements – Under the Public Utility Regulatory Policies Act of 1978 ("PURPA"), 

electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that 

are qualifying co-generation facilities and qualifying small power production facilities ("QFs"). As of December 31, 

2011, SCE had 171 QF contracts which expire at various dates between 2012 and 2025.

• Other Power Purchase Agreements – In accordance with the SCE's CPUC-approved long-term procurement plans, SCE 

has entered into capacity agreements with third parties, including 15 tolling arrangements, 40 power call options and 143 

resource adequacy contracts. SCE's obligations under a portion of these agreements are limited to payments for the 

availability of such resources.

At December 31, 2011, the undiscounted future minimum expected payments for power purchase agreements that have been 

approved by the CPUC and have completed major milestones for construction were as follows:

(in millions)

2012

2013

2014

2015

2016

Thereafter

Total future commitments

Renewable

Energy

Contracts

$ 561

616

712

751

752

13,186

$ 16,578

QF Power

Purchase

Agreements

$ 439

438

437

426

368

1,569

$ 3,677

Other 

Purchase

Agreements1

$ 624

828

812

705

476

2,853

$ 6,298

1 Includes power purchase agreements with SCE's consolidated affiliates.

Some of the power purchase agreements that SCE entered into with independent power producers are treated as operating and 

capital leases. The following table shows the future minimum expected payments due under the contracts that are treated as 

operating and capital leases (these amounts are also included in the table above). The future expected payments for capital 
143

leases are discounted to their present value in the table below using SCE's incremental borrowing rate at the inception of the 

leases. The amount of this discount is shown in the table below as the amount representing interest.

(in millions)

2012

2013

2014

2015

2016

Thereafter

Total future commitments

Amount representing executory costs

Amount representing interest

Net commitments

Operating

Leases

$ 839

966

930

916

815

11,468

$ 15,934

Capital

Leases

$ 33

33

72

109

109

1,751

$ 2,107

(445)

(773)

$ 889

Operating lease expense for these power purchase agreements was $1.4 billion in 2011, $1.3 billion in 2010 and $1.2 billion 

in 2009. The timing of SCE's recognition of the lease expense conforms to ratemaking treatment for SCE's recovery of the 

cost of electricity and is included in purchased power.

At December 31, 2011 and 2010, net capital leases reflected in "Utility plant" on the consolidated balance sheets were 

$222 million and $227 million, including accumulated amortization of $27 million and $22 million, respectively. SCE had 

$6 million and $5 million included in "Other current liabilities" and $216 million and $222 million included in "Other 

deferred credits and other liabilities," representing the present value of the minimum lease payments due under these 

contracts recorded on the consolidated balance sheets at December 31, 2011 and 2010, respectively. SCE has a power 

purchase contract, with net commitments totaling $667 million, that meet the requirements for capital lease treatment, but is 

not reflected on the consolidated balance sheets since the lease term begins in 2014.

Power Plant and Other Lease Commitments

The following summarizes the estimated minimum future commitments for noncancelable power plant (which are related to 

EMG's long-term leases primarily related to the Illinois power facilities and Homer City facilities) and other operating leases

(excluding SCE's power purchase agreements discussed above):

(in millions)

2012

2013

2014

2015

2016

Thereafter

Total future commitments

Operating

Leases –

Power

Plants

$ 311

300

289

174

115

1,412

$ 2,601

Operating

Leases –

Other

$ 99

100

83

75

65

469

$ 891

The minimum commitments above do not include EMG's contingent rentals with respect to the wind projects which may be 

paid under certain leases on the basis of a percentage of sales calculation if this is in excess of the stipulated minimum 

amount. 

Operating lease expense for power plants and other leases (primarily related to vehicles, office space and other equipment) 

were $279 million in 2011, $279 million in 2010 and $256 million in 2009.
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Sale-Leaseback Transactions

On December 7, 2001, a subsidiary of EMG completed a sale-leaseback of EMG's Homer City plant to third-party lessors. 

Under the terms of the 33.67-year leases, EMG's subsidiary is obligated to make semi-annual lease payments on each April 1 

and October 1. If an owner-lessor intends to sell its interest in the Homer City plant, EMG has a right of first refusal to 

acquire the interest at fair market value. The gain on the sale of the facilities has been deferred and is being amortized over

the term of the leases.

Under the sale-leaseback documents, Homer City rent payments are comprised of two components, senior rent and equity 

rent. Senior rent is used exclusively for debt service to secured lease obligation bondholders, while equity rent is paid to the 

owner-lessors. In order to pay equity rent, among other requirements, Homer City must meet historical and projected senior 

rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances). The senior rent service 

coverage ratio of 1.18 to 1 for the 12 months ended December 31, 2011 was below the covenant threshold and Homer City 

also did not meet the threshold for the prospective two 12-month periods, which currently precludes Homer City from 

making distributions, including repayment of certain intercompany loans and from paying the equity portion of the rent 

payment. A failure to pay equity rent does not entitle the owner-lessors to foreclose upon Homer City's leasehold interest, but

it does result in the suspension of Homer City's ability to make permitted distributions. Moreover, Homer City would be 

permanently restricted in its ability to make permitted distributions if a failure to pay equity rent when due was not cured 

within nine months, or even if cured, occurred more than one additional time during the term of the lease. Homer City is not 

subject to any minimum historical and projected senior rent service coverage ratios except as conditions to distributions and 

equity rent payments. Also, failure by Homer City to pay equity rent when due in April 2012 could trigger termination of the 

$48 million senior rent reserve letter of credit. Homer City would then be required to fund the senior rent reserve, and failure 

to do so could entitle counterparties to seek available remedies under the sale-leaseback documents, including termination or 

foreclosure upon the leasehold interest. As a result of the expectation that EMG is likely to lose substantially all beneficial

economic interest in and material control of the Homer City plant, EMG recorded an impairment charge of $1.03 billion for 

the fourth quarter of 2011. For further discussion, see Note 16. Asset Impairments, Lease Terminations and Other.

On August 24, 2000, a subsidiary of EMG completed a sale-leaseback of EMG's Powerton and Joliet power stations located 

in Illinois to third-party lessors. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), EMG's 

subsidiary makes semi-annual lease payments on each January 2 and July 2, which began January 2, 2001. EMG guarantees 

its subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power station, EMG 

has a right of first refusal to acquire the interest at fair market value. The gain on the sale of the power stations has been 

deferred and is being amortized over the term of the leases.

Under the terms of the foregoing sale-leaseback transactions, distributions are restricted by EMG's subsidiaries unless 

specified financial covenants are met. At December 31, 2011, Midwest Generation met these covenants. In addition, the lease 

agreements and the Midwest Generation credit agreement contain covenants that include restrictions on the ability of these 

subsidiaries to, among other things, incur debt, create liens on its property, merge or consolidate, sell assets, make 

investments, engage in transactions with affiliates, make distributions, make capital expenditures, enter into agreements 

restricting its ability to make distributions, engage in other lines of business, enter into swap agreements, or engage in 

transactions for any speculative purpose.

Nuclear Decommissioning Commitment

SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in 

independent trusts. The recorded liability to decommission SCE's nuclear power facilities is $2.5 billion as of December 31, 

2011, based on site-specific studies performed in 2008 for San Onofre and 2007 for Palo Verde. Changes in the estimated 

costs, timing of decommissioning or the assumptions underlying these estimates could cause material revisions to the 

estimated total cost to decommission. SCE estimates that it will spend approximately $8.6 billion through 2053 to 

decommission its active nuclear facilities. This estimate is based on SCE's decommissioning cost methodology used for 

ratemaking purposes, escalated at rates ranging from 1.8% to 6.9% (depending on the cost element) annually. These costs are 

expected to be funded from independent decommissioning trusts, which received contributions of $23 million in both 2011 

and 2010 and $46 million in 2009. SCE estimates annual after-tax earnings on the decommissioning funds of 4.2% to 5.7%. 

If the assumed return on trust assets is not earned, it is probable that additional funds needed for decommissioning will be 

recoverable through rates in the future. If the assumed return on trust assets is greater than estimated, funding amounts may 

be reduced through future decommissioning proceedings.

All of SCE's San Onofre Unit 1 decommissioning costs will be paid from its nuclear decommissioning trust funds and are 

subject to CPUC review. The estimated remaining cost to decommission San Onofre Unit 1 is recorded as an ARO liability of 
145

$65 million at December 31, 2011. Total expenditures for the decommissioning of San Onofre Unit 1 were $597 million from 

the beginning of the project in 1998 through December 31, 2011.

Decommissioning expense under the ratemaking method was $23 million, $30 million and $46 million in 2011, 2010 and 

2009, respectively. The ARO for decommissioning SCE's active nuclear facilities was $2.5 billion and $2.4 billion at 

December 31, 2011 and 2010, respectively. See Note 4 and Note 15 for discussion on the nuclear decommissioning trusts.

Other Commitments

Certain other commitments for the years 2012 through 2016 are estimated below:

(in millions)

Nuclear fuel supply contracts

Other fuel supply contracts

Coal transportation agreements1

Gas transportation agreements

Capital expenditures

Other contractual obligations

2012

$ 190

479

386

7

286

114

2013

$ 135

237

326

7

19

73

2014

$ 78

208

333

7

—

43

2015

$ 78

83

315

7

—

37

2016

$ 128

46

315

8

—

19

1

 In years 2013 through 2016, represents contracts for minimum volumes without regard to payment of alternative liquidated 

damages or plant closures.

Fuel Supply Contracts and Coal Transportation Agreements

SCE has fuel supply contracts which require payment only if the fuel is made available for purchase. SCE has a coal fuel 

contract that requires payment of certain fixed charges whether or not coal is delivered.

At December 31, 2011, Midwest Generation and Homer City had commitments to purchase coal from third-party suppliers at 

fixed prices, subject to adjustment clauses. In addition, Midwest Generation had contractual agreements for the transportation 

of coal. The commitments under these contracts are based on either actual coal purchases derived from committed coal 

volumes set forth in fuel supply contracts or minimum quantities as set forth in the transportation agreements. The 

transportation agreements have provisions that address the financial exposure of Midwest Generation related to a plant 

closure under certain circumstances as specified in the agreements. 

Gas Transportation Agreements

At December 31, 2011, EMG had a contractual commitment to transport natural gas. EMG's share of the commitment to pay 

minimum fees under its gas transportation agreement, which has a remaining contract length of six years, is estimated to 

aggregate $36 million in the next five years. EMG has entered into agreements to re-sell the transportation under this 

agreement which aggregates $45 million over the same period.

Capital Commitments

At December 31, 2011, EMG's subsidiaries had firm commitments for capital expenditures primarily related to the Walnut 

Creek project and the construction of wind projects. EMG intends to fund these expenditures through project-level financing, 

U.S. Treasury grants, Midwest Generation and EME lines of credit, if available, cash on hand and cash generated from 

operations.

Other Contractual Obligations

At December 31, 2011, EMG and its subsidiaries were party to turbine operations and maintenance agreements, agreements 

for the purchase of materials used in the operation of environmental controls equipment and a coal cleaning agreement.

Guarantees and Indemnities

Edison International's subsidiaries have various financial and performance guarantees and indemnity agreements which are 

issued in the normal course of business. The contracts discussed below included performance guarantees.

Environmental Indemnities Related to the Midwest Generation Plants

In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison 
146

Company (Commonwealth Edison) with respect to specified environmental liabilities before and after December 15, 1999, 

the date of sale. The indemnification obligations are reduced by any insurance proceeds and tax benefits related to such 

indemnified claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses 

related to any such indemnification claim. Also, in connection with the sale-leaseback transaction related to the Powerton and 

Joliet Stations in Illinois, EME agreed to indemnify the owner-lessors for specified environmental liabilities. These 

indemnities are not limited in term or amount. Due to the nature of the obligations under these indemnities, a maximum 

potential liability cannot be determined. Commonwealth Edison has advised EME that Commonwealth Edison believes it is 

entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the litigation 

discussed below under "—Contingencies—Midwest Generation New Source Review and Other Litigation." Except as 

discussed below, EME has not recorded a liability related to these environmental indemnities.

Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation 

Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of Midwest Generation's reimbursement 

obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this 

supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of 

specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a 

sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. 

The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial fiveyear term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to 

terminate); pursuant to the automatic renewal provision, it has been extended until February 2013. There were approximately 

226 cases for which Midwest Generation was potentially liable that had not been settled and dismissed at December 31, 2011. 

While the range of this liability is between $46 million and $64 million, Midwest Generation had recorded an estimated 

liability of $54 million and $56 million at December 31, 2011 and 2010, respectively, related to this contractual 

indemnity. 

Environmental Indemnity Related to the Homer City Plant

In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to 

specified environmental liabilities before and after the date of sale. EME guaranteed this obligation of Homer City. Also, in 

connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the ownerlessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity provisions, they are 

not subject to a maximum potential liability and do not have expiration dates. EME has not recorded a liability related to this

indemnity. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City 

New Source Review and Other Litigation."

Indemnities Provided under Asset Sale and Sale-Leaseback Agreements

The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, 

including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing 

environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. At December 31, 

2011 and 2010, EME had recorded a liability of $36 million and $42 million, respectively, related to these matters.

In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers, 

including for taxes imposed with respect to operations of the assets prior to the sale. Not all indemnities under the asset sale 

agreements have specific expiration dates. Due to the nature of these potential obligations, EME cannot determine a range of 

estimates and has not recorded a liability related to these indemnities.

In connection with the sale-leaseback transactions related to the Homer City plant in Pennsylvania, the Powerton and Joliet 

Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax 

indemnity agreements. Under certain of these tax indemnity agreements, Homer City and Midwest Generation, as the lessees 

in the sale-leaseback transactions agreed to indemnify the respective owner-lessors for specified adverse tax consequences 

that could result from certain situations set forth in each tax indemnity agreement, including specified defaults under the 

respective leases. Although the Collins Station lease terminated in April 2004, Midwest Generation's indemnities in favor of 

its former lease equity investors are still in effect. EME provided similar indemnities in the sale-leaseback transactions 

related to the Powerton and Joliet Stations in Illinois. The potential indemnity obligations under these tax indemnity 

agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a range of estimated 

obligation which would be triggered by a valid claim from the owner-lessors. EME has not recorded a liability for these 

matters.

In addition to the indemnity provided by Homer City, EME agreed to indemnify the owner-lessors in the sale-leaseback 
147

transaction related to the Homer City plant for certain negative federal income tax consequences should the rent payments be 

"levelized" for tax purposes and for potential foreign tax credit losses in the event that the owner-lessor's debt is characterized 

as recourse, rather than nonrecourse. This indemnity covers a limited range of possible tax consequences that are unrelated to 

performance under the lease.

Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of the Mountainview power plant, SCE agreed to indemnify the seller with respect to 

specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 

1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to 

environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase 

agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities 

expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

Mountainview Filter Cake Indemnity

SCE has indemnified the City of Redlands, California in connection with Mountainview's California Energy Commission 

permit for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake 

at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a 

maximum liability. SCE has not recorded a liability related to this indemnity.

Other Edison International Indemnities

Edison International provides other indemnifications through contracts entered into in the normal course of business. These 

are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and 

indemnities for specified environmental liabilities and income taxes with respect to assets sold. Edison International's 

obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison 

International may have recourse against third parties. Edison International has not recorded a liability related to these 

indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.

Contingencies

In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory 

proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. 

Edison International believes the outcome of these other proceedings will not materially affect its results of operations or 

liquidity.

Midwest Generation New Source Review and Other Litigation

In August 2009, the United States Environmental Protection Agency ("US EPA") and the State of Illinois filed a complaint in 

the Northern District of Illinois alleging that Midwest Generation or Commonwealth Edison performed repair or replacement 

projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration 

("PSD") requirements and of the New Source Performance Standards of the Clean Air Act ("CAA"), including alleged 

requirements to obtain a construction permit and to install controls sufficient to meet best available control technology 

("BACT") emission rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain 

operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and 

particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to 

$37,500 per violation, per day, the complaint called for an injunction ordering Midwest Generation to install controls 

sufficient to meet BACT emission rates at all units subject to the complaint; and other remedies. The remedies sought by the 

plaintiffs in the lawsuit could go well beyond the requirements of the Combined Pollutant Standard ("CPS"). Several 

Chicago-based environmental action groups intervened in the case.

Nine of ten PSD claims have been dismissed, along with claims related to alleged violations of Title V of the CAA to the 

extent based on the dismissed PSD claims. The court has also dismissed all claims asserted against Commonwealth Edison 

and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties 

in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations 

should be equitably tolled. The court did not address other counts in the complaint that allege violations of opacity and 

particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. The dismissals have been 

certified as “partial final judgments” capable of appeal, and an appeal is pending before the Seventh Circuit Court of Appeals.

The remaining claims are stayed pending the appeal.
148

In January 2012, two complaints were filed against Midwest Generation in Illinois state court by residents living near the 

Crawford and Fisk Stations on behalf of themselves and all others similarly situated, each asserting claims of nuisance, 

negligence, trespass, and strict liability. The plaintiffs seek to have their suits certified as a class action and request injunctive 

relief, as well as compensatory and punitive damages. The complaints are similar to two complaints previously filed in the 

Northern District of Illinois, which were dismissed in October 2011 for lack of federal jurisdiction. 

Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on 

the financial condition and results of operations of Midwest Generation and EME. EME cannot predict the outcome of these 

matters or estimate the impact on the Midwest Generation plants, or its and Midwest Generation's results of operations, 

financial position or cash flows. EME has not recorded a liability for this matter.

Homer City New Source Review and Other Litigation

In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback 

owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleged violations 

of the PSD and Title V provisions of the CAA, as a result of projects in the 1990s performed by prior owners without PSD 

permits and the subsequent failure to incorporate emissions limitations that meet BACT into the station's Title V operating 

permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint called for an 

injunction ordering Homer City to install controls sufficient to meet BACT emission rates at all units subject to the complaint

and for other remedies. The Pennsylvania Department of Environmental Protection, the State of New York and the State of 

New Jersey intervened in the lawsuit. In October 2011, all of the claims in the US EPA's lawsuit were dismissed with 

prejudice. An appeal of the dismissal is pending before the Third Circuit Court of Appeals. 

Also in January 2011, two residents filed a complaint in the Western District of Pennsylvania, on behalf of themselves and all 

others similarly situated, against Homer City, the sale-leaseback owner participants of the Homer City plant, two prior 

owners of the Homer City plant, EME, and Edison International, claiming that emissions from the Homer City plant had 

adversely affected their health and property values. The plaintiffs sought to have their suit certified as a class action and 

requested injunctive relief, the funding of a health assessment study and medical monitoring, as well as compensatory and 

punitive damages. In October 2011, the claims in the purported class action lawsuit that were based on the federal CAA were 

dismissed with prejudice, while state law statutory and common law claims were dismissed without prejudice to re-file in 

state court should the plaintiffs choose to do so. EME does not know whether the plaintiffs will file a complaint in state court. 

In February 2012, Homer City received a 60-day Notice of Intent to Sue indicating the Sierra Club’s intent to file a citizen 

lawsuit alleging violations of emissions standards and limitations under the CAA and the Pennsylvania Air Pollution Control 

Act.

Adverse decisions in these cases could involve penalties, remedial actions and damages that could have a material impact on 

the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters 

or estimate the impact on the Homer City plant, or its and Homer City's results of operations, financial position or cash flows. 

EME has not recorded a liability for this matter.

CPSD Investigations

San Gabriel Valley Windstorm Investigation

In November 2011, a windstorm resulted in significant damage to SCE’s electric system and service outages for SCE 

customers primarily in the San Gabriel Valley. The CPUC directed its Consumer Protection and Safety Division (“CPSD”) to 

conduct an investigation focused on the cause of the outages, SCE’s service restoration effort, and SCE’s customer 

communications during the outages. The CPSD issued its preliminary report on February 1, 2012. The report asserts that SCE 

and others with whom SCE shares utility poles violated certain CPUC safety rules applicable to overhead line construction, 

maintenance and operation, which may have caused the failures of affected poles and supporting cables. The report also 

concludes that SCE’s restoration time was not adequate and makes other assertions. Additionally, the report contends that 

SCE violated CPUC rules by failing to preserve evidence relevant to the investigation when it did not retain damaged poles 

that were replaced following the windstorm. If the CPUC issues an Order Instituting Investigation ("OII") regarding this 

matter and SCE is found to have violated any CPUC rules, it could face penalties. In addition, the cost of any large scale 

review of poles or other equipment for safety compliance could be significant. SCE is unable to estimate a possible loss or 

range of loss associated with any penalties that may be imposed by the CPUC on SCE.

Malibu Fire Order Instituting Investigation

Following a 2007 wildfire in Malibu, California, the CPUC issued an OII to determine if any statutes, CPUC general orders, 
149

rules or regulations were violated by SCE or telecomm providers (“OII Respondents”) that shared the use of three failed 

power poles in the wildfire area. The CPSD has alleged, among other things, that the poles were overloaded, that the OII 

Respondents violated the CPUC's rules governing the design, construction and inspection of poles and misled the CPUC 

during its investigation of the fire, and that SCE failed to preserve evidence relevant to the investigation. In October 2011, the 

CPSD proposed that the OII Respondents be assessed penalties of approximately $99 million, with SCE being allocated 

approximately $50 million of the total. SCE has denied the allegations and believes the proposed penalties are excessive. 

Four Corners New Source Review Litigation

In October 2011, four private environmental organizations filed a CAA citizen lawsuit against the co-owners of Four Corners. 

The complaint alleges that certain work performed at the Four Corners generating units 4 and 5, over the approximate periods 

of 1985-1986 and 2007-present, constituted plant “major modifications” for which the plant should have, but did not, obtain 

permits and install BACT in violation of the PSD requirements and of the New Source Performance Standards of the CAA. 

The complaint also alleges subsequent and continuing violation of BACT air emissions limits. The lawsuit seeks injunctive 

and declaratory relief, civil penalties, including a mitigation project and litigation costs. In November 2010, SCE entered into 

an agreement to sell its ownership interest in generating units 4 and 5 to APS. The sale is subject to regulatory approvals and

is expected to close in late 2012. Under the agreement SCE would remain responsible for its pro rata share of certain 

environmental liabilities, including penalties arising from environmental violations prior to the sale, but SCE would not be 

liable for any costs of installing BACT or other costs related to continuing or extending Four Corners operations. SCE is 

unable to estimate a possible loss or range of loss associated with this matter.

Concurrently, the US EPA has proposed a regional haze federal implementation plan based on an APS proposal that would 

require shut down of units 1, 2 and 3 by 2016 and the installation of selective catalytic reduction technology on units 4 and 5

by 2018. APS' proposal contemplated that these actions would both satisfy the federal regional haze requirements and resolve 

any New Source Review claims the US EPA might have. A final federal implementation plan is expected in 2012. 

Environmental Remediation

Edison International 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. Edison International 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 single 

probable amount, Edison International records the lower end of this reasonably likely range of costs (reflected in "Other longterm liabilities") at undiscounted amounts as timing of cash flows is uncertain.

At December 31, 2011, Edison International's recorded estimated minimum liability to remediate its 26 identified material 

sites (sites in which the upper end of the range of the costs is at least $1 million) at SCE (24 sites) and EMG (2 sites related to 

Midwest Generation) was $56 million, of which $49 million was related to SCE, including $14 million related to San Onofre. 

In addition to its identified material sites, SCE also has 33 immaterial sites for which the total minimum recorded liability 

was $3 million. Of the $52 million total environmental remediation liability for SCE, $49 million has been recorded as a 

regulatory asset. SCE expects to recover $31 million through an incentive mechanism that allows SCE to recover 90% of its 

environmental remediation costs at certain sites (SCE may request to include additional sites) and $18 million through a 

mechanism that allows SCE to recover 100% of the costs incurred at certain sites through customer rates. Edison 

International's identified sites include several sites for which there is a lack of currently available information, including the 

nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for 

contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for 

these sites.

The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous 

uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data 

for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the 

possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison 

International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at the identified material 

sites and immaterial sites could exceed its recorded liability by up to $197 million and $6 million, respectively, all of which is 

related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International 

among a range of reasonably possible outcomes.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next five years 
150

are expected to range from $7 million to $17 million. Costs incurred for the years ended December 31, 2011, 2010 and 2009 

were $16 million, $17 million and $11 million, respectively.

Based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International 

believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows.

There can be no assurance, however, that future developments, including additional information about existing sites or the 

identification of new sites, will not require material revisions to estimates.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is 

currently approximately $12.6 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum 

private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor 

licensees. If a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the 

primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in 

the form of a deferred premium.

Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear 

incident. However, it would have to pay no more than approximately $35 million per incident in any one year. If the public 

liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This 

could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. 

Decontamination liability and excess property damage coverage exceeding the primary $500 million also has been purchased 

in amounts greater than the federal requirement of a minimum of approximately $1.1 billion. Property damage insurance also 

covers damages caused by acts of terrorism up to specified limits. Additional insurance covers part of replacement power 

expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear 

facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated 

funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately 

$48 million per year. Insurance premiums are charged to operating expense.

Wildfire Insurance

Severe wildfires in California have given rise to large damage claims against California utilities for fire-related losses alleged 

to be the result of the failure of electric and other utility equipment. Invoking a California Court of Appeal decision, plaintiffs 

pursuing these claims have relied on the doctrine of inverse condemnation, which can impose strict liability (including 

liability for a claimant's attorneys' fees) for property damage. On September 1, 2011, SCE's parent, Edison International, 

renewed its insurance coverage, which included coverage for SCE's wildfire liabilities up to a $575 million limit (with a selfinsured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the 

insurance coverage could result in additional self-insured costs in the event of multiple wildfire occurrences during the policy 

period (September 1, 2011 to August 31, 2012). SCE may experience coverage reductions and/or increased insurance costs in 

future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.

Spent Nuclear Fuel

Under federal law, the Department of Energy ("DOE") is responsible for the selection and construction of a facility for the 

permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to 

begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of 

costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim 

storage for spent nuclear fuel on site sufficient for the current license period.

In June 2010, the United States Court of Federal Claims issued a decision granting SCE and the San Onofre co-owners 

damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet 

its obligation to begin accepting spent nuclear fuel from San Onofre. SCE received payment from the federal government in 

the amount of the damage award in November 2011. SCE has returned to the San Onofre co-owners their respective share of 

the damage award paid. SCE, as operating agent, filed a lawsuit against the DOE in the Court of Federal Claims in December 

2011 seeking damages for the period from January 1, 2006 to December 31, 2010 for the DOE's failure to meet its obligation 

to begin accepting spent nuclear fuel. Additional legal action would be necessary to recover damages incurred after 

December 31, 2010. Any damages recovered by SCE are subject to CPUC review as to what amounts would be returned to 

SCE customers or used to offset past or future fuel decommissioning or storage costs for the benefit of customers.
151

Note 10. Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

During 2011, Midwest Generation continued to advance necessary activities for nitrogen oxide ("NOx") and sulfur dioxide 

("SO2") controls to meet the requirements of the CPS. Midwest Generation has substantially completed the installation of 

selective non-catalytic reduction ("SNCR") technology on multiple units to meet the NOx portion of the CPS and has 

received all necessary permits from the Illinois EPA for the installation of a dry sorbent injection system using Trona or its 

equivalent at the Waukegan generating station's Unit 7 and Units 5 and 6 at the Powerton Station. In February 2012, Midwest 

Generation received an extension of its permit to install a dry sorbent injection system at the Powerton Station. 

Decisions regarding whether or not to proceed with retrofitting any particular remaining units to comply with CPS 

requirements for SO2 emissions, including those that have received permits, are subject to a number of factors, such as 

market conditions, regulatory and legislative developments, liquidity and forecasted commodity prices and capital and 

operating costs applicable at the time decisions are required or made. Midwest Generation may also elect to shut down units, 

instead of installing controls, to be in compliance with the CPS. Decisions about any particular combination of retrofits and 

shutdowns Midwest Generation may ultimately employ also remain subject to conditions applicable at the time decisions are 

required or made. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend 

capital or continue with the expenditure of capital will be made as required, subject to the requirements of the CPS and other 

applicable regulations. In February 2012, Midwest Generation decided to shut down the Fisk Station by the end of 2012 and 

the Crawford Station by the end of 2014 and concluded it was less likely to retrofit the Waukegan Station rather than the 

larger Powerton, Joliet and Will County Stations. As a result, EME recorded an impairment charge of $640 million at 

December 31, 2011 related to the Crawford, Fisk and Waukegan Stations. For further discussion, see Note 16. Asset 

Impairments, Lease Terminations and Other. Units that are not retrofitted may continue to operate until required to shut down 

by applicable regulations or operate with reduced output.

Based on work to date, Midwest Generation estimates the cost of retrofitting the large stations (Powerton, Joliet Units 7 and 

8,and Will County) using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, 

and the associated upgrading of existing particulate removal systems, would be up to approximately $628 million. The cost of 

retrofitting Joliet Unit 6 is not included in the large unit amounts as it is less likely that Midwest Generation will make 

retrofits for this unit. The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the 

estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. For further discussion 

related to EMG's impairment policy on the unit of account, see Note 1. Summary of Significant Accounting Policies—

Impairment of Long-Lived Assets. 

Homer City Environmental Issues and Capital Resource Limitations

Homer City has begun work on designing SO2 and particulate emissions control equipment for Units 1 and 2. Based on 

preliminary estimates, Homer City expects the cost of such equipment to be approximately $700 million to $750 million. 

However, construction of these improvements is dependent upon funding from the owner-lessors or other third parties. For 

additional information, see Note 16. Asset Impairments, Lease Terminations and Other.

Cross-State Air Pollution Rule

On July 6, 2011, the US EPA adopted the Cross-State Air Pollution Rule ("CSAPR"). CSAPR is the final form of a 

previously proposed replacement for the Clean Air Interstate Rule ("CAIR"), originally called the Clean Air Transport Rule 

that was released in 2010. CSAPR establishes emissions reductions for annual SO2 emissions and annual and ozone season 

NOx emissions in two phases: a first phase originally scheduled to be effective January 1, 2012 and, in most states subject to 

the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional 

reductions in annual SO2 emissions.

In December 2011, the United States Court of Appeals for the District of Columbia granted a stay of CSAPR pending 

completion of its review of the rule's validity. Oral argument is scheduled for April 13, 2012, and a court decision is expected 

during the third quarter of 2012. The court directed the US EPA to continue administering the CAIR until its review is 

completed.

Hazardous Air Pollutant Regulations

In December 2011, the US EPA announced the Mercury and Toxics Air Standards ("MATS") rule, limiting emissions of 

hazardous air pollutants from coal- and oil-fired electrical generating units. The rule was published in the Federal Register on 

February 16, 2012, and becomes effective on April 16, 2012. EMG does not expect that these standards will require Midwest 
152

Generation to make material changes to the approach to compliance with state and federal environmental regulations that it 

contemplates for CPS compliance. EMG also does not expect that these standards will require Homer City to make additional 

capital expenditures beyond those that would be required for compliance with CSAPR Phase II.

Water Quality

Once-Through Cooling Issues

In March 2011, the US EPA proposed standards under the federal Clean Water Act that would affect cooling water intake 

structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens 

attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). 

The regulations are expected to be finalized by July 2012. The required measures to comply with the proposed standards 

regarding entrainment are subject to the discretion of the permitting authority, and Edison International is unable at this time 

to assess potential costs of compliance, which could be significant for the Midwest Generation plants and San Onofre, but are 

not expected to be material for the Homer City plant, which already has cooling towers.

In addition to the proposed draft US EPA standards, the existing California once-through cooling policy may result in 

significant capital expenditures at San Onofre and may affect its operations. If other coastal power plants in California that 

rely on once-through cooling are forced to shut down or limit operations, the California policy may also significantly impact 

SCE's ability to procure generating capacity from those plants, which could have an adverse effect on system reliability and 

the cost of electricity.

Coal Combustion Wastes

US EPA regulations currently classify coal ash and other coal combustion residuals as solid wastes that are exempt from 

hazardous waste requirements. In June 2010, the US EPA published proposed regulations relating to coal combustion 

residuals that could result in their reclassification. Two different proposed approaches are under consideration. 

The first approach, under which the US EPA would list these residuals as special wastes subject to regulation as hazardous 

wastes, could require EME and SCE to incur additional capital and operating costs. The second approach, under which the 

US EPA would regulate these residuals as nonhazardous wastes, would establish minimum technical standards for units that 

are used for the disposal of coal combustion residuals, but would allow procedural and enforcement mechanisms (such as 

permit requirements) to be exclusively a matter of state law. Many of the proposed technical standards are similar under both 

proposed options (for example, surface impoundments may need to be retrofitted, depending on which standard is finally 

adopted), but the second approach is not expected to require the retrofitting of landfills used for the disposal of coal 

combustion residuals.

Greenhouse Gas Regulation

There have been a number of federal and state legislative and regulatory initiatives to reduce greenhouse gas ("GHG") 

emissions. Any climate change regulation or other legal obligation that would require substantial reductions in GHG 

emissions or that would impose additional costs or charges for GHG emissions could significantly increase the cost of 

generating electricity from fossil fuels as well as the cost of purchased power, which could adversely affect SCE's business. 

In the case of utilities, like SCE, these costs are generally borne by customers.

Significant developments include the following:

• In June 2010, the US EPA issued the Prevention of Significant Deterioration ("PSD") and Title V Greenhouse Gas 

Tailoring Rule, known as the "GHG tailoring rule." This regulation generally subjects newly constructed sources of GHG 

emissions and newly modified existing major sources to the Prevention of Significant Deterioration air permitting 

program (and later, to the Title V permitting program under the CAA), beginning in January 2011. A challenge to the 

GHG tailoring rule (along with other GHG regulations and determinations issued by the US EPA) is pending before the 

U.S. Court of Appeals for the D.C. Circuit. 

• Under a pending court settlement, the US EPA was to propose performance standards for GHG emissions from new and 

modified power plants. The specific requirements will not be known until the regulations are finalized.

• In December 2011, the California Air Resources Board ("CARB") regulation was officially published establishing a 

California cap-and-trade program. The first compliance period under the regulations is for 2013 GHG emissions. CARB 

regulations implementing a California cap-and-trade program and the cap-and-trade program itself continue to be the 

subject of litigation. 
153

• In April 2011, California enacted a law requiring California retail sellers of electricity to procure 33% of their customers'

electricity requirements from renewable resources, as defined in the statute. Specifically, the new law establishes multiyear compliance periods and requires the CPUC and the CEC to establish the quantity of renewable resources to be 

procured according to the limitations set forth in the statute. On December 1, 2011, the CPUC approved a decision 

setting procurement quantity requirements for CPUC-regulated retail sellers that incrementally increase to 33% over 

several periods between January 2011 and December 31, 2020. The quantity would remain at 33% of retail sales for each 

year thereafter. The full impact of the new 33% law will depend on how the CPUC and CEC implement the law, which 

remains uncertain.

Greenhouse Gas Litigation Developments

In June 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies, ruling that the CAA 

and the US EPA actions the CAA authorizes displace federal common law nuisance claims that might arise from the emission 

of GHGs. The court also affirmed the Second Circuit's determination that at least some of the plaintiffs had standing to bring 

the case. The court did not address whether the CAA also preempts state law claims arising from the same circumstances.

An appeal before the Ninth Circuit of a federal district order dismissing a case against Edison International, and other 

defendants, had been deferred pending the U.S. Supreme Court's ruling described above. In the case, which was brought by 

the Alaskan Native Village of Kivalina, the plaintiffs seek damages of up to $400 million for the cost of relocating the village, 

which they claim is no longer protected from storms because the Arctic sea ice has melted as the result of climate change. 

The stay of the appeal has been lifted and argument before the Ninth Circuit was held in November 2011.

In May 2011, private citizens filed a purported class action complaint in the United States District Court for the Southern 

District of Mississippi, naming a large number of defendants, including Edison International and its subsidiaries, including 

SCE and EME. Plaintiffs allege that the defendants' activities resulted in emissions of substantial quantities of GHGs that 

have contributed to climate change and sea level rise, which in turn are alleged to have increased the destructive force of 

Hurricane Katrina. The lawsuit alleges causes of action for negligence, public and private nuisance, and trespass, and seeks 

unspecified compensatory and punitive damages. The claims in this lawsuit are nearly identical to a subset of the claims that 

were raised against many of the same defendants in a previous lawsuit that was filed in, and dismissed by, the same federal 

district court where the current case has been filed. Edison International was dismissed as a defendant in this complaint in 

July 2011, but SCE and EME remain defendants.

Note 11. Accumulated Other Comprehensive Loss

Edison International's accumulated other comprehensive loss consists of:

(in millions)

Balance at December 31, 2009

Change for 2010

Balance at December 31, 2010

Change for 2011

Balance at December 31, 2011

Unrealized

Gain (Loss)

on Cash

Flow Hedges

$ 105

(89)

16

(50)

$ (34)

Pension and

PBOP – Net

Loss

$ (70)

(17)

(87)

(13)

$ (100)

Pension and

PBOP – Prior

Service Cost

$ 2

(7)

(5)

—

$ (5)

Accumulated

Other

Comprehensive

Loss

$ 37

(113)

(76)

(63)

$ (139)

Included in accumulated other comprehensive loss at December 31, 2011 was $21 million, net of tax, of unrealized gains on 

commodity-based cash flow hedges; and $55 million, net of tax, of unrealized losses related to interest rate hedges. The 

maximum period over which a commodity cash flow hedge is designated is through May 31, 2014.

Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. 

These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. 

Approximately $22 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings 

during the next 12 months. Management expects that reclassification of net unrealized gains will increase energy revenues 

recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary 

materially from this estimated amount as a result of changes in market conditions.
154

Note 12. Supplemental Cash Flows Information

Edison International's supplemental cash flows information is:

(in millions)

Cash payments (receipts) for interest and taxes:

Interest – net of amounts capitalized

Tax payments (refunds) – net

Details of assets acquired:

Fair value of assets acquired

Liabilities assumed

Net assets acquired

Noncash investing and financing activities:

Accrued capital expenditures

Details of debt exchange:

Pollution-control bonds redeemed

Pollution-control bonds issued

Details of capital lease obligations:

Capital lease purchased

Capital lease obligation issued

Consolidation of variable interest entities:

Assets other than cash

Liabilities and noncontrolling interests

Deconsolidation of variable interest entities:

Assets other than cash

Liabilities and noncontrolling interests

Dividends declared but not paid:

Common stock

Preferred and preference stock

Years ended December 31,

2011

$ 713

(332)

$ 1

—

$ 1

$ 639

$ (86)

86

$ —

—

$ —

—

$ —

—

$ 106

11

2010

$ 609

232

$ 1

—

$ 1

$ 680

$ (378)

378

$ —

—

$ (94)

99

$ 380

(476)

$ 104

13

2009

$ 661

427

$ 14

3

$ 11

$ 448

$ —

—

$ (223)

223

$ 3

(4)

$ —

—

$ 103

13

In connection with certain wind projects acquired during the past five years, the purchase price included payments that were 

due upon the completion of specific construction activities or the achievement of operational milestones. Accordingly, EMG 

accrues for estimated payments when the obligation is probable. These incremental purchase price payments are capitalized.

Note 13. Preferred and Preference Stock of Utility

SCE's authorized shares are: $100 cumulative preferred – 12 million shares, $25 cumulative preferred – 24 million shares and 

preference with no par value – 50 million shares. SCE's outstanding shares are not subject to mandatory redemption. There 

are no dividends in arrears for the preferred or preference shares. Shares of SCE's preferred stock have liquidation and 

dividend preferences over shares of SCE's common stock and preference stock. All cumulative preferred shares are 

redeemable. When preferred shares are redeemed, the premiums paid, if any, are charged to common equity. No preferred 

shares were issued or redeemed in the years ended December 31, 2011, 2010 and 2009. There is no sinking fund requirement 

for redemptions or repurchases of preferred shares.

Shares of SCE's preference stock rank junior to all of the preferred stock and senior to all common stock. Shares of SCE's 

preference stock are not convertible into shares of any other class or series of SCE's capital stock or any other security. The

preference shares issued prior to 2012 have a $100 liquidation value. There is no sinking fund requirement for redemptions or 

repurchases of preference shares.
155

Preferred stock and preference stock is:

(in millions, except shares and per-share amounts)

Cumulative preferred stock

$25 par value:

4.08% Series

4.24% Series

4.32% Series

4.78% Series

Preference stock

No par value:

4.90% Series A (variable and noncumulative)

6.125% Series B (noncumulative)

6.00% Series C (noncumulative)

6.50% Series D (cumulative)

Less issuance costs

Total

Shares

Outstanding

650,000

1,200,000

1,653,429

1,296,769

4,000,000

2,000,000

2,000,000

1,250,000

Redemption

Price

$ 25.50

25.80

28.75

25.80

100.00

100.00

100.00

100.00

December 31,

2011

$ 16

30

41

33

400

200

200

125

1,045

(16)

$ 1,029

2010

$ 16

30

41

33

400

200

200

—

920

(13)

$ 907

Shares of Series A and B preference stock were issued in 2005 and shares of Series C preference stock were issued in 2006. 

SCE may, at its option, redeem the Series A, B, or C preference shares in whole or in part. Shares of Series D preference 

stock, issued in 2011, may not be redeemed prior to March 1, 2016. After March 1, 2016, SCE may, at its option, redeem the 

shares in whole or in part for a price of $100 per share plus accrued and unpaid dividends, if any. The proceeds from the sale 

of these shares were used to fund SCE's capital program. Preference shares are not subject to mandatory redemption and no 

preference shares were redeemed in the last three years.

At December 31, 2011 accrued dividends related to SCE's preferred and preference stock were $11 million.

In January and February 2012, SCE issued 250,000 and 100,000 shares, respectively, of 6.25% Series E preference stock 

(cumulative, $1,000 liquidation value). The Series E preference shares may not be redeemed prior to February 1, 2022. After 

February 1, 2022, SCE may at its option, redeem the shares, in whole or in part for a price of $1,000 per share plus accrued 

and unpaid dividends, if any. The shares are not subject to mandatory redemption. The proceeds from the sale of these shares 

were used to repay commercial paper borrowings and to fund SCE's capital program.

Note 14. Regulatory Assets and Liabilities

Included in SCE's regulatory assets and liabilities are regulatory balancing accounts. CPUC authorized balancing account 

mechanisms require SCE to refund or recover any differences between forecasted and actual costs. The CPUC has authorized 

balancing accounts for specified costs or programs such as fuel, purchased-power, demand-side management programs, 

nuclear decommissioning and public purpose programs. Certain of these balancing accounts include a return on rate base of 

8.75%. The CPUC also authorizes the use of a balancing account to recover from or refund to customers differences in 

revenue resulting from actual and forecasted electricity sales.

Balancing account over and under collections represent differences between cash collected in current rates for specified 

forecasted costs and these costs that are actually incurred. Under-collections are recorded as regulatory balancing account 

assets. Over-collections are recorded as regulatory balancing account liabilities. With some exceptions, SCE seeks to adjust 

rates on an annual basis or at other designated times to recover or refund the balances recorded in its balancing accounts. 

Regulatory balancing accounts that SCE does not expect to collect or refund in the next 12 months are reflected in the longterm section of the consolidated balance sheets. Under collections and over collections accrue interest based on a three-month 

commercial paper rate published by the Federal Reserve.

Amounts included in regulatory assets and liabilities are generally recorded with corresponding offsets to the applicable 

income statement accounts.
156

Regulatory Assets

Regulatory assets included on the consolidated balance sheets are:

(in millions)

Current:

Regulatory balancing accounts

Energy derivatives

Other

Total Current

Long-term:

Deferred income taxes – net

Pensions and other postretirement benefits

Unamortized investments – net

Unamortized loss on reacquired debt

Energy derivatives

Nuclear-related investment – net

Regulatory balancing accounts

Other

Total Long-term

Total Regulatory Assets

December 31,

2011

$ 223

264

7

494

2,020

1,703

484

249

487

156

69

298

5,466

$ 5,960

2010

$ 213

162

3

378

1,855

1,097

460

268

177

154

56

280

4,347

$ 4,725

SCE's regulatory assets related to energy derivatives are primarily an offset to unrealized losses on derivatives. The 

regulatory asset changes based on fluctuations in the fair market value of the contracts, which expire in 1 to 12 years. 

SCE's regulatory assets related to deferred income taxes represent tax benefits passed through to customers. The CPUC 

requires SCE to pass through certain deferred income tax benefits to customers by reducing electricity rates, thereby 

deferring recovery of such amounts to future periods. Based on current regulatory ratemaking and income tax laws, SCE 

expects to recover its regulatory assets related to deferred income taxes over the life of the assets that give rise to the 

accumulated deferred income taxes, ranging from 1 to 45 years. 

SCE's regulatory assets related to pensions and other post-retirement plans represents the unfunded net loss and prior service 

costs of the plans (see "Pension Plans and Postretirement Benefits Other than Pensions" discussion in Note 8). This amount is 

being recovered through rates charged to customers as the plans are funded. 

SCE's unamortized investments include nuclear assets related to San Onofre which are expected to be recovered by 2022, 

nuclear assets related to Palo Verde which are expected to be recovered by 2027 and SCE's unamortized coal plant investment 

which is being recovered through June 2016. Unamortized investments also include legacy meters retired as part of the 

EdisonSmartConnectTM program which are expected to be recovered by 2025. Although SCE's unamortized investments are 

classified as regulatory assets on the consolidated balance sheets, they continue to be a component of rate base and earned an 

8.75% return in both 2011 and 2010. 

SCE's net regulatory asset related to its unamortized loss on reacquired debt will be recovered over the remaining original 

amortization period of the reacquired debt over periods ranging from 1 to 27 years.

SCE's nuclear-related investment include assets and accumulated depreciation related to the AROs for San Onofre and Palo 

Verde, which are expected to be recovered by 2022 and 2027, respectively. These assets are included in rate base and earned a 

return of 8.75% in 2011 and 2010.
157

Regulatory Liabilities

Regulatory liabilities included on the consolidated balance sheets are:

(in millions)

Current:

Regulatory balancing accounts

Other

Total Current

Long-term:

Costs of removal

Asset Retirement Obligations

Regulatory balancing accounts

Other

Total Long-term

Total Regulatory Liabilities

December 31,

2011

$ 661

9

670

2,697

1,105

864

4

4,670

$ 5,340

2010

$ 733

5

738

2,623

1,099

802

—

4,524

$ 5,262

SCE's regulatory liabilities related to costs of removal represent operating revenue collected for asset removal costs that SCE

expects to incur in the future. These balances will be returned to customers in a future ratemaking proceeding, be charged 

against expense to the extent that future expenses exceed amounts recoverable through the ratemaking process, or be applied 

as otherwise directed by the CPUC.

SCE's regulatory liabilities related to the AROs represent timing differences between the AROs and the assets of the nuclear 

decommissioning trust. The balance varies due to changes in the AROs as well as nuclear decommissioning trust investment 

activities. 

Note 15. Other Investments

Nuclear Decommissioning Trusts

Future decommissioning costs of removal of nuclear assets are expected to be funded from independent decommissioning 

trusts, which currently receive contributions of approximately $23 million per year included in SCE customer rates. 

Contributions to the decommissioning trusts are reviewed every three years by the CPUC. If additional funds are needed for 

decommissioning, it is probable that the additional funds will be recoverable through customer rates. Funds collected, 

together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions 

related to the investments of these trusts.

The following table sets forth amortized cost and fair value of the trust investments:

(in millions)

Stocks

Municipal bonds

U.S. government and agency securities

Corporate bonds

Short-term investments and receivables/payables

Total

Longest

Maturity 

Dates

—

2051

2041

2054

One-year

Amortized Cost

December 31,

2011

$ 865

625

516

259

38

$ 2,303

December 31,

2010

$ 895

706

270

288

26

$ 2,185

Fair Value

December 31,

2011

$ 1,899

756

580

317

40

$ 3,592

December 31,

2010

$ 2,029

790

288

346

27

$ 3,480

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. 

Proceeds from sales of securities (which are reinvested) were $2.8 billion, $1.4 billion and $2.2 billion for the years ended 
158

December 31, 2011, 2010 and 2009, respectively. Unrealized holding gains, net of losses, were $1.3 billion at both 

December 31, 2011 and 2010.

The following table sets forth a summary of changes in the fair value of the trust for the years ended December 31:

(in millions)

Balance at beginning of period

Gross realized gains

Gross realized losses

Unrealized gains (losses) – net

Other-than-temporary impairments

Interest, dividends, contributions and other

Balance at end of period

2011

$ 3,480

108

(17)

(7)

(47)

75

$ 3,592

2010

$ 3,140

125

(4)

148

(27)

98

$ 3,480

2009

$ 2,524

242

(147)

526

(111)

106

$ 3,140

Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no 

impact on operating revenue or earnings.

Note 16. Asset Impairments, Lease Terminations and Other

Asset impairments, lease terminations and other expenses consisted of the following:

(in millions)

Homer City plant impairment

Midwest Generation Stations impairment

Lease termination

Wind projects impairment and other charges

Other

Total

Years Ended December 31,

2011

$ 1,032

640

—

64

36

$ 1,772

2010

$ —

40

—

—

7

$ 47

2009

$ —

—

887

—

3

$ 890

Homer City Plant

Homer City failed to obtain sufficient interest from market participants to fund the capital improvements during the process 

undertaken in the fourth quarter of 2011, and Homer City is currently engaged in discussions with the owner-lessors 

regarding the potential for such funding. EMG expects that the outcome of any such discussions, if successful in providing 

funding for the Homer City plant, will likely result in EMG's loss of substantially all beneficial economic interest in and 

material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the 

Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the ownerlessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of 

Homer City, or both. In connection with the preparation of its year end financial statements, EMG concluded that these 

events combined with the current and projected financial condition of Homer City were indicators of impairment. The longlived asset group subject to the impairment evaluation was determined to include the Homer City lease, leasehold 

improvements and prepaid rent. In assessing impairment, EMG concluded that the future undiscounted cash flows through 

the period in which EMG expects to continue to have significant economic interest and material control of the Homer City 

plant were insufficient to recover the carrying amount of the asset group. To measure the amount of impairment loss, the 

market and income approaches were considered the most appropriate and resulted in a zero fair value. EMG viewed the lack 

of interest from market participants to provide sufficient funding for the capital improvements as indicative that the fair value 

of the asset group is zero. Furthermore, discounted cash flow analysis based on estimates of future energy, capacity and coal 

prices, operations and maintenance costs and operating lease payments along with the estimated costs of constructing the 

environmental control equipment also indicated a fair value of zero. Accordingly, EMG recorded an impairment charge of 

$1.03 billion for the fourth quarter of 2011. For additional information on the impairment of long-lived assets, see Note 1. 

Summary of Significant Accounting Policies—Impairment of Long-Lived Assets.
159

Included in the consolidated financial statements are the following assets and liabilities related to Homer City, excluding 

deferred taxes:

(in millions)

Cash

Restricted deposits

Inventory

Other assets

Total assets

Accounts payable and accrued liabilities

Pension and other postretirement benefits

Other liabilities

Total liabilities

Net assets

At December 31, 

2011

$ 84

27

105

43

259

30

49

13

92

$ 167

In addition, at December 31, 2011, EMMT had a $38 million intercompany accounts receivable from Homer City. In the 

event that EMG no longer controls Homer City, EMG will record a loss on disposition of assets and liabilities and classify 

Homer City as a discontinued operation. The loss on disposition will be determined based on the assets and liabilities at the 

date of disposition and an assessment whether any ongoing contingencies exist.

Midwest Generation Stations

A significant decline in power prices from September 30, 2011, combined with new environmental regulations and public 

policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants. In 

connection with the preparation of its year end financial statements, EMG concluded, based on the current energy price 

environment, it is less likely that Midwest Generation will install environmental controls required by the CPS at its Fisk, 

Crawford and Waukegan Stations; and such assessment was an indicator that these stations were impaired. The long-lived 

asset groups that were subject to the impairment evaluation were determined to include the property, plant and equipment of 

each station. Management updated the probability weighted future undiscounted cash flows expected to be received at these 

stations and concluded that such amounts did not recover the respective station's carrying amounts. As part of these 

alternative cash flow scenarios, management considered a shortened estimated useful life of each station if environmental 

improvements were not made and a forecasted reduction in generation from lower forward power prices. In February 2012, 

Midwest Generation decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014.

To measure the amount of the impairment loss, the income approach was considered the most relevant, but market data 

obtained prior to the significant decline in power prices was used to corroborate the income approach. The discounted cash 

flow analysis assumptions that have the most significant impact on fair value are forecasted energy and capacity prices. The 

discounted cash flow analysis indicated a fair value of zero. EMG also concluded it was unlikely that a third party would 

consummate the purchase of the Fisk, Crawford or Waukegan Stations in the current economic and regulatory environment 

resulting in a determination that the fair value of each of these stations is zero. This resulted in an impairment charge of 

$115 million, $186 million and $339 million for Fisk, Crawford and Waukegan Stations, respectively. Environmental and 

other remediation or ongoing maintenance costs are expected to be offset by the salvage value of the asset groups. For 

additional information on the impairment of long-lived assets, see Note 1. Summary of Significant Accounting Policies—

Impairment of Long-Lived Assets.

In the fourth quarter of 2010, Midwest Generation recorded a $40 million write-off of capitalized engineering and other costs 

related to a change in air emissions control technology selection at the Powerton Station.

Lease Termination

Pursuant to the Global Settlement with the IRS, a subsidiary of EMG terminated its interests in cross-border leases during the 

first half of 2009 (for further discussion see Note 7. Income Taxes for further discussion). The net proceeds and loss, before 

income tax, from termination of the cross-border leases were $1.385 billion and $920 million, respectively. In addition, 

interest in another leverage lease transaction, Midland Cogeneration Ventures, was sold during the second quarter of 2009, 

resulting in a pre-tax gain on sale of $33 million.
160

Wind Projects

In connection with the preparation of its year end financial statements, management has reviewed the Storm Lake project and 

four small wind projects in Minnesota for impairment in the fourth quarter of 2011 based on an expected future increase in 

operating costs and declines in long-term power prices that the projects could potentially realize following the term of the 

power purchase agreements. The probability weighted future undiscounted cash flows of each project are not expected to be 

sufficient to recover the respective carrying value of each of these long-lived assets ($53 million in aggregate). The income 

approach was utilized to determine fair value for these asset groups. The most significant assumptions used in determining 

fair value were discount rates, future wind generation, the future availability of the project to generate energy and future plant 

operations expense. The asset groups at each project consisted of property, plant and equipment and, where appropriate, 

deferred revenue. In aggregate, the fair value of these five asset groups was determined to be $23 million, resulting in an 

impairment charge of $30 million. For additional information on the impairment of long-lived assets, see Note 1. Summary of 

Significant Accounting Policies—Impairment of Long-Lived Assets.

During the fourth quarter of 2011, EMG significantly reduced development of renewable energy projects to conserve cash 

and in light of more limited market opportunities. As a result, EMG reduced staffing and has undertaken efforts to reduce 

funding joint development projects, thereby reducing the development pipeline of potential wind projects to a projected 

installed capacity to approximately 1,300 megawatts. These changes triggered charges of $34 million.

Fair Value

The fair value of the long-lived assets and wind projects as determined using the discounted cash flow models discussed 

above qualified as Level 3 in the fair value hierarchy.

American Airlines Lease

In the fourth quarter of 2011, EMG recorded a $26 million pre-tax earnings charge ($16 million after-tax) related to a write 

down of net investments in aircraft leases with American Airlines.

Note 17. Other Income and Expenses

Other income and expenses are as follows:

(in millions)

Other income:

Equity Available Funds Used During Construction

Increase in cash surrender value of life insurance policies

Energy settlement

Other

Total utility other income

Competitive power generation and other income

Total other income

Other expenses:

Civic, political and related activities and donations

Marketing services

Other

Total utility other expenses

Competitive power generation and other expenses

Total other expenses

Years ended December 31,

2011

$ 96

26

2

11

135

21

$ 156

$ 30

7

18

55

—

$ 55

2010

$ 100

25

5

11

141

7

$ 148

$ 28

7

16

51

—

$ 51

2009

$ 116

23

9

12

160

11

$ 171

$ 28

11

10

49

8

$ 57

During 2009, the CPUC and FERC authorized the transfer of the Mountainview power plant to utility rate base which 

resulted in a non-cash accounting benefit of approximately $46 million. This non-cash accounting benefit primarily resulted 

from the establishment of regulatory assets to recognize $50 million in differences in the accounting treatment for nonregulated and rate-regulated entities mainly related to equity AFUDC. There was no economic impact to customers from this 

change as compared to the FERC-approved power-purchase agreement. 
161

Note 18. Business Segments

The following is information (including the elimination of intercompany transactions) related to Edison International's 

reportable segments:

(in millions)

Operating revenue

Depreciation, decommissioning and amortization

Interest and dividend income

Equity in income from partnerships and

unconsolidated subsidiaries – net

Interest expense – net of amounts capitalized

Income tax expense (benefit) – continuing operations

Income (loss) from continuing operations

Net income (loss) attributable to common shareholders

Total assets

Capital expenditures

Electric

Utility

Year ended December 31, 2011

$ 10,577

1,426

5

—

463

601

1,144

1,085

40,315

4,122

Competitive

Power

Generation

$ 2,186

310

32

86

324

(864)

(1,087)

(1,089)

8,392

686

1

Parent and

Other2

$ (3)

1

—

—

21

(25)

(33)

(33)

(668)

—

Consolidated

Edison

International

$ 12,760

1,737

37

86

808

(288)

24

(37)

48,039

4,808

Operating Revenue

Depreciation, decommissioning and amortization

Interest and dividend income

Equity in income (loss) from partnerships and unconsolidated

subsidiaries-net

Interest expense -net of amounts capitalized

Income tax expense (benefit) - continuing operations

Income (loss) from continuing operations

Net income (loss) attributable to common shareholders

Total assets

Capital expenditures

Year ended December 31, 2010

$ 9,983

1,273

7

—

429

440

1,092

1,040

35,906

3,780

3

$ 2,429

249

30

106

264

(36)

219

224

9,597

763

1,4

$ (3)

—

(6)

—

10

(50)

(8)

(8)

27

—

5

$ 12,409

1,522

31

106

703

354

1,303

1,256

45,530

4,543

Operating revenue

Depreciation, decommissioning and amortization

Interest and dividend income

Equity in income from partnerships and unconsolidated

subsidiaries – net

Interest expense – net of amounts capitalized

Income tax expense (benefit) – continuing operations

Income (loss) from continuing operations

Net income (loss) attributable to common shareholders

Total assets

Capital expenditures

Year ended December 31, 2009

$ 9,965

1,178

11

—

420

249

1,371

1,226

32,474

2,999

3

$ 2,399

239

30

89

306

(284)

(391)

(395)

9,543

283

1,4

$ (3)

1

(9)

(47)

6

(63)

(28)

18

(573)

—

5

12,361

1,418

32

42

732

(98)

952

849

41,444

3,282

1 Includes earnings (losses) from discontinued operations of $(3) million, $4 million and $(7) million for the years ended 

December 31, 2011, 2010 and 2009, respectively.

2 Includes amounts from Edison International (parent) and other Edison International subsidiaries that are not significant as a 

reportable segment, as well as intercompany eliminations.

3 Includes earnings of $95 million and $306 million for the years ended December 31, 2010 and 2009, respectively, related to the 

federal and state impacts of the Global Settlement. See Note 7.

4

 Includes earnings (losses) of $52 million and $(610) million for the years ended December 31, 2010 and 2009, respectively, related 

to termination of Edison Capital's cross-border leases and the federal and state impacts of the Global Settlement on EMG. See 

Note 7.

5

 Includes earnings of $28 million and $50 million for the years ended December 31, 2010 and 2009, respectively, related to the 

federal and state impacts of the Global Settlement. See Note 7.
162

Note 19. Quarterly Financial Data (Unaudited)

(in millions, except per-share amounts)

Operating revenue

Operating income (loss)

Income (loss) from continuing operations

Income (loss) from discontinued operations – net

Net income (loss) attributable to common shareholders

Basic earnings (loss) per share:

Continuing operations

Discontinued operations

Total

Diluted earnings (loss) per share1

:

Continuing operations

Discontinued operations

Total

Dividends declared per share

Common stock prices:

High

Low

Close

2011

Total

$ 12,760

320

24

(3)

(37)

(0.10)

(0.01)

(0.11)

(0.10)

(0.01)

(0.11)

1.285

41.57

32.64

41.40

Fourth

$ 3,013

(1,319)

(824)

—

(839)

(2.57)

—

(2.57)

(2.57)

—

(2.57)

0.325

41.57

35.63

41.40

Third

$ 3,981

810

441

—

426

1.31

—

1.31

1.30

—

1.30

0.320

39.25

32.64

38.25

Second

$ 2,983

380

192

(1)

176

0.54

—

0.54

0.54

—

0.54

0.320

40.15

36.54

38.75

First

$ 2,782

450

216

(2)

200

0.62

(0.01)

0.61

0.62

(0.01)

0.61

0.320

39.20

35.12

36.59

(in millions, except per-share amounts)

Operating revenue

Operating income

Income from continuing operations

Income (loss) from discontinued operations – net

Net income attributable to common shareholders

Basic earnings (loss) per share:

Continuing operations

Discontinued operations

Total

Diluted earnings (loss) per share:

Continuing operations

Discontinued operations

Total

Dividends declared per share

Common stock prices:

High

Low

Close

2010

Total

$ 12,409

2,126

1,303

4

1,256

3.83

0.01

3.84

3.81

0.01

3.82

1.265

39.37

30.37

38.60

Fourth

$ 3,069

414

178

—

166

0.51

—

0.51

0.51

—

0.51

0.320

39.37

34.38

38.60

Third

$ 3,788

862

527

(4)

510

1.57

(0.01)

1.56

1.57

(0.01)

1.56

0.315

35.15

31.06

34.39

Second

$ 2,741

351

356

1

344

1.05

—

1.05

1.05

—

1.05

0.315

34.74

30.37

31.72

First

$ 2,810

498

243

6

236

0.70

0.02

0.72

0.70

0.02

0.72

0.315

35.82

31.88

34.17

1 Due to a loss for the three months and year ended December 31, 2011, there are no incremental shares in the diluted computation

because such shares would be considered antidilutive.

Due to the seasonal nature of Edison International's business, a significant amount of revenue and earnings are recorded in 

the third quarter of each year. As a result of rounding, the total of the four quarters does not always equal the amount for the 

year. 
163

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 

FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Edison International's management, under the supervision and with the participation of the company's Chief Executive 

Officer and Chief Financial Officer, has evaluated the effectiveness of Edison International's disclosure controls and 

procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended 

(the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer 

and Chief Financial Officer have concluded that, as of the end of the period, Edison International's disclosure controls and 

procedures are effective.

Management's Report on Internal Control Over Financial Reporting

Edison International's management is responsible for establishing and maintaining adequate internal control over financial 

reporting (as that term is defined in Rule 13a-15(f) and Rule 15d-15f under the Exchange Act) for Edison International. 

Under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, Edison 

International's management conducted an evaluation of the effectiveness of Edison International's internal control over 

financial reporting based on the framework set forth in Internal Control—Integrated Framework issued by the Committee of 

Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under the COSO framework, 

Edison International's management concluded that Edison International's internal control over financial reporting were 

effective as of December 31, 2011. Edison International's internal control over financial reporting as of December 31, 2011 

have been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report 

on the financial statements in Edison International's Annual Report, which is incorporated herein by this reference.

Internal Control Over Financial Reporting

There were no changes in Edison International’s internal control over financial reporting (as that term is defined in Rules 

13a-15(f) or 15d-15(f) under the Exchange Act) during the period to which this report relates that have materially affected, or

are reasonably likely to materially affect, Edison International’s internal control over financial reporting.

Jointly Owned Utility Plant

Edison International's scope of evaluation of internal control over financial reporting includes its Jointly Owned Utility 

Projects.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information concerning executive officers of Edison International is set forth in Part I in accordance with General 

Instruction G(3), pursuant to Instruction 3 to Item 401(b) of Regulation S-K. Other information responding to Item 10 will 

appear in Edison International's definitive Proxy Statement to be filed with the SEC in connection with Edison International's 

Annual Shareholders' Meeting to be held on April 26, 2012, under the headings "Item 1: Election of Directors," and "Board 

Committees" and is incorporated herein by this reference.

The Edison International Employee Ethics and Compliance Code is applicable to all officers and employees of Edison 

International and its subsidiaries. The Code is available on Edison International's Internet website at www.edisoninvestor.com 

at "Corporate Governance." Any amendments or waivers of Code provisions for the Company's principal executive officer, 

principal financial officer, principal accounting officer or controller, or persons performing similar functions, will be posted 

on Edison International's Internet website at www.edisoninvestor.com.
164

ITEM 11. EXECUTIVE COMPENSATION

Information responding to Item 11 will appear in the Proxy Statement under the headings "Compensation Discussion and 

Analysis," "Compensation Committee Interlocks and Insider Participation," "Summary Compensation Table," "Grants of 

Plan-Based Awards," "Outstanding Equity Awards at Fiscal Year-End," "Option Exercises and Stock Vested," "Pension 

Benefits," "Non-Qualified Deferred Compensation," "Potential Payments Upon Termination or Change in Control," and 

"Director Compensation" and is incorporated herein by this reference, and under the heading “Compensation Committee 

Report,” which is incorporated by reference in accordance with Instruction G(3) pursuant to Instruction 2 to Item 407(e)(5) of 

Regulation S-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND 

RELATED STOCKHOLDER MATTERS

Information responding to Item 12 will appear in the Proxy Statement under the headings "Stock Ownership of Directors and 

Executive Officers," and "Stock Ownership of Certain Shareholders," and is incorporated herein by this reference.

Equity Compensation Plans

The following Table sets forth, for each of Edison International's Equity compensation plans, the number of shares of Edison 

International Common Stock subject to outstanding options, warrant and rights to acquire such stock, the weighted-average 

exercise price of those outstanding options, warrants and rights, and the number of shares remaining available for future 

award grants as of December 31, 2011.

Plan Category

Equity compensation plans approved by

security holders

Equity compensation plans not 

approved by security holders3

Total

Number of securities to 

be issued upon exercise 

of outstanding options, 

warrants and rights

(a)

21,497,796

182,823

21,680,619

1

Weighted-average 

exercise price of 

outstanding options, 

warrants and rights

(b)

$34.99

$21.16

$34.86

Number of securities remaining

for future issuance under equity

compensation plans (excluding

securities reflected in column

(a))(c)

30,102,721

—

30,102,721

2

1 This amount includes 19,531,391 shares covered by outstanding stock options, 970,047 shares that could be delivered for 

outstanding performance share awards, 786,932 shares covered by outstanding restricted stock unit awards, and 209,426 

shares covered by outstanding deferred stock unit awards. The weighted-average exercise price of awards outstanding 

under equity compensation plan approved by security holders reflected in column (b) above is calculated based on the 

outstanding stock options under these plans as the other forms of wards outstanding have no exercise price.

2

 This amount is the aggregate number of shares available for new awards under the Edison International 2007 Performance 

Incentive Plan as of December 31, 2011, and includes shares that have become available from the Edison International 

Equity Compensation Plan and the Edison International 2000 Equity Plan (together, the "Prior Plans"). However, no 

additional awards have been granted under the Prior Plans since April 26, 2007, and all awards granted since that date 

have been made under the Edison International 2007 Performance Incentive Plan. The maximum number of shares or 

Edison International Common Stock that may be issued or transferred pursuant to awards under the Edison International 

2007 Performance Incentive Plan is 49,500,000 shares, plus the number of any shares subject to awards issued under the 

Prior Plans and outstanding as of April 26, 2007 that expire, cancel or terminate without being exercised or shares being 

issued. Shares available under the Edison International 2007 Performance Incentive Plan may generally, subject to certain 

limits set forth in the plan, be used for any type of award authorized under that plan, including stock options, restricted 

stock, performance shares, restricted or deferred units, and stock bonuses.

3

 The Edison International 2000 Equity Plan is a broad-based stock option plan that did not require shareholder approval. It 

was adopted in May 2000 by Edison International with an original authorization of 10,000,000 shares. The Edison 

International Compensation and Executive Personnel Committee is the plan administrator. Edison International 

nonqualified stock options were granted to employees of the Edison International companies under this plan, but the 

granting authority expired on April 26, 2007. Any outstanding shares as of that date that expire, cancel or terminate 

without being exercised or shares being issued increase the maximum shares that may be delivered under the Edison 

International 2007 Performance Incentive Plan as described in footnote (2) above. The exercise price was not less than the 

fair market value of a share of Edison International Common Stock on the date of grant and the stock options cannot be 

exercised more than 10 years after the date of grant.
165

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information responding to Item 13 will appear in the Proxy Statement under the headings "Certain Relationships and Related 

Transactions," and "Corporate Governance—Q: How does the Board determine which Directors are considered independent?

—Q: Which Directors has the Board determined are independent?" and "Where can I find the Company's corporate 

governance documents?" and is incorporated herein by this reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information responding to Item 14 will appear in the Proxy Statement under the heading "Independent Registered Public 

Accounting Firm Fees," and is incorporated herein by this reference.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

See Consolidated Financial Statements listed in the Table of Contents of this report.

(a)(2) Report of Independent Registered Public Accounting Firm and Schedules Supplementing Financial Statements

The following documents may be found in this report at the indicated page numbers:

 Page

Schedules III through V, inclusive, are omitted as not required or not applicable

(a)(3) Exhibits

See "Exhibit Index" beginning on page 173 of this report.

Edison International will furnish a copy of any exhibit listed in the accompanying Exhibit Index upon written request and 

upon payment to Edison International of its reasonable expenses of furnishing such exhibit, which shall be limited to 

photocopying charges and, if mailed to the requesting party, the cost of first-class postage.

Schedule I – Condensed Financial Information of Parent

Schedule II – Valuation and Qualifying Accounts

166

170
166

EDISON INTERNATIONAL

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED BALANCE SHEETS

(in millions)

Assets:

Cash and equivalents

Other current assets

Total current assets

Investments in subsidiaries

Deferred income tax

Other

Total assets

Liabilities and Shareholders' Equity:

Accounts payable

Other current liabilities

Total current liabilities

Long-term debt

Other

Common stockholders' equity

Total liabilities and common shareholders' equity

December 31,

2011

$ 28

236

264

10,511

150

192

$ 11,117

$ 4

448

452

400

210

10,055

$ 11,117

2010

$ 21

285

306

11,050

142

67

$ 11,565

$ —

456

456

410

116

10,583

$ 11,565
167

EDISON INTERNATIONAL

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME

For the Years Ended December 31, 2011, 2010 and 2009 

(in millions, except per-share amounts)

Operating revenue and other income

Operating expenses and interest expense

Loss before equity in earnings of subsidiaries

Equity in earnings (loss) of subsidiaries

Income (loss) before income taxes

Income tax benefit

Net income (loss) attributable to Edison International common

shareholders

Weighted-average common stock outstanding

Basic earnings (loss) per share

Diluted earnings (loss) per share

2011

$ —

63

(63)

(1)

(64)

(27)

$ (37)

326

$ (0.11)

$ (0.11)

2010

$ —

56

(56)

1,262

1,206

(50)

$ 1,256

326

$ 3.84

$ 3.82

2009

$ 1

50

(49)

833

784

(65)

$ 849

326

$ 2.59

$ 2.58
168

EDISON INTERNATIONAL

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2011, 2010 and 2009 

(in millions)

Net cash provided by operating activities

Cash flows from financing activities:

Long-term debt issued

Long-term debt issuance costs

Long-term debt repaid

Short-term debt financing – net

Settlements of stock-based compensation – net

Capital transfer

Dividends paid

Net cash used by financing activities

Net cash provided by investing activities:

Net increase (decrease) in cash and cash equivalents

Cash and cash equivalents, beginning of year

Cash and cash equivalents, end of year

2011

$ 437

—

—

—

(9)

(5)

—

(417)

(431)

1

7

21

$ 28

2010

$ 90

399

(3)

—

(66)

(6)

—

(411)

(87)

—

3

18

$ 21

2009

$ 267

9

—

(7)

(165)

(5)

3

(404)

(569)

—

(302)

320

$ 18

Note 1. Basis of Presentation

The accompanying condensed financial statements of Edison International (parent) should be read in conjunction with the 

consolidated financial statements and notes thereto of Edison International and subsidiaries ("Registrant") included in Part II, 

Item 8 of this Form 10-K. Edison International's (parent) significant accounting policies are consistent with those of the 

Registrant and its wholly-owned subsidiaries, SCE and EMG.

Dividends Paid

SCE paid cash dividends to Edison International of $461 million in 2011 and $300 million for both 2010 and 2009. 

Dividend Restrictions

The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent 

cost of capital proceeding, the CPUC sets an authorized capital structure for SCE which included a common equity 

component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's 

capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At December 31, 2011, 

SCE's 13-month weighted-average common equity component of total capitalization was 50.4% resulting in the capacity to 

pay $436 million in additional dividends.

Note 2. Debt and Credit Agreements

Long-Term Debt

As of December 31, 2011, Edison International (parent) had 3.75% senior notes outstanding of $400 million which matures 

in 2017. 

Credit Agreements and Short-Term Debt

Edison International (parent) has a $1.4 billion revolving credit facility with various banks that terminates in February 2013.

Edison International's (parent) short-term debt is generally used for liquidity purposes. At December 31, 2011, Edison 

International (parent)'s outstanding short-term debt was $10 million at a weighted-average interest rate of 0.66%. At 

December 31, 2010, the outstanding short-term debt was $19 million at a weighted-average interest rate of 0.63%.
169

The following table summarizes the status of the credit facility at December 31, 2011:

(in millions)

Commitment

Outstanding borrowings

Amount available

Edison

International

(parent)

$ 1,426

(10)

$ 1,416

Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of 

less than or equal to 0.65 to 1. At December 31, 2011, Edison International's consolidated debt to total capitalization ratio was 

0.56 to 1.

Note 3. Related-Party Transactions

Edison International (parent) had current receivables due from affiliates of $219 million and $62 million and current payables 

due to affiliates of $106 million and $315 million at December 31, 2011 and 2010, respectively. Edison International (parent) 

had long-term payables due to affiliates of $98 million and $25 million at December 31, 2011 and 2010, respectively.
170

EDISON INTERNATIONAL

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

(in millions)

For the Year ended December 31, 2011

Uncollectible accounts

Customers

All others

Total

For the Year ended December 31, 2010

Uncollectible accounts

Customers

All others

Total

For the Year ended December 31, 2009

Uncollectible accounts

Customers

All others

Total

Balance at

Beginning of

Period

$ 41.2

53.8

$ 95.0

$ 36.2

70.2

$ 106.4

$ 30.8

61.0

$ 91.8

Additions

Charged to

Costs and

Expenses

$ 31.0

19.2

$ 50.2

$ 27.0

15.0

$ 42.0

$ 28.7

21.2

$ 49.9

Charged to

Other

Accounts

$ —

—

$ —

$ 2.8

24.5

$ 27.3

$ —

—

$ —

b

Deductions

$ 25.1

35.4

$ 60.5

$ 24.8

55.9

$ 80.7

$ 23.3

12.0

$ 35.3

b

a

c

a

a

Balance at

End of

Period

$ 47.1

37.6

$ 84.7

$ 41.2

53.8

$ 95.0

$ 36.2

70.2

$ 106.4

a

 Accounts written off, net.

b

 In 2010, SCE recorded a reserve against an uncollectible receivable related to contract termination negotiations. During 

2011, the $23 million was written-off.

c EMG filed bankruptcy claims in the amount of $48 million related to the contracts terminated with Lehman Brothers 

through the termination provisions of its master netting agreements with a Lehman Brothers subsidiary. In 2010, EMG 

sold its bankruptcy claims.
171

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused 

this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 29, 2012

By:

EDISON INTERNATIONAL

/s/ Mark C. Clarke

Mark C. Clarke

Vice President and Controller

(Duly Authorized Officer and

Principal Accounting Officer)
172

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following 

persons on behalf of the registrant and in the capacities and on the date indicated.

Signature

Principal Executive Officer:

Theodore F. Craver, Jr.*

Principal Financial Officer:

W. James Scilacci*

Principal Accounting Officer:

Mark C. Clarke*

Board of Directors:

Jagjeet S. Bindra*

Vanessa C.L. Chang*

France A. Córdova*

Theodore F. Craver, Jr.*

Charles B. Curtis*

Bradford M. Freeman*

Luis G. Nogales*

Ronald L. Olson*

James M. Rosser*

Richard T. Schlosberg, III*

Thomas C. Sutton*

Peter J. Taylor*

Brett White*

Title

Chairman of the Board, President,

Chief Executive Officer and Director

Executive Vice President,

Chief Financial Officer and Treasurer

Vice President and Controller

Director

Director

Director

Director

Director

Director

Director

Director

Director

Director

Director

Director

Director

*By: 

Date: 

/s/ Mark C. Clarke

Mark C. Clarke

Vice President and Controller

(Attorney-in-fact)

February 29, 2012
173

EXHIBIT INDEX

Exhibit

Number

3.1

3.2

Edison International

4.1

Southern California Edison Company

4.2

4.3

Edison Mission Group

4.4

4.4.1

4.4.2

4.4.3

4.4.4

4.5

4.6

4.6.1

4.6.2

4.7

4.7.1

Description

Certificate of Restated Articles of Incorporation of Edison International, effective December 19, 2006 (File

No. 1-9936, filed as Exhibit 3.1 to Edison International's Form 10-K for the year ended December 31, 2006)*

Amended Bylaws of Edison International, as Adopted by the Board of Directors effective October 27, 2011

(File No. 1-9936, filed as Exhibit 3.1 to Edison International's Form 10-Q for the quarter ended September 30,

2011)*

Senior Indenture, dated September 10, 2010 (File No. 1-9936, filed as Exhibit 4.1 to Edison International's

Form 10-Q for the quarter ended September 30, 2010)*

Southern California Edison Company First Mortgage Bond Trust Indenture, dated as of October 1, 1923 (File

No. 1-2313, filed as Exhibit 4.2 to Southern California Edison Company's Form 10-K for the year ended

December 31, 2010)*

Southern California Edison Company Indenture, dated as of January 15, 1993 (File No. 1-2313, Form 8-K

dated January 28, 1993)*

Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank, National

Association as Trustee (File No. 333-68630, filed as Exhibit 4.1 to Edison Mission Energy's Form 8-K filed on

May 10, 2007)*

First Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo Bank,

National Association as Trustee (File No. 333-68630, filed as Exhibit 4.1.1 to Edison Mission Energy's Form 8-

K filed on May 10, 2007)*

Second Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo

Bank, National Association as Trustee (File No. 333-68630, filed as Exhibit 4.1.2 to Edison Mission Energy's

Form 8-K filed on May 10, 2007)*

Third Supplemental Indenture, dated as of May 7, 2007, between Edison Mission Energy and Wells Fargo

Bank, National Association as Trustee (File No. 333-68630, filed as Exhibit 4.1.3 to Edison Mission Energy's

Form 8-K filed on May 10, 2007)*

Fourth Supplemental Indenture, dated as of August 22, 2007, between Edison Mission Energy and Wells Fargo

Bank, National Association, as Trustee, supplementing the Indenture, dated as of May 7, 2007, (File

No. 333-68630, filed as Exhibit 4.1.4 to Edison Mission Energy's Form S-4 filed September 10, 2007)*

Second Supplemental Indenture, dated as of April 30, 2007, between Edison Mission Energy and The Bank of

New York, as Trustee, supplementing the Indenture, dated as of June 28, 1999, pursuant to which Edison

Mission Energy's 7.73% Senior Notes due 2009 were issued (File No. 333-30748, filed as Exhibit 4.1 to Edison

Mission Energy's Form 8-K filed May 1, 2007)*

Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank, National

Association as Trustee (File No. 333-68630, filed as Exhibit 4.1 to Edison Mission Energy's Form 8-K filed on

June 8, 2006)*

First Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo Bank,

National Association as Trustee, supplementing the Indenture, dated as of June 6, 2006 (File No. 333-68630,

filed as Exhibit 4.1.1 to Edison Mission Energy's Form 8-K filed on June 8, 2006)*

Second Supplemental Indenture, dated as of June 6, 2006, between Edison Mission Energy and Wells Fargo

Bank, National Association as Trustee, supplementing the Indenture, dated as of June 6, 2006 (File

No. 333-68630, filed as Exhibit 4.1.2 to Edison Mission Energy's Form 8-K filed on June 8, 2006)*

Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton

Trust I, as Owner Lessor (File No. 333-59348-01, filed as Exhibit 4.9 to Edison Mission Energy's and Midwest

Generation, LLC's Registration Statement on Form S-4 to the SEC on April 20, 2001)*

Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.7 hereto (File

No. 333-59348-01, filed as Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation, LLC's

Registration Statement on Form S-4 to the SEC on April 20, 2001)*
174

Exhibit

Number Description

4.8

4.8.1

4.9

4.9.1

4.10

4.10.1

4.11

4.11.1

4.12

4.12.1

4.12.2

4.13

4.13.1

Edison International

10.1**

Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust

I, as Owner Lessor (File No. 333-59348-01, filed as Exhibit 4.10 to Edison Mission Energy's and Midwest

Generation, LLC's Registration Statement on Form S-4 to the SEC on April 20, 2001)*

Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.8 hereto (File

No. 333-59348-01, filed as Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation, LLC's

Registration Statement on Form S-4 to the SEC on April 20, 2001)*

Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC,

Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton

Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New

York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through

Trustees (File No. 333-59348-01, filed as Exhibit 4.12 to Edison Mission Energy's and Midwest

Generation, LLC's Registration Statement on Form S-4 to the SEC on April 20, 2001)*

Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.9

hereto (File No. 333-59348-01, filed as Exhibit 4.12.1 to Edison Mission Energy's and Midwest

Generation, LLC's Registration Statement on Form S-4 to the SEC on April 20, 2001)*

Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet

Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as

the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease

Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees (File

No. 333-59348-01, filed as Exhibit 4.13 to Edison Mission Energy's and Midwest Generation, LLC's

Registration Statement on Form S-4 to the SEC on April 20, 2001)*

Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.10

hereto (File No. 333-59348-01, filed as Exhibit 4.13.1 to Edison Mission Energy's and Midwest

Generation, LLC's Registration Statement on Form S-4 to the SEC on April 20, 2001)*

Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest

Generation, LLC (File No. 000-24890, filed as Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year

ended December 31, 2000)*

Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.11 hereto

(File No. 000-24890, filed as Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended

December 31, 2000)*

Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City

OLI LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General

Electric Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease

Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee (File

No. 333-92047-03, filed as to Exhibit 4.4 to the EME Homer City Generation L.P. Form 10-K for the year

ended December 31, 2001)*

Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.12

hereto (File No. 333-92047-03, filed as Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for

the year ended December 31, 2001)*

Appendix A (Definitions) to the Participation Agreement constituting Exhibit 4.12 hereto (File

No. 333-92047-03, filed as Exhibit 4.4.2 to the EME Homer City Generation L.P. Form 10-K for the year ended

December 31, 2004)*

Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, between

Homer City OLI LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee (File

No. 333-92047-03, filed as Exhibit 4.9 to the EME Homer City Generation L.P. Form 10-K for the year ended

December 31, 2001)*

Schedule identifying substantially identical agreements to Open-End Mortgage, Security Agreement and

Assignment of Rents constituting Exhibit 4.13 hereto (File No. 333-92047-03, filed as Exhibit 4.9.1 to the EME

Homer City Generation L.P. Form 10-K for the year ended December 31, 2003)*

Amendment to 1985 Deferred Compensation Plan Agreement for Directors with James M. Rosser, dated

December 31, 2003 (File No. 1-2313, filed as Exhibit 10.36 to Southern California Edison Company's Form 10-

K for the year ended December 31, 2003)*
175

Exhibit

Number Description

10.2**

10.3**

10.4**

10.4.1**

10.4.2**

10.5**

10.6**

10.7**

10.7.1**

10.8**

10.9**

10.10**

10.11**

10.12**

10.13**

10.14**

10.15**

10.15.1**

10.15.2**

10.16**

10.17**

10.17.1**

10.17.2**

10.17.3**

10.17.4**

Director Deferred Compensation Plan as amended December 31, 2008 (File No. 1-9936, filed as Exhibit

No. 10.4 to Edison International's Form 10-K for the year ended December 31, 2008)*

2008 Director Deferred Compensation Plan, effective December 31, 2008 (File No. 1-9936, filed as Exhibit

No. 10.5 to Edison International's Form 10-K for the year ended December 31, 2008)*

Director Grantor Trust Agreement, dated August 1995 (File No. 1-9936, filed as Exhibit 10.10 to Edison

International's Form 10-K for the year ended December 31, 1995)*

Director Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002 (File No. 1-9936, filed as

Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 2002)*

Executive and Director Grantor Trust Agreements Amendment 2008-1 (File No. 1-9936, filed as Exhibit

No. 10.6.2 to Edison International's Form 10-K for the year ended December 31, 2008)*

Executive Deferred Compensation Plan, as amended and restated December 31, 2008

2008 Executive Deferred Compensation Plan, as amended and restated effective October 26, 2011

Executive Grantor Trust Agreement, dated August 1995 (File No. 1-9936, filed as Exhibit 10.12 to Edison

International's Form 10-K for the year ended December 31, 1995)*

Executive Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002 (File No. 1-9936, filed as

Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended June 30, 2002)*

Executive Supplemental Benefit Program, as amended December 31, 2008 (File No. 1-9936, filed as Exhibit

No. 10.10 to Edison International's Form 10-K for the year ended December 31, 2008)*

Executive Retirement Plan as restated effective December 31, 2008

2008 Executive Retirement Plan, as amended and restated effective October 26, 2011

Edison International Executive Incentive Compensation Plan, as amended in February 2009 (File No. 1-9936,

filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2009)*

2008 Executive Disability Plan, as amended and restated effective October 26, 2011

2008 Executive Survivor Benefit Plan, as amended and restated effective October 26, 2011

Retirement Plan for Directors, as amended and restated effective December 31, 2008 (File No. 1-9936 filed as

Exhibit No. 10.17 to Edison International's form 10-K for the year ended December 31, 2008)*

Equity Compensation Plan as restated effective January 1, 1998 (File No. 1-9936, filed as Exhibit 10.1 to

Edison International's Form 10-Q for the quarter ended June 30, 1998)*

Equity Compensation Plan Amendment No. 1, effective May 18, 2000 (File No. 1-9936, filed as Exhibit 10.4 to

Edison International's Form 10-Q for the quarter ended June 30, 2000)*

Amendment of Equity Compensation Plans, adopted October 25, 2006 (File No. 1-9936, filed as Exhibit 10.52

to Edison International's Form 10-K for the year ended December 31, 2006)*

2000 Equity Plan, effective May 18, 2000 (File No. 1-9936, filed as Exhibit 10.1 to Edison International's

Form 10-Q for the quarter ended June 30, 2000)*

Edison International 2007 Performance Incentive Plan as amended and restated in February 2011 (File

No. 1-9936, filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter ended June 30, 2011)*

Edison International 2008 Long-Term Incentives Terms and Conditions (File No. 1-9936, filed as Exhibit 10.2

to Edison International's Form 10-Q for the quarter ended March 31, 2008)*

Edison International 2009 Long-Term Incentives Terms and Conditions (File No. 1-9936, filed as Exhibit 10.2

to Edison International's Form 10-Q for the quarter ended March 31, 2009)*

Edison International 2010 Long-Term Incentives Terms and Conditions (File No. 1-9936, filed as Exhibit 10.2

to Edison International's Form 10-Q for the quarter ended March 31, 2010)*

Edison International 2011 Long-Term Incentives Terms and Conditions (File No. 1-9936, filed as Exhibit 10.2

to Edison International's Form 10-Q for the quarter ended March 31, 2011)*
176

Exhibit

Number Description

10.18**

10.18.1**

10.18.2**

10.18.3**

10.18.4**

10.18.5**

10.19**

10.19.1**

10.19.2**

10.20**

10.20.1**

10.20.2**

10.20.3**

10.21**

10.22**

10.23**

10.24**

10.25**

10.26

Terms and conditions for 2002 long-term compensation awards under the Equity Compensation Plan and 2000

Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended

March 31, 2002)*

Terms and conditions for 2003 long-term compensation awards under the Equity Compensation Plan and 2000

Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended

March 31, 2003)*

Terms and conditions for 2004 long-term compensation awards under the Equity Compensation Plan and 2000

Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended

March 31, 2004)*

Terms and conditions for 2005 long-term compensation award under the Equity Compensation Plan and 2000

Equity Plan (File No. 1-9936, filed as Exhibit 99.2 to Edison International's Form 8-K dated December 16,

2004 and filed on December 22, 2004)*

Terms and conditions for 2006 long-term compensation awards under the Equity Compensation Plan and 2000

Equity Plan (File No. 1-9936, filed as Exhibit 10.29 to Edison International's Form 10-K for the year ended

December 31, 2005)*

Terms and conditions for 2007 long-term compensation awards under the Equity Compensation Plan and the

2007 Performance Incentive Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q

for the quarter ended March 31, 2007)*

Director Nonqualified Stock Option Terms and Conditions under the Equity Compensation Plan (File

No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2002)*

Director 2004 Nonqualified Stock Option Terms and Conditions under the Equity Compensation Plan (File

No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2004)*

Director Nonqualified Stock Option Terms and Conditions under the 2007 Performance Incentive Plan

(File 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 2007)*

Edison International and Edison Capital Affiliate Option Exchange Offer Circular, dated July 3, 2000 (File

No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended September 30,

2000)*

Edison International and Edison Capital Affiliate Option Exchange Offer Summary of Deferred Compensation

Alternatives, dated July 3, 2000 (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for

the quarter ended September 30, 2000)*

Edison International and Edison Mission Energy Affiliate Option Exchange Offer Circular, dated July 3, 2000

(File No. 1-13434, filed as Exhibit 10.93 to the Edison Mission Energy's Form 10-K for the year ended

December 31, 2001)*

Edison International and Edison Mission Energy Affiliate Option Exchange Offer Summary of Deferred

Compensation Alternatives, dated July 3, 2000 (File No. 1-13434, filed as Exhibit 10.94 to the Edison Mission

Energy's Form 10-K for the year ended December 31, 2001)*

Estate and Financial Planning Program as amended December 31, 2008 (File No. 1-9936, filed as Exhibit

No. 10.24 to Edison International's Form 10-K for the year ended December 31, 2008)*

2008 Executive Severance Plan, as amended and restated effective December 7, 2011

Edison International and Southern California Edison Company Director Compensation Schedule, as adopted

June 23, 2011 (File No. 1-9936, filed as Exhibit 10.1 to Edison International's form 10-Q for the quarter ended

June 30, 2011)*

Edison International Director Matching Gifts Program, as adopted June 24, 2010 (File No. 1-9936, filed as

Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2010*

Edison International Director Nonqualified Stock Options 2005 Terms and Conditions (File No. 1-9936, filed as

Exhibit 99.3 to Edison International's Form 8-K dated May 19, 2005, and filed on May 25, 2005)*

Amended and Restated Agreement for the Allocation of Income Tax Liabilities and Benefits among Edison

International, Southern California Edison Company and The Mission Group dated September 10, 1996 (File

No. 1-9936, filed as Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended September 30,

2002)*
177

Exhibit

Number Description

10.26.1

10.26.2

10.26.3

10.26.4

10.27**

10.28**

10.29**

10.30**

10.30.1**

10.31

10.31.1

10.31.2

21

23

24.1

24.2

31.1

31.2

32

101

Amended and Restated Tax-Allocation Agreement among The Mission Group and its first-tier subsidiaries

dated September 10, 1996 (File No. 1-9936, filed as Exhibit 10.3.1 to Edison International's Form 10-Q for the

quarter ended September 30, 2002)*

Amended and Restated Tax-Allocation Agreement between Edison Capital and Edison Funding Company

(formerly Mission First Financial and Mission Funding Company) dated May 1, 1995 (File No. 1-9936, filed as

Exhibit 10.3.2 to Edison International's Form 10-Q for the quarter ended September 30, 2002)*

Amended and Restated Tax-Allocation Agreement between Mission Energy Holding Company and Edison

Mission Energy dated February 13, 2012 (File No. 333-68630, filed as Exhibit 10.11 to Edison Mission

Energy's Form 10-K for the year ended December 31, 2011)*

Amended and Restated Administrative Agreement Re Tax Allocation Payments, dated February 13, 2012,

among Edison International and subsidiary parties. (File No. 333-68630, filed as Exhibit 10.12 to Edison

Mission Energy's Form 10-K for the year ended December 31, 2011)*

Form of Indemnity Agreement between Edison International and its Directors and any officer, employee or

other agent designated by the Board of Directors (File No. 1-9936, filed as Exhibit 10.5 to Edison

International's Form 10-Q for the period ended June 30, 2005, and filed on August 9, 2005)*

Edison International 2011 Executive Annual Incentive Program (File No. 1-9936, filed as Exhibit 10.1 to

Edison International's Form 10-Q for the quarter ended March 31, 2011)*

Edison International Executive Perquisites (File No. 1-9936, filed as Exhibit No. 10.36 to Edison International's

Form 10-K for the year ended December 31, 2008)*

Section 409A and Other Conforming Amendments to Terms and Conditions (File No. 1-9936, filed as Exhibit

No. 10.37 to Edison International's Form 10-K for the year ended December 31, 2008)*

Section 409A Amendments to Director Terms and Conditions (File No. 1-9936, filed as Exhibit No. 10.37.1 to

Edison International's Form 10-K for the year ended December 31, 2008)*

Amended and Restated Credit Agreement, dated as of February 23, 2007, among Edison International and JP

Morgan Chase Bank, N.A., as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Credit

Suisse, Lehman Commercial Paper Inc., and Wells Fargo Bank, N.A., as Documentation Agents, and the

lenders thereto (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 8-K dated and filed

February 27, 2007)*

First Amendment to Amended and Restated Credit Agreement, dated as of February 14, 2008 (File No. 1-9936,

filed as Exhibit 10.1 to Edison International's Form 8-K dated and filed March 19, 2008)*

Second Amendment to Amended and Restated Credit Agreement, dated as of December 19, 2008 (File

No. 1-9936, filed as Exhibit 10.41 to Edison International's Form 10-K for the year ended December 31, 2008)*

Subsidiaries of the Registrant

Consent of Independent Registered Public Accounting Firm

Power of Attorney

Certified copy of Resolution of Board of Directors Authorizing Signature

Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

Statement Pursuant to 18 U.S.C. Section 1350

Financial statements from the annual report on Form 10-K of Edison International for the year ended

December 31, 2011, filed on February 29, 2012, formatted in XBRL: (i) the Consolidated Statements of

Income; (ii) the Consolidated Statements of Comprehensive Income; (iii) the Consolidated Balance Sheets;

(iv) the Consolidated Statements of Cash Flows; (v) Consolidated Statements of Changes in Equity and (vi) the

Notes to Consolidated Financial Statements

________________________________________

* Incorporated by reference pursuant to Rule 12b-32.

** Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)3.
(This page has been left blank intentionally.)
EDISON INTERNATIONAL 2011 ANNUAL REPORT

Theodore F. Craver, Jr.

Chairman of the Board,

President and

Chief Executive Officer

Edison International

A director since 2007

Jagjeet S. Bindra1,3

Retired President 

Chevron Global Manufacturing 

(an integrated energy company)

Dallas, Texas 

A director since 2010 

Vanessa C.L. Chang1,3

Principal

EL & EL Investments

(private real estate investment

company)

Los Angeles, California

A director since 2007

France A. Córdova1,4

President

Purdue University

West Lafayette, Indiana

A director since 2004

Charles B. Curtis3,4

President Emeritus

Nuclear Threat Initiative

(private foundation dealing with

national security issues)

Washington, DC

A director since 2006

Bradford M. Freeman2,3

Founding Partner

Freeman Spogli & Co.

(private investment company)

Los Angeles, California

A director since 2002

Luis G. Nogales1,2

Managing Partner

Nogales Investors, LLC

(private equity investment company)

Los Angeles, California

A director since 1993 

Ronald L. Olson3

Senior Partner

Munger, Tolles & Olson (law firm)

Los Angeles, California

A director since 1995

James M. Rosser2,4

President

California State University, Los Angeles

Los Angeles, California

A director since 1988

Richard T. Schlosberg, III2,4

Retired President and

Chief Executive Officer

The David and Lucile Packard 

Foundation

(private family foundation)

San Antonio, Texas

A director since 2002

Thomas C. Sutton1,3

Retired Chairman of the Board and 

Chief Executive Officer

Pacific Life Insurance Company

Newport Beach, California

A director since 1995

Peter J. Taylor1

Executive Vice President and

Chief Financial Officer

University of California

Oakland, California

A director since 2011

Brett White2,4

President and

Chief Executive Officer

CB Richard Ellis

(commercial real estate 

services company)

Los Angeles, California

A director since 2007

1 Audit Committee

2 Compensation and Executive

 Personnel Committee

3 Finance Committee

4 Nominating/Corporate Governance

 Committee

Theodore F. Craver, Jr.

Chairman of the Board,

President and

Chief Executive Officer

Robert L. Adler

Executive Vice President and

General Counsel

Polly L. Gault

Executive Vice President,

Public Affairs

W. James Scilacci

Executive Vice President,

Chief Financial Officer and

Treasurer

Janet T. Clayton

Senior Vice President,

Corporate Communications

Daryl D. David

Senior Vice President,

Human Resources

Bertrand A. Valdman

Senior Vice President,

Strategic Planning

Jeffrey L. Barnett

Vice President,

Tax

Mark C. Clarke

Vice President and Controller

Scott S. Cunningham

Vice President,

Investor Relations

David J. Heller

Vice President and Chief Ethics and

Compliance Officer

Dana Kracke 

Vice President,

Chairman's Office

Barbara E. Mathews

Vice President,

Associate General Counsel,

Chief Governance Officer and

Corporate Secretary

Megan Scott-Kakures

Vice President and

General Auditor

BOARD OF DIRECTORS EDISON INTERNATIONAL
EDISON INTERNATIONAL 2011 ANNUAL REPORT

SOUTHERN CALIFORNIA EDISON COMPANY

Ronald L. Litzinger

President

Stephen E. Pickett

Executive Vice President,

External Relations

Lynda L. Ziegler

Executive Vice President,

Power Delivery Services

Peter T. Dietrich

Senior Vice President,

Generation and 

Chief Nuclear Officer

Erwin G. Furukawa

Senior Vice President,

Customer Service

Stuart R. Hemphill

Senior Vice President,

Power Supply

Cecil R. House

Senior Vice President,

Safety & Operations Support and

Chief Procurement Officer

David L. Mead

Senior Vice President,

Transmission & Distribution

Leslie E. Starck

Senior Vice President,

Regulatory Affairs

Linda G. Sullivan

Senior Vice President and

Chief Financial Officer

Russell C. Swartz

Senior Vice President and

General Counsel

Gaddi H. Vasquez

Senior Vice President,

Public Affairs

Mahvash Yazdi

Senior Vice President,

Information Technology and

Business Integration and

Chief Information Officer

Douglas R. Bauder

Vice President, 

Generation and

Station Manager,

San Onofre Nuclear Generating Station

Robert C. Boada

Vice President and Treasurer

Lisa D. Cagnolatti

Vice President,

Business Customer Division

Caroline Choi

Vice President,

Regulatory & Environmental Policy

Kevin R. Cini

Vice President,

Rate Challenge Project

Ann P. Cohn

Vice President and

Associate General Counsel

Chris C. Dominski

Vice President and

Controller

Steven D. Eisenberg

Vice President, 

Energy Supply and Management

Veronica Gutierrez

Vice President,

Local Public Affairs

Harry B. Hutchison

Vice President,

Customer Service Operations

Todd L. Inlander

Vice President,

Client Services Planning and Controls

Akbar Jazayeri

Vice President,

Regulatory Operations

Walter J. Johnston

Vice President,

Power Delivery

Megan K. Jordan

Vice President,

Corporate Communications

Seth J. Kiner

Vice President,

Customer Programs and Services

R. W. (Russ) Krieger, Jr.

Vice President,

Power Production

Barbara E. Mathews

Vice President,

Associate General Counsel,

Chief Governance Officer and

Corporate Secretary

Patricia H. Miller

Vice President,

Human Resources

Stacy R. Mines

Vice President and Chief Ethics 

and Compliance Officer

Paul L. Multari

Vice President,

Major Projects

Thomas J. Palmisano

Vice President,

Nuclear Engineering

Kevin M. Payne

Vice President,

Engineering & Technical Services

Michael L. Pinter

Vice President,

Technology Delivery & Maintenance

Walter Rhodes

Vice President,

Supply Management

Megan Scott-Kakures

Vice President and General Auditor

Marc L. Ulrich

Vice President,

Renewable and Alternative Power

Pedro J. Pizarro

President 

Andrew J. Hertneky

Senior Vice President,

Marketing and Trading

John C. Kennedy

Senior Vice President,

Generation

Daniel McDevitt 

Senior Vice President and 

General Counsel 

Douglas R. McFarlan

Senior Vice President,

Public Affairs and

Communications

Maria C. Rigatti

Senior Vice President and 

Chief Financial Officer

Letitia D. Davis 

Vice President and

Chief Ethics and Compliance Officer 

Reem J. Fahey 

Vice President,

Market Policy & Operations

Karen A. House

Vice President,

Generation Technical Support

Randolph P. Mann 

Vice President, 

Development

Frederick W. McCluskey 

Vice President, 

Technical Services 

Aaron D. Moss 

Vice President and 

Controller

Charles S. Parnell

Vice President,

Public Affairs

William (Tres) Petmecky

Vice President and Treasurer 

Oded J. Rhone 

Vice President,

Development

Aram G. Sogomonian

Vice President,

Risk Management

Paul Weiss

Vice President,

Commercial Management and 

Marketing

Jenene J. Wilson

Vice President,

Human Resources

*Parent company of Edison Mission 

Energy and Edison Capital

EDISON MISSION GROUP*
FINANCIAL HIGHLIGHTS

Dollar amounts in millions, except per share data

Year ended December 31, 2011 2010 2009

Operating revenues $12,760 $12,409 $12,361 

Core earnings(1) $1,048 $1,140 $1,064

Non-core items:

Asset impairments and other charges, net $(1,082) $(24) —

Global settlement and lease terminations — $175 $(254)

Regulatory — — $46

Health care legislation — $(39) — 

Discontinued operations $(3) $4 $(7)

Net income (loss) attributable to Edison International common shareholders $(37) $1,256 $849

Basic earnings (loss) per common share attributable to Edison International 

common shareholders $(0.11) $3.84 $2.59

Dividends paid per common share $1.28 $1.26 $1.24

Total assets at December 31 $48,039 $45,530 $41,444

Total employees – Edison International and subsidiaries 19,930 20,117 19,244

BUSINESS HIGHLIGHTS

Southern California Edison

System rate base(2) $18,793 $16,811 $15,020

Capital expenditures $4,122 $3,780 $2,999

Peak demand (megawatts) 22,443 22,771 22,112

Total system sales (kilowatt-hours, in millions) 87,338 87,651 91,730

Renewable energy procured (as a percent of total portfolio) 21.1% 19.3% 16.8%

Edison Mission Group

Generation capacity at December 31 (megawatts) 10,379 9,852 10,072

Wind generation capacity (megawatts)

(in operation and under construction) 1,981 1,815 1,575

Power delivered(3) (kilowatt hours, in millions) 43,137 44,472 44,837

(1) Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States.

Management uses core earnings internally for financial planning and for analysis of performance. Core earnings are also used when

communicating with analysts and investors regarding our earnings results to facilitate comparisons of the Company's performance from

period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings

are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income

or loss from significant discrete items that management does not consider representative of ongoing earnings. 

(2) Rate base includes capital expenditures related to certain FERC-approved projects during the construction phase, as of year-end. 

(3) Excluding gas partnerships generation.
2244 WALNUT GROVE AVENUE

ROSEMEAD, CA 91770

www.edison.com

ES01AR2012