Use these links to rapidly review the document
TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

---

FORM 10-K

---

---

EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)

---

---

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

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 þ    No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o    No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check One):

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

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

The aggregate market value of registrant's voting stock held by non-affiliates was approximately $10.3 billion on or about June 30, 2010, based upon prices reported on the New York Stock Exchange. As of February 24, 2011, 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.

---

Table of Contents

TABLE OF CONTENTS

i

---

Table of Contents

ii

---

Table of Contents

iii

---

Table of Contents

iv

---

Table of Contents

v

---

Table of Contents

vi

---

Table of Contents

vii

---

Table of Contents

GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

viii

---

Table of Contents

ix

---

Table of Contents

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;

•

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;

•

risks associated with operating nuclear and other power generating facilities, including operating risks; nuclear fuel storage 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;

1

---

Table of Contents

•

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;

•

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, construction, permitting, and governmental approvals;

•

risks that competing transmission systems will be built by merchant transmission providers in SCE's territory: 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. Forward-looking 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.

2

---

Table of Contents

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, Edison Mission Energy ("EME"), a competitive power generation company, and Edison Capital, an infrastructure finance company. EME and Edison Capital are presented on a consolidated basis as Edison Mission Group Inc. ("EMG"), reflecting the integration of management and personnel at EME and Edison Capital. As a holding company, Edison International's progress and outlook are dependent on developments at its operating subsidiaries.

At December 31, 2010, Edison International and its subsidiaries had an aggregate of 20,117 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 operation 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 over 13 million people. In 2010, SCE's total operating revenue was derived as follows: 43.5% commercial customers, 39.5% residential customers, 6.0% industrial customers, 1.3% resale sales, 5.8% public authorities, and 3.9% agricultural and other customers. SCE had 18,230 full-time employees at December 31, 2010. SCE's operating revenue was approximately $10 billion in 2010.

Sources of power to serve SCE's customers during 2010 were approximately: 42% purchased power; 24% CDWR; and 34% SCE-owned generation.

SCE files separately an Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished 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 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.

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, 2010, EME and its subsidiaries employed 1,833 people.

EME'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 EME as a project. EME's operating projects primarily consist of coal-fired generating facilities, natural gas-fired generating facilities and renewable energy facilities, which include

3

---

Table of Contents

wind projects and one biomass project. As of December 31, 2010, EME's subsidiaries and affiliates owned or leased interests in 39 operating projects with an aggregate net physical capacity of 10,979 MW of which EME's pro rata share was 9,852 MW. At December 31, 2010, EME's subsidiaries and affiliates also owned four wind projects under construction totaling 480 MW of net generating capacity. EME's consolidated operating revenue in 2010 was approximately $2.4 billion.

EME files separately an Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished 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.

Prior to January 1, 2010, Edison International reported three business segments: electric utility operations (SCE), competitive power generation (EME) and financial services and other (Edison Capital and other EMG subsidiaries). As a result of termination of Edison Capital's cross-border leases during 2009 and the continued reduction of its remaining portfolio, the remaining business activity is no longer significant enough to report separately. Accordingly, the financial services and other segment has been combined into the competitive power generation segment for all periods presented. The combination of these business activities is consistent with the management structure of EMG and evaluation of performance by Edison International.

Edison International maintains a property and casualty insurance program for itself and its subsidiaries, which includes 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 issues, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments."

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.

SCE's rates and operations are subject to extensive regulation by the CPUC, FERC, NRC, CEC, and CAISO. EMG's operating projects are also subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels, and EMG is additionally subject to the market rules, procedures, and protocols of the markets in which it participates. Both SCE and EMG are also subject to the reliability standards for the bulk power system required by the North American Electric Reliability Corporation ("NERC").

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 providing the CPUC access to certain records, establishing accounting procedures to protect against subsidization of nonutility activities by SCE's customers, and following transfer pricing rules. In addition, the decision provides 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.

4

---

Table of Contents

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. The governing body of the CPUC consists of five Commissioners who are appointed by the Governor of California, confirmed by the California Senate and serve for six-year staggered terms.

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.

NERC

The NERC establishes and enforces reliability standards and critical infrastructure protection standards for the bulk power system. 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.

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 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 its San Onofre and Palo Verde Nuclear Generating Stations. NRC requirements govern the granting, amendment, and extension of licenses for the construction and operation of nuclear power plants and subject those power plants to continuing oversight, inspection, and performance assessment.

The NRC has continued to affirm that San Onofre is being operated safely. However, SCE has had to address a number of regulatory and performance issues for which corrective action is required to mitigate exposure to events that could have safety significance. In its September 1, 2010 mid-cycle performance review letter the NRC noted that although San Onofre had developed corrective actions to resolve previously noted human performance and problem identification and resolution issues, the corrective actions that had been implemented had not been fully effective. The NRC is conducting inspections over its

5

---

Table of Contents

baseline program, including inspections to evaluate progress on these issues, and to assess actions taken to improve the working environment for employees to feel free to raise safety concerns. The NRC is also conducting additional public meetings to discuss these issues. To address these regulatory and performance issues, SCE has applied increased management focus and other resources to San Onofre, with an associated impact on operations and maintenance costs. SCE anticipates that its corrective actions, and related additional management focus and operations and maintenance costs, will continue. If issues identified by the NRC remain uncorrected, these issues could have a material adverse effect on SCE.

Overview of Ratemaking Mechanisms

SCE sells electricity to retail customers at rates authorized by the CPUC. SCE sells transmission service and wholesale power at rates authorized by the FERC.

Base Rates

Base rates authorized by the CPUC and the FERC are intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution facilities (or "rate base"). These base rates provide for recovery of operations and maintenance costs, capital-related carrying costs (depreciation, taxes and interest) and a return or profit, on a forecast basis.

CPUC Base Rates

Base rates for SCE's generation and distribution functions provide a rate of return and are authorized by the CPUC through triennial GRC proceedings. The CPUC sets an annual revenue requirement for the base year which is made up of the carrying cost on capital investment (depreciation, return and taxes), plus the authorized level of operations and maintenance expense. The return is established by multiplying an authorized rate of return, determined in separate cost of capital proceedings (as discussed below), by SCE's investment in the generation and distribution rate base. In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecast basis. Adjustments to the revenue requirement for the remaining two years of a typical three-year GRC cycle are requested, based on criteria established in the GRC proceeding, which generally, among other items, include annual allowances for escalation in operation and maintenance costs, forecasted changes in capital-related investments and the timing and number of expected nuclear refueling outages. SCE's GRC decision for the 2009-2011 period was issued in March 2009 and was effective as of January 1, 2009. In the 2009 GRC, the CPUC determined the 2010 and 2011 authorized revenues by escalating the entire revenue requirement. 2009's authorized revenue requirement of $4.83 billion was escalated by 4.25% to create the 2010 authorized amount, which was in turn escalated by 4.35% to create the 2011 authorized amount. SCE filed its 2012 GRC application with the CPUC on November 23, 2010, to be effective on January 1, 2012. The CPUC has authorized a revenue decoupling mechanism, which allows the difference between the revenue authorized and the actual volume of electricity sales to be collected from or refunded to ratepayers. 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%, authorized cost of preferred equity of 6.01% and authorized return on common equity of 11.5%. In 2008, the CPUC approved a multi-year cost of capital mechanism, which allows for annual adjustments if certain thresholds are reached. In 2009, the CPUC granted SCE's request to extend SCE's existing capital structure and authorized rate of return of 11.5% through December 2012, absent any future potential annual adjustments. The revised mechanism will be subject to CPUC review in 2012 for the cost of capital established for 2013 and beyond. SCE's earnings may be impacted when actual financing costs are above or below its authorized costs for long-term debt and preferred equity financings.

FERC Base Rates

Base rates for SCE's transmission functions provide a rate of return and are authorized by the FERC in periodic proceedings that are similar to the CPUC GRC and cost of capital proceedings. Requested rate changes at the FERC are generally implemented before final approval of the application, with revenue collected prior to a final FERC decision being subject to refund. FERC-approved base rate revenues that vary from forecast are not recoverable or refundable and will therefore impact earnings.

6

---

Table of Contents

Cost-Recovery Rates

Cost-recovery mechanisms allow SCE to recover its costs, but do not allow a return. These mechanisms are used to recover SCE's costs of fuel, purchased-power, demand-side management programs, nuclear decommissioning, public purpose programs, certain operation and maintenance expenses, and depreciation expense related to certain projects. Although the CPUC authorizes balancing account mechanisms for such costs to refund or recover any differences between forecasted and actual costs, under- or over-collections in these balancing accounts do impact cash flows and can build rapidly.

The CPUC also authorizes the use of a balancing account to eliminate the effect on earnings from differences in revenue resulting from actual and forecasted electricity sales. Under this mechanism, the difference in revenue between actual and forecast electricity sales is recovered from or refunded to ratepayers and therefore does not impact SCE's earnings.

SCE's balancing account for fuel and power procurement-related costs is established under the Energy Resource Recovery Account ("ERRA") Mechanism. SCE files annual forecasts of the costs that it expects to incur during the following year and sets rates using forecasts. 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 generation revenue. For 2011, the trigger amount is approximately $252 million.

The majority of costs eligible for recovery through cost-recovery rates are subject to CPUC reasonableness reviews, and thus could negatively impact earnings and cash flows if found to be unreasonable and disallowed.

Energy Efficiency Shareholder Risk/Reward Incentive Mechanism

The CPUC has adopted an Energy Efficiency Risk/Reward Mechanism ("Energy Efficiency Mechanism") which allows SCE to earn incentives based on SCE's performance toward meeting CPUC energy efficiency goals. In December 2010, the CPUC modified and extended the existing Energy Efficiency Mechanism to apply to the 2009 energy efficiency program. Under the modified mechanism, SCE has the opportunity to earn an incentive of 7% of the value of the total energy efficiency savings created, if SCE achieves 85% or more of the CPUC's energy efficiency goals for the 2009 energy efficiency program year.

In November 2010, the CPUC issued a draft decision in a new rulemaking intended to review the framework of the Energy Efficiency Mechanism and to establish a mechanism applicable to performance during the 2010 – 2012 energy efficiency program cycle. SCE cannot predict when a final decision will be issued, the content of such final decision or the amount of earnings, if any, that SCE may receive as a result of the adoption of a new mechanism.

CDWR-Related Rates

As a result of the California energy crisis, in 2001 the California Department of Water Resources ("CDWR") entered into contracts to purchase power for sale at cost 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 are allocated by the CPUC among the customers of the investor-owned utilities (SCE, PG&E and SDG&E). SCE bills and collects from its customers the costs of power purchased and sold by the CDWR, CDWR bond-related charges and direct access exit fees. 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 revenue; but do affect customer rates. The remaining CDWR power contracts that were allocated to SCE terminate by the end of 2011. The bond-related charges and direct access exit fees continue until 2022.

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,

7

---

Table of Contents

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. In addition, customers may install their own on-site power generation facilities.

Competition with SCE is conducted mainly on the basis of price, as customers seek the lowest cost power available. The effect of competition on SCE generally is to reduce the number of customers purchasing power from SCE, but those customers typically continue to utilize and pay for SCE's transmission and distribution services.

In the area of transmission infrastructure, SCE may experience increased competition from merchant transmission providers.

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. In addition, power is provided to SCE's customers through purchases by the CDWR under contracts with third parties.

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 needed for generation under those power contracts) and to serve demand for gas at SCE's Mountainview and peaker plants, which are supplemental plants that only operate when demand for power is high. The physical 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:

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

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. In November 2010, SCE entered into an agreement to sell its interest in Four Corners subject to certain conditions and regulatory approvals.

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

8

---

Table of Contents

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 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 utility-owned generation assets and existing power procurement contracts on, 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 to all loads 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.

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 60,000 circuit miles of overhead lines, 43,500 circuit miles of underground lines and over 700 distribution substations, all of which are located in California.

SCE owns the generating facilities (and operates all of these facilities except Palo Verde and Four Corners, which are operated by Arizona Public Service Company ("APS")) listed in the following table.

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.

9

---

Table of Contents

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 2011 and 2040. 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."

SCE's rights in Four Corners, which is located on land of the Navajo Nation under an easement from the United States and a lease from the Navajo Nation, may be subject to defects. These defects include possible conflicting grants or encumbrances not ascertainable because of the absence of, or inadequacies in, the applicable recording law and record systems of the Bureau of Indian Affairs and the Navajo Nation, the possible inability of SCE to resort to legal process to enforce its rights against the Navajo Nation without Congressional consent, the possible impairment or termination under certain circumstances of the easement and lease by the Navajo Nation, Congress, or the Secretary of the Interior, and the possible invalidity of the trust indenture lien against SCE's interest in the easement, lease, and improvements on Four Corners. For more information on SCE's sale of its interest in Four Corners, see "Item 8. Edison International Notes to Consolidated Financial Statements Note 2. Property, Plant and Equipment."

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

---

Table of Contents

EDISON MISSION GROUP INC.

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). Rates may be based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be workably competitive, may be market based. Previously approved rates may also be revoked or modified by the FERC after notice and opportunity for hearing.

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 EWG. Most qualifying facilities, including EMG's qualifying facilities, are exempt from the ratemaking and several other provisions of the Federal Power Act. EMG's EWGs 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 the 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 EWG 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

Generally, 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 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 real-time 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 in this annual report, 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 MISO RTO, which includes all or parts of Illinois, Wisconsin, Indiana, Michigan, Ohio

11

---

Table of Contents

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 every 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 capacity resources.

Fuel Supply

The Midwest Generation plants purchase coal from several suppliers that operate mines in the Southern PRB of Wyoming. The total volume of coal consumed annually is largely dependent on the amount of generation and ranges between 17.5 million to 19.5 million tons. Coal is transported under long-term transportation agreements with Union Pacific Railroad and various short-haul carriers. Midwest Generation's long-term rail transportation contract with Union Pacific Railroad expires at the end of 2011. See "Item 1A. Risk Factors—Risks Related to EMG—Market Risks." As of December 31, 2010, Midwest Generation leased approximately 3,900 railcars to transport the coal from the mines to the generating stations and the leases have remaining terms that range from less than one year to nine 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 collectively consumes approximately 3.3 million to 3.5 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 consumes approximately 2 million tons of coal per year and can consume either raw or ready-to-burn coal. 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 and originates from mines that are within approximately 100 miles of the Homer City plant. Homer City purchases the majority of its coal under term contracts with the balance purchased in the spot market as needed.

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 most independent power producers and, in the case of utilities, are often 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, and the CPS could put the Midwest Generation plants at a disadvantage compared with competing plants not subject to similar regulations. Potential future climate change regulations could also put EMG's coal plants at a disadvantage compared to both power plants utilizing other fuels and utilities that may be able to recover climate change compliance costs through rate base mechanisms. In addition, the ability of these plants to compete may be affected by governmental and regulatory activities designed to support the construction and operation of power generation facilities fueled by renewable energy sources.

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

12

---

Table of Contents

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 of fuels, including coal, 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. 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—As an extension of its asset management activities, 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.

13

---

Table of Contents

Properties

Power Plants in Operation

As of December 31, 2010, EMG's operations consisted of ownership or leasehold interests in the following operating projects:

14

---

Table of Contents

Renewable Development Activities

At December 31, 2010, EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,600 MW and had four projects totaling 480 MW under construction. Projects under construction at December 31, 2010 were as follows:

Laredo Ridge and Big Sky achieved commercial operation on February 1, 2011 and February 18, 2011, respectively. EMG anticipates that the remaining projects under construction will also achieve commercial operation in 2011. In addition to the projects under construction at December 31, 2010, EMG expects the 55 MW Pinnacle project in West Virginia will commence construction in 2011 with anticipated commercial operation in 2011. For more information, see "Edison International Overview—EMG Renewable Program" in the MD&A.

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."

Energy and Infrastructure Investments

EMG's energy and infrastructure investments are held by Edison Capital in the form of leveraged leases, partnership interests in international infrastructure funds and affordable housing projects in the United States.

15

---

Table of Contents

As of December 31, 2010, Edison Capital is the lessor with an investment balance (including current lease receivable) of $166 million in the following leveraged 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 Affecting Sales from the Coal Plants" in the MD&A.

EME'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.

ENVIRONMENTAL REGULATION OF EDISON INTERNATIONAL AND SUBSIDIARIES

Because Edison International does not own or operate any assets, other than the stock of its subsidiaries, it does not have any direct environmental obligations or liabilities. However, 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 subsidiaries, 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" and in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" and "Note 10.—Regulatory and 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 emissions of GHGs 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.

16

---

Table of Contents

Federal Legislative/Regulatory Developments

Efforts to pass comprehensive federal climate change legislation have not yet been successful. The timing, content and potential effects on Edison International of any legislation that may be enacted remain uncertain. However, the US EPA has begun to issue federal GHG regulations that are likely to impact the operations of Edison International's subsidiaries.

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.

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. 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 and pollution control requirements that could delay such projects. If EMG or SCE is required to install controls in the future or otherwise modify its operations in order to reduce GHG emissions, the potential impact of the GHG tailoring rule will depend on the nature and timing of the controls or modifications, which remain uncertain.

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. Under the pending settlement, the US EPA will propose performance standards for GHG emissions from new and modified power plants and emissions guidelines for existing power plants in July 2011, and will finalize such regulations by May 2012, with compliance dates for existing power plants expected to be in 2015 or 2016. 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, with the first report due on March 31, 2011. EMG's 2010 GHG emissions were approximately 50.2 million metric tons. SCE's 2010 GHG emissions were approximately 6.5 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, generators and utilities 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 2010, the CARB finalized regulations establishing a California cap-and-trade program, which include revisions to the CARB's mandatory GHG emissions reporting regulation. The regulations and the cap-and-trade program itself are being challenged by various citizens' groups under the California Environmental Quality Act.

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 long-term financial commitments with generators that emit more than 1,100 pounds of CO₂ per MWh, the performance of a combined-cycle gas turbine generator. Accordingly, the prohibition applies to most coal-fired plants. Utility purchases of power

17

---

Table of Contents

generated by EMG's California facilities are subject to the emissions performance standards established in SB 1368. EMG believes that all of its California facilities meet SB 1368 standards, but EMG will continue to monitor the regulations, as they are developed, for potential impact on its existing facilities and its projects under development.

SB 1368 also affects the ability of utilities to make long-term capital investments in generators that do not meet the emission performance standards. 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.

California law also requires 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. Through December 31, 2010, SCE estimates its delivery of eligible renewable resources to customers to be 19% of its total energy portfolio. In accordance with the procurement rules and regulations, SCE expects to demonstrate full compliance with the RPS Program in its March 2011 filing. In addition, in September 2010, the CARB adopted a Renewable Electricity Standard, which requires SCE to demonstrate renewable energy production equal to 33% of its sales to retail customers for 2020 and each year thereafter. Subsequently, in February 2011, a California Senate bill was introduced that would impose a similar requirement that California utilities purchase 33% of their electricity requirements from renewable resources. It is unclear whether the legislation will preempt the CARB's standard, if it is enacted.

Edison International subsidiary operations in California and New Mexico may also be affected by the Western Climate Initiative ("WCI"), an agreement entered into by California, other western states and certain Canadian provinces, to develop strategies to reduce GHG emissions in the region to 15% below 2005 levels by 2020. In July 2010, the WCI partners released a comprehensive strategy for a regional cap-and-trade program, with a planned start date of January 2012, to help achieve their reduction goal. Recent political developments make it uncertain whether this regional program will proceed and what form it might take. As noted above, California is implementing its own program to reduce GHG emissions.

EMG's operations in Illinois may be affected by the Midwestern Greenhouse Gas Reduction Accord, an initiative by which six Midwestern states, including Illinois, and the Canadian province of Manitoba agreed to develop regional GHG emission reduction goals using a multi-sector cap-and-trade program. In May 2010, the Midwestern Greenhouse Gas Reduction Accord Advisory Group finalized recommendations and a model rule for emissions reduction targets and the design of a regional cap-and-trade program to serve as a basis for individual state legislative or regulatory action. However, there is substantial uncertainty as to whether the parties to the Midwestern Greenhouse Gas Reduction Accord intend to continue their efforts to develop or implement such a program, especially in light of the failure to pass a federal cap-and-trade program in the 111^th Congress.

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.

In December 2010, the U.S. Supreme Court agreed to review a case in which an appellate panel had endorsed the availability of judicial remedies for nuisance allegedly caused by GHG emissions associated with climate change. Oral argument before the Supreme Court is scheduled for April 2011. Currently pending, while the Supreme Court considers the matter before it, is an appeal before the Ninth Circuit of a federal district order dismissing a case against Edison International and other defendants brought by the Alaskan Native Village of Kivalina in which the plaintiffs seek damages of up to $400 million for the cost of relocating the village, which plaintiffs claim is no longer protected from storms because the Arctic sea ice has melted as the result of climate change. Edison International and the other defendants in the lawsuit recently requested the Ninth Circuit to defer oral argument on the appeal pending the Supreme Court's decision on related issues.

18

---

Table of Contents

Edison International cannot predict whether the legal principles emerging from the Supreme Court or any of the cases in the appellate courts will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts to resolve claims associated with climate change.

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 NO_x emissions from power plants) and fine particulate matter (affected by SO₂ and NO_x 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, NO_x and SO₂ emissions at the Midwest Generation plants. The CPS requires Midwest Generation to achieve air emission reductions for NO_x 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, NO_x 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 Transport Rules

The CAIR, issued by the US EPA on March 10, 2005, mandated significant reductions in NO_x 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 will remain in effect until the US EPA finalizes a revised regulation.

In July 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to reduce power plant emissions of NO_x and SO₂ substantially, starting in 2012, with additional reductions in 2014. The Transport Rule would replace the CAIR.

The US EPA has proposed allocating emission allowances based on the historic and projected emissions data from power plants, along with three possible approaches to emissions allowance trading. Under its preferred approach, a pollution limit would be set for each state, intrastate trading of allowances would be permitted among power plants, and limited interstate trading would also be permitted consistent with the requirement that each state meet its own pollution control obligations. Under the first alternative, a pollution limit would be set for each state, and only intrastate trading of allowances would be permitted. Under the second alternative, a pollution limit would be set for each state, an emissions limit would be set for each power plant, and limited emissions averaging would be permitted among affected units. In January 2011, the US EPA proposed two other possible approaches to emission allowance allocation. Both approaches would allocate allowances among units within each state based on each unit's proportional

19

---

Table of Contents

share of the state's total historic heat input, and the second approach would add a constraint based on a unit's reasonably foreseeable maximum emissions under the proposed Transport Rule trading programs.

The Transport Rule is scheduled to be finalized in 2011. The CAIR will remain in place until that time. Depending on the approach adopted, the Transport Rule may provide allowance allocations for the Midwest Generation plants which are adequate for the plants' needs or may require the Midwest Generation plants to procure additional allowances, based on projected emissions using the Illinois CPS allowable emission rates. The Transport Rule may require the installation of additional environmental equipment on Units 1 and 2 at the Homer City plant to reduce SO₂ emissions and, depending on the approach adopted, may also require Homer City to procure a significant number of additional allowances pending such installation or curtail operations if it is unable to do so on acceptable terms.

Proposed 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. The final standard is being taken into account in EMG's environmental compliance strategy. Revisions to SIPs to achieve compliance with the new standard are due to be submitted to the US EPA by February 2014, with a compliance deadline of August 2017.

Illinois

On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NO_x 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 principal emission standards and control technology requirements for NO_x and SO₂ under the CPS are as described below:

NO_x Emissions—Beginning in calendar year 2012 and continuing in each calendar year thereafter, Midwest Generation must comply with an annual and seasonal NO_x emission rate of no more than 0.11 lbs/million Btu. In addition to these standards, Midwest Generation must install and operate SNCR equipment on Units 7 and 8 at the Crawford Station by December 31, 2015.

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.

The CPS also specifies the control technologies that are to be installed on some units by specified dates. In these cases, Midwest Generation must either install the required technology by the specified deadline or shut down the unit. The CPS also required Midwest Generation to shut down Unit 6 at the Waukegan Station by December 31, 2007, and Units 1 and 2 at the Will County Station by December 31, 2010, which it has done.

During 2009, Midwest Generation also conducted tests of NO_x removal technology based on SNCR that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has concluded that installation of SNCR technology on multiple units will meet the NO_x portion of the CPS. Capital expenditures for installation of SNCR equipment are expected to be approximately $109 million in 2011.

Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO₂ emissions. Use of this technology in conjunction with low sulfur coal is expected to require substantially less capital and time than 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—Environmental Developments—Midwest Generation and Compliance Plans and Cost" in the MD&A.

Pennsylvania

The Homer City plant was subject to CAIR during 2010 and complied with both the NO_x and SO₂ requirements using existing equipment and purchasing of SO₂ allowances. Pennsylvania adopted a state version of CAIR, which the US EPA approved in December 2009. Homer City expects to comply with the

20

---

Table of Contents

Pennsylvania CAIR, which is substantially similar to the federal CAIR, in the same manner in which it complies with the federal CAIR.

Mercury/Hazardous Air Pollutants

Clean Air Mercury Rule/Hazardous Air Pollutant Regulations

The CAMR was established by the US EPA as an attempt to reduce mercury emissions from existing coal-fired power plants using a cap-and-trade program. In February 2007, the U.S. Court of Appeals for the D.C. Circuit vacated both the CAMR and the related US EPA decision to remove oil- and coal-fired power plants from the list of sources to be regulated under the provisions of the CAA governing the emissions of HAPs.

In accordance with a consent decree entered in April 2010, the US EPA committed to proposing regulations by March 2011 limiting emissions of HAPs from coal- and oil-fired electrical generating units that are major sources of HAPs, and to finalizing such regulations by November 2011. The emissions standards must be designed to achieve the maximum degree of emission reduction that the US EPA determines is achievable for the affected units, taking into account costs and non-air quality environmental and health benefits (also referred to as maximum achievable control technology, or MACT, standard). Unlike the CAMR, the US EPA must regulate all of the HAPs emitted by these generating units. Compliance with the MACT standards will be required three years after the effective date of the final regulations. Until the US EPA's regulations are finalized, EMG cannot determine whether the actions it is taking to comply with other legal requirements (including the CPS) will be sufficient to address its obligations under the new HAPs regulations.

Illinois

Midwest Generation's compliance with the CPS supersedes the Illinois mercury regulations that would otherwise be applicable to the Midwest Generation plants. 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 installed required carbon injection equipment on all operating units in 2009 to achieve the necessary mercury reductions. Capital expenditures relating to these controls were $42 million. 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. The IEPA granted Midwest Generation a construction permit to install a cold side electrostatic precipitator on Unit 7 in November 2010.

Pennsylvania

Until Pennsylvania passes new legislation authorizing the adoption of mercury regulations or the US EPA finalizes a revised HAPs regulation that includes mercury limits, the Homer City plant will not be required to comply with Pennsylvania mercury limitations. The Pennsylvania Department of Environmental Protection ("PADEP") attempted to implement regulations reducing the mercury emissions at coal-fired power plants by 80% by 2010 and 90% by 2015, as embodied in the Pennsylvania CAMR SIP. The Pennsylvania Supreme Court upheld a decision by the Commonwealth Court declaring Pennsylvania's mercury rule unlawful, invalid and unenforceable, and enjoining the continued implementation and enforcement of the rule.

Ozone and Particulates

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. The US

21

---

Table of Contents

EPA is expected to finalize the revision to the ozone NAAQS by July 2011. It is expected that once the US EPA finalizes the revised ozone NAAQS, it will propose a second Transport Rule that may further affect electric power generating units. The US EPA is also expected to propose revised fine particulate matter NAAQS in 2011, which could result in further emission reduction requirements in future years.

Illinois

The Illinois SIP for compliance with 1997 8-hour ozone standard was submitted to the US EPA in March 2009. The SIP for fine particulates was submitted to the US EPA in June 2010. As the fine particulate and ozone standards are finalized, as described above, Illinois may be required to implement additional emission control measures to address emissions of NO_x, SO₂ and volatile organic compounds.

Pennsylvania

In August 2007, the US EPA accepted PADEP's maintenance plan, which indicated that the existing (and upcoming) regulations controlling emissions of volatile organic compounds and NO_x will result in continued compliance with the 1997 8-hour ozone standard. However, in March 2009, the PADEP recommended to the US EPA that Indiana County (where the Homer City plant is located) be designated non-attainment under the US EPA's 2008 revised 8-hour ozone standard. Until the US EPA completes its revision to the 8-hour ozone standard, redesignations are finalized, and additional regulations are developed to achieve attainment with the revised standard, EMG will not know what specific requirements it will have to meet. However, EMG expects that its currently installed SCRs will be capable of meeting these new requirements.

Effective April 1, 2009, the PADEP changed its air opacity policy, eliminating many exemptions and reducing the allowable exceedance rate to 0.5% of a unit's operating time. Homer City undertook optimization of unit ramp rates and combustion parameters at the Homer City plant to reduce the deratings required to meet the opacity standards. Additional capital improvements may also be required. Homer City operated below the 0.5% exceedance rate during 2010.

With respect to fine particulates, in November 2009, the US EPA determined that Indiana County (where the Homer City plant is located) had not attained applicable standards. The PADEP must submit an updated SIP by November 13, 2012. EMG cannot predict the potential effects on the Homer City plant of changes to the SIP.

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. The US EPA issued a final rulemaking on regional haze in 2005 requiring emission controls that constitute BART for industrial facilities that emit air pollutants which reduce visibility by causing or contributing to regional haze. These amendments required states to develop SIPs to comply with BART by December 2007, to identify the facilities that will have to reduce SO_2, NO_x and particulate matter emissions, and then to set BART emissions limits for those facilities. Failure to do so would result in the imposition of a FIP. Because the Four Corners plant is located on the Navajo Reservation there is no applicable SIP and the plant will be subject only to a FIP.

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 by approximately 2016 on all Four Corners units. In November 2010, SCE and APS entered into an agreement for the sale of SCE's Four Corners interest to APS, subject to regulatory approvals and other conditions. A final FIP is expected in 2011. Due to the investment constraints of SB 1368, the California law on GHG emission performance standards discussed above in "—Climate Change—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.

22

---

Table of Contents

Illinois and Pennsylvania

Beginning on December 31, 2009 Illinois and Pennsylvania became subject to a two-year deadline after which a FIP (which has not yet been proposed) will govern related emission issues. Pennsylvania submitted its proposed SIP revisions to the US EPA in December 2010 and Illinois is has prepared proposed revisions to its SIP and is expected to submit them to the US EPA in 2011. Illinois proposes 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 also proposes that the existing particulate matter emission limits on the Homer City plant, as well as the plant's participation in the CAIR, will satisfy the BART requirement in that state.

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 strategy has included both the filing of suits against a number of power plant owners, and the issuance of administrative NOVs to a number of power plant owners alleging NSR violations. 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 May 2010, four environmental organizations (Dine CARE, National Parks Conservation Association, Sierra Club, and To Nizhoni Ani) served SCE and the other Four Corners owners with a notice of intent to sue under the CAA alleging violations of NSR requirements. The US EPA has not initiated any NSR enforcement-related proceedings with respect to Four Corners. 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.

Water Quality

Clean Water Act

Regulations under the federal Clean Water Act govern critical 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. The US EPA is rewriting these regulations following a 2009 U.S. Supreme Court decision holding that the US EPA may consider, but is not required to use, a cost-benefit analysis for this purpose. The Supreme Court set a deadline of March 2011 for draft regulations, which are to be finalized by July 2011.

Because there are no defined compliance targets absent a new rule, EMG and SCE are reviewing a wide range of possible control technologies. A new rule could have a material impact on EMG and SCE, but neither EMG nor SCE can determine the financial impact until the final compliance criteria have been published.

California—Prohibition on the Use of Ocean-Based Once-Through Cooling

California has a US EPA-approved program to issue individual or group (general) permits for the regulation of Clean Water Act discharges. California also regulates certain discharges not regulated by the US EPA. In May 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, which took effect on October 1, 2010, requires an independent engineering study to be completed prior to the fourth quarter of 2013 regarding the feasibility of compliance by California's two

23

---

Table of Contents

coastal nuclear power plants, which may result in significant capital expenditures at San Onofre and may affect its operations. The policy could adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined, in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory. The policy may also significantly impact SCE's ability to procure generating capacity from fossil-fuel plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity if other coastal power plants in California are forced to shut down or limit operations.

Illinois

Midwest Generation is a party to an administrative proceeding before the Illinois Pollution Control Board ("PCB") 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 Fisk, Crawford, 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.

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. 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 EMG and SCE to incur additional capital and operating costs without assurance that the additional costs could be recovered. For SCE, to the extent such expenditures are for long-term extended operation of Four Corners, SCE does not expect to participate in any such expenditures consistent with SB 1368, the California law on GHG emission performance standards (see "—Climate Change—Regional Initiatives and State Legislation" above for a description of SB 1368). 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, but the second approach would not require the retrofitting of landfills used for the disposal of coal combustion residuals.

24

---

Table of Contents

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. The construction, planning and project site identification of transmission lines that are outside of California are subject to the regulation of the relevant state agency. 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.

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.

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.

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, pollution control equipment 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. 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 off site 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."

25

---

Table of Contents

Edison International may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay upstream dividends or to repay funds for an extended period 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 its subsidiaries and their ability to make upstream distributions or to repay funds to Edison International. Prior to funding Edison International, Edison International's subsidiaries have financial and regulatory obligations that must be satisfied, including, among others, debt service and preferred stock dividends. 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.

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 its ability to pass through to its customers in rates its FERC-authorized revenue requirements. SCE's financial results also depend on its ability to earn through the rates it is allowed to charge an adequate return on capital, including long-term debt and equity. SCE's capital investment plan, California's commitment to renewable power, increasing environmental regulations, sensitivity to increasing natural gas costs and moderating demand, collectively place continuing upward pressure on customer rates. 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—SCE Rate Cases" 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, renewable attributes 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 resulting from its procurement activities, including exposure to commodity price and counterparty credit risks. In addition, SCE is subject to the risks of unfavorable or untimely CPUC decisions about the compliance of procurement activities 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: 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 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 adversely 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, system limitations and degradation, failure or breaches of critical

26

---

Table of Contents

information technology systems and interruptions in necessary supplies. See "SCE: Liquidity and Capital Resources—Capital Investment Plan" in the MD&A.

There are inherent risks associated with operating nuclear power generating facilities.

Continued NRC scrutiny of regulatory and performance issues at San Onofre may result in additional corrective actions that will increase operations and maintenance costs or require additional capital expenditures.

As discussed in "Item 1. Business—Southern California Edison Company—Regulation—Nuclear Power Plant Regulation," the NRC is conducting additional inspections and public meetings to assess the corrective actions taken at San Onofre in connection with various regulatory and performance issues. 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, 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.

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 a nuclear incident claim(s) 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.

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. Regulatory and Environmental Developments."

Financing Risks

As a capital intensive company, SCE relies on access to the capital markets. If SCE were unable to access capital markets or the cost of capital was to substantially increase, its liquidity and operations would be adversely affected.

SCE regularly accesses 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

27

---

Table of Contents

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 "SCE: Liquidity and Capital Resources—Historical Segment Cash Flows" in the MD&A.

RISKS RELATING TO EMG

Liquidity Risks

EME and its subsidiaries have significant cash requirements and limited sources of capital.

At December 31, 2010, EME had corporate cash and cash equivalents of $615 million and $484 million of available borrowing capacity under its $564 million credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $295 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012.

As of December 31, 2010, EME's consolidated debt was approximately $4.5 billion. EME's subsidiaries had $2.9 billion of long-term, power plant lease obligations that are due over a period ranging up to 24 years. Compliance with current and forthcoming environmental requirements will add to EME's near-term liquidity needs.

EME's and Midwest Generation's 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 the current credit facilities, depending on market conditions. In the case of a further downgrade, EME expects that these negative effects would become more pronounced. If EME's credit facilities are not extended or replaced, or 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 provide credit support for contracts for power and fuel related to merchant activities. The terms of EME's and its subsidiaries' debt instruments may restrict EME's subsidiaries 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 of EME's liquidity needs, see "EMG: Liquidity and Capital Resources" in the MD&A.

EME depends upon tax-allocation payments from Edison International to meet its obligations. EME receives these payments only if, and only to the extent that, Edison International is able to utilize tax losses and credits generated by EME.

EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group generates sufficient taxable income to be able to utilize EME's consolidated tax losses and credits in the consolidated income tax returns for Edison International and its subsidiaries. The timing of certain tax-allocation payments was delayed in 2010 as a result of the Small Business Jobs Act and the 2010 Tax Relief Act, because Edison International was not able to fully utilize EME's consolidated tax losses and credits. Tax-allocation payments to EME may be further delayed until tax benefits are fully utilized by Edison International on a consolidated basis, which may take several years as a result of these new tax laws. See "Edison International Overview—Bonus Depreciation Impact on Edison International" in the MD&A for further discussion.

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 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 Tax-Allocation Agreement" in the MD&A.

28

---

Table of Contents

Regulatory and Environmental Risks

The controls imposed on the Midwest Generation plants as a result of the Combined Pollutant Standard may require material expenditures or unit shutdowns.

All of Midwest Generation's Illinois coal-fired electric generating units are subject to the CPS. Capital expenditures relating to controls contemplated by the CPS are expected to be significant and could make some units uneconomic to maintain or operate. Midwest Generation may ultimately decide to comply with CPS requirements by shutting down units rather than making improvements. Unit shutdowns could have an adverse effect on EMG's business, results of operation and financial condition. For more information about the CPS requirements and Midwest Generation's plans for compliance, see "Item 1. Business—Environmental Matters and Regulations—Air Quality—Nitrogen Oxide and Sulfur Dioxide—Illinois."

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 have declined significantly in recent years as a result of increased use of demand response technology, changes in final demand for power during the economic slowdown, and technological developments that have permitted the exploitation of natural gas shale reserves in a way that has resulted 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 or whether EMG can effectively hedge the risks involved on economic terms. 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 long-term transportation contract that will expire in 2011.

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

29

---

Table of Contents

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 development projects may not be successful.

EMG's development activities are subject to risks including, without limitation, risks related to the identification of project sites, financing, construction, permitting, governmental approvals and the negotiation of project agreements, including power purchase agreements. EMG may be required to spend significant amounts for preliminary engineering, permitting, fuel supply, resource exploration, legal and other expenses before it can determine whether a project is feasible, economically attractive, or capable of being built. As a result of these risks, EMG may not be successful in developing new projects, or the timing of such development 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. Projects under development may also be adversely affected by delays in construction or equipment deliveries, commissioning delays or performance issues, and agreements with off-takers may contain damages and termination provisions related to failures to meet specified milestones. 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 with potentially higher risks of failure or outage than an average plant, 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."

30

---

Table of Contents

ITEM 3. LEGAL PROCEEDINGS

California Coastal Commission Potential Environmental Proceeding

In May 2010, the California Coastal Commission issued a NOV to SCE, its contractor and certain property owners related to activity on a property that was used for equipment storage related to a nearby SCE electricity line undergrounding construction project. The NOV alleged that SCE, through its contractor, violated the California Coastal Act by removing without the appropriate permits approximately one acre of vegetation from the property, which was located in a protected coastal zone within and adjacent to the City of Newport Beach, California. In the NOV, the Coastal Commission indicated an interest in negotiating a settlement of the alleged violations but no settlement has been reached. The Coastal Act provides for penalties of up to $30,000 per violation, which may be increased by up to $15,000 per day per violation for knowing and intentional violations. SCE has sought indemnification from its contractor for liability associated with the NOV.

For a discussion of other material pending legal proceedings affecting Edison International and its subsidiaries, see "Item 8. Edison International Notes to the Consolidated Financial Statements—Note 9. Commitments and Contingencies."

Pursuant to Form 10-K's General Instruction G(3), the following information in included as an additional item in Part I:

EXECUTIVE OFFICERS OF THE REGISTRANT

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 and David, and have served in their present positions for the periods stated below. Additionally, those officers who have

31

---

Table of Contents

had other or additional principal positions in the past five years had the following business experience during that period:

32

---

Table of Contents

PART II

ITEM 4. RESERVED

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 18. 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 2010.

33

---

Table of Contents

Comparison of Five-Year Cumulative Total Return

ITEM 6. SELECTED FINANCIAL DATA

Selected Financial Data: 2006 – 2010

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.

34

---

Table of Contents

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

EDISON INTERNATIONAL OVERVIEW

Edison International is a holding company whose operations are conducted through its wholly owned subsidiaries. Its principal wholly owned subsidiaries are SCE, a rate-regulated electric utility that supplies electric energy to an approximately 50,000 square-mile area of southern California; and EMG, a wholly owned competitive power generation company that operates in 12 states.

Highlights of Operating Results

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 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 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, 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 2010 core earnings increased $110 million primarily due to higher operating income and capitalized financing costs (AFUDC), both driven by higher rate base growth, and lower income tax expense. The lower tax expense in 2010 includes a change in the method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program.

EMG's 2010 core earnings decreased $30 million from 2009 primarily from higher plant maintenance costs in 2010 due to scheduled outages in EMG's merchant power plants, unrealized losses in 2010 compared to gains in 2009, higher income tax expense partially offset by higher energy trading revenues.

35

---

Table of Contents

Edison International Parent and Other 2010 core losses increased from 2009 primarily due to higher interest and general and administrative costs.

Consolidated non-core items for Edison International included:

•

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 a revision to interest recorded on the federal Global Settlement. In 2009, Edison International recorded an after-tax earnings charge of $254 million related to the Global Settlement with the IRS and termination of EMG's cross-border leases ($920 million pre-tax loss). 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 the recently enacted federal health care legislation. The new 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 the fourth quarter of 2010 resulting from the write-off of capitalized engineering and other costs for air emissions control technology that is not currently being pursued for use at the Powerton Station. These activities were previously suspended as Midwest Generation pursued testing and evaluation of the use of a dry sorbent injection system using Trona or similar sorbents which is expected to require lower capital costs. The Illinois EPA recently issued a construction permit to authorize installation of a dry sorbent injection system, which Midwest Generation currently expects to use if this project is undertaken. For further discussion, see "—Environmental Developments—Midwest Generation Environmental Compliance Plans and Costs" below.

•

An after-tax earnings benefit of $46 million recorded in 2009 resulting from the transfer of the Mountainview power plant to utility rate base pursuant to CPUC and FERC approvals.

See "SCE: Results of Operations" for discussion of SCE results of operations, including a comparison of 2009 results to 2008. Also, see "EMG: Results of Operations" for discussion of EMG results of operations, including a comparison of 2009 results to 2008.

Management Overview of SCE

During 2009 and 2010, SCE focused on the execution of its capital investment program. Capital expenditures under the program were primarily for: upgrading, maintaining and expanding SCE's transmission and distribution system; extending the useful life of generation assets; and installing smart meters. Total capital expenditures were $2.9 billion in 2009 and $3.8 billion in 2010. A description of SCE's capital program for 2011 – 2014 and status of major rate cases is discussed below.

Capital Program

SCE's capital program for 2011 – 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 for system reliability and increased access to renewable energy, including the Tehachapi, Devers-Colorado River, Eldorado-Ivanpah, Red Bluff and Alberhill projects.

•

Generation investments for nuclear and hydro-electric plant betterment projects and general facilities and technology needs.

•

Installing "smart" meters in households and small businesses, referred to as EdisonSmartConnect™. Through 2010, SCE installed 2 million smart meters and plans to complete installation of the remaining 3.3 million meters during 2011 and 2012.

36

---

Table of Contents

SCE forecasts capital expenditures in the range of $15.6 billion to $17.5 billion for 2011 – 2014. The rate of actual capital spending may be affected by permitting, regulatory, market and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plan." SCE plans to utilize cash generated from its operations, tax benefits and issuance of additional debt and preferred equity to fund its capital needs.

SCE Rate Cases

2012 CPUC General Rate Case

On November 23, 2010, SCE filed its 2012 GRC application requesting a 2012 base rate revenue requirement of $6.3 billion. After considering the effects of sales growth, SCE's request would be an $866 million increase in 2012 base rate revenue. The requested revenue requirement increase is driven by investments in capital projects to maintain system reliability and accommodate customer load growth, as well as an increase in operation and maintenance expenses primarily for capital-related projects, information technology, insurance premiums and pension contributions. If the CPUC approves the requested rate increase, the system average rate increase over base rate and total revenue requirement is estimated to be 16.2% and 7.6%, respectively. The increase excludes the impact of rate changes not associated with the CPUC GRC, such as rates to recover purchased power. The application also proposes a ratemaking mechanism that would result in 2013 and 2014 incremental base rate revenue requirement increases, net of sales growth of $246 million and $527 million, respectively, driven by the same reasons.

SCE is required to update its 2012 GRC request to reflect, among other items, the impacts of governmental and legislative actions. As part of this update, SCE expects the base rate revenue requirement will be reduced to reflect bonus depreciation (discussed below in "—Bonus Depreciation Impact on Edison International"). Bonus depreciation is an acceleration of future tax deductions which results in a reduction to rate base. SCE intends to update its 2012 GRC request after the IRS issues final regulations.

The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or when a final decision will be adopted.

FERC 2010 Rate Case

In February 2011, the FERC approved a settlement agreement in SCE's 2010 FERC rate case that provides a FERC retail base revenue requirement of $490 million, an increase of $42 million, or 9.4%, over the 2009 FERC base revenue requirement. The increased revenue requirement is primarily due to an increase in transmission capital investments and will be retroactive to March 1, 2010. As of December 31, 2010, SCE had collected revenue, subject to refund, of $58 million that will be refunded to ratepayers. SCE did not previously recognize revenue for the amount that will be refunded.

NRC Oversight of San Onofre

SCE continues to apply increased management focus and other resources to San Onofre to address regulatory and performance issues identified by the NRC (see "Item 1. Business—Southern California Edison Company—Regulation—Nuclear Power Plant Regulation" for further discussion).

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 its approximately 7,000 megawatts of coal-fired power plants. The profitability of these operations is expected to decline significantly in 2011 as a result of lower realized energy prices (largely driven by the expiration of hedge contracts) and higher fuel costs. In addition, the profitability of EMG's Midwest Generation plants is expected to be adversely affected in 2012 by a decline in capacity prices (projected to begin in June 2012) and higher rail transportation costs (due to the expiration at the end of 2011 of a favorable long-term rail contract). For discussion of energy and fuel price risks, see "EMG: Market Risk Exposures—Commodity Price Risk" and "Item 1A. Risk Factors—Risks Relating to EMG—Market Risks." As a result of the projected decrease in profitability of EMG's merchant

37

---

Table of Contents

activities, EMG may incur net losses during 2011 and in subsequent years unless energy prices recover or its costs decline.

At December 31, 2010, EMG and its subsidiaries had $1.1 billion in cash and cash equivalents and $981 million of liquidity available from credit facilities that expire in 2012. EMG's principal subsidiary, EME, had $3.7 billion of notes outstanding at December 31, 2010, $500 million of which mature in 2013. EMG business plans are focused on operating effectively through the current commodity price cycle and on environmental compliance and renewable energy plans as described below.

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

During 2010, Midwest Generation continued its permitting and planning activities for NO_x and SO₂ controls to meet the requirements of the CPS. Midwest Generation has received all necessary permits from the Illinois EPA to allow the installation of SNCR technology on multiple units to meet the NO_x portion of the CPS. In November 2010 and February 2011, the Illinois EPA issued construction permits authorizing Midwest Generation to install 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. The permit for Unit 7 for the Waukegan Station also authorizes Midwest Generation to convert the existing electrostatic precipitator to a cold-side design which will improve removal efficiency of particulate matter to satisfy the particulate control requirements of the CPS.

Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO₂ emissions. Use of this technology in conjunction with low sulfur coal is expected to require substantially less capital and time 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.

Based on work to date, Midwest Generation estimates the cost of retrofitting all units, 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 approximately $1.2 billion in 2010 dollars. If these projects are undertaken, these expenditures would be incurred through 2018.

Decisions regarding whether or not to proceed with the above projects or other approaches to compliance 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. Midwest Generation could also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation intends to defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others. Preconstruction engineering and initial construction work on a project may occur in 2011 in advance of a final decision to continue or complete the project.

Homer City Environmental Issues and Capital Resource Limitations

Homer City may be required to install additional environmental equipment on Units 1 and 2 to comply with environmental regulations under the Transport Rule. Homer City projects that if SO₂ reduction technology becomes required, it may need to make capital commitments for such equipment several years in advance of the effective date of such requirements. Homer City continues to review technologies available to reduce SO₂ and mercury emissions and to monitor developments related to hazardous pollutants and other environmental regulations. The timing, selection of technology and required capital costs remain uncertain. The installation of environmental compliance equipment will be dependent on lessor decisions regarding the funding of these expenditures. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. EME has no legal

38

---

Table of Contents

obligation to provide funding. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital have not been made.

EMG Renewable Program

At December 31, 2010, EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,600 MW and had four projects totaling 480 MW under construction. EMG anticipates that these projects will achieve commercial operation in 2011. In addition to the projects under construction at December 31, 2010, EMG expects the 55 MW Pinnacle project in West Virginia will commence construction in 2011 with anticipated commercial operation in 2011. The pace of additional growth in EMG's renewable program will be subject to the availability of third-party capital.

Bonus Depreciation Impact on Edison International

The Small Business Jobs Act of 2010 and The Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 ("2010 Tax Relief Act") extended 50% bonus depreciation for qualifying property through 2012 and created a new 100% bonus depreciation for qualifying property placed in service between September 9, 2010 and December 31, 2011. In addition to the update of the 2012 GRC discussed above, these provisions are expected to:

•

result in a consolidated net operating loss for federal income tax purposes for 2010 and 2011;

•

provide additional cash flow benefits during 2011 to SCE of approximately $550 million;

•

delay tax-allocation payments to EMG until tax benefits are fully utilized by Edison International on a consolidated basis which may take several years; and

•

eliminate income tax benefits from the domestic production activities deduction (also known as Section 199 deductions) of $16 million in 2011. The negative impact on 2010 net income was $15 million from recapture of 2008 Section 199 deductions realized in prior years resulting from the carry back of net operating losses.

The impact on cash flow represents an acceleration of tax benefits that would have otherwise been deductible over the life of the qualifying assets.

Environmental Regulation Developments

For a discussion of environmental regulation developments regarding Greenhouse Gas Regulation, the Transport Rule, Hazardous Air Pollutant Regulations, California Once-Through Cooling issues and Coal Combustion Wastes, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments."

39

---

Table of Contents

SOUTHERN CALIFORNIA EDISON COMPANY

RESULTS OF OPERATIONS

SCE's results of operations are derived mainly through two sources:

•

Utility earning activities – representing CPUC and FERC-authorized base rates, including an authorized reasonable return, and CPUC-authorized incentive mechanisms; and

•

Utility cost-recovery activities – representing CPUC-authorized balancing accounts which allow for recovery of costs incurred or provide for mechanisms to track and recover or refund differences in forecasted and actual amounts.

Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest (including interest on balancing accounts), taxes and a return, including the return on capital projects recovered through balancing account mechanisms. Differences between authorized amounts and actual results impact earnings. Also, included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.

Utility cost-recovery activities include rates that provide for recovery, subject to reasonableness review, of fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses, and depreciation expense related to certain projects. There is no return for cost-recovery expenses.

40

---

Table of Contents

Electric Utility Results of Operations

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.

Utility Earning Activities

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 related to the implementation of SCE's 2009 GRC (effective January 1, 2009) which authorized an increase of approximately $205 million ($15 million of which is reflected in utility cost-recovery activities) from SCE's 2009 revenue requirement.



•

$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 (see

41

---

Table of Contents

"Edison International Overview—SCE Rate Cases—2010 FERC Rate Case" for further discussion).

•

$55 million increase related to capital-related revenue requirements recovered through CPUC-authorized mechanisms outside of the GRC process primarily related to the steam generator replacement project and the EdisonSmartConnect^TM 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.

SCE completed the replacement of the steam generators at San Onofre Unit 2 and Unit 3 in April 2010 and February 2011, respectively. During the San Onofre Unit 2 scheduled outage, SCE identified and completed additional work unrelated to the steam generator replacement that resulted in increased operation and maintenance expense and extended the outage beyond SCE's initial estimated timeframe. The San Onofre Unit 3 outage was briefly extended beyond SCE's initial estimated timeframe.

The CPUC previously adopted a mechanism establishing thresholds for review and recovery of SCE's incurred capital costs for the steam generator replacements. Based on preliminary cost information, SCE does not expect a reasonableness review will be required. SCE will file an application with the CPUC setting forth its final costs and compliance with the adopted mechanism.

•

$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.

See "—Income Taxes" below for discussion of higher income taxes during 2010 compared to the same period in 2009.

42

---

Table of Contents

2009 vs. 2008

Utility earning activities were primarily affected by:

•

Higher operating revenue of $447 million primarily due to the following:

•

$485 million increase resulting from the implementation of SCE's 2009 CPUC GRC decision which authorized an increase of $512 million ($27 million of which is reflected in utility cost-recovery activities) from SCE's 2008 revenue requirement effective January 1, 2009.



•

$114 million increase resulting from the implementation of SCE's 2009 FERC approved rate case settlement effective March 1, 2009.



•

$25 million decrease due to the presentation of revenue requirements for medical, dental, and vision expenses and SCE's share of Palo Verde operation and maintenance expenses, which beginning in 2009 are reflected in utility cost-recovery activities consistent with the balancing account ratemaking treatment authorized in SCE's 2009 GRC.

•

Higher operation and maintenance expenses of $32 million primarily due to:

•

$105 million of higher transmission and distribution expenses primarily due to higher costs to support system reliability and infrastructure projects, increases in preventive maintenance work, as well as engineering costs.



•

$50 million of higher expenses related to regulatory and performance issues, including the NRC requiring SCE to take action to provide greater assurance of compliance by San Onofre personnel with applicable NRC requirements and procedures (See "Item 1. Business—Southern California Edison Company Regulation—Nuclear Power Plant Regulation" for further discussion).



•

$50 million of higher expenses associated with new information technology system requirements and facility maintenance to support company growth programs.



•

$175 million decrease due to presentation of medical, dental and vision expenses and SCE's share of Palo Verde operations and maintenance expenses, which beginning in 2009 are reflected in cost-recovery activities consistent with the balancing account ratemaking treatment authorized in SCE's 2009 GRC.

•

Higher depreciation expense of $69 million primarily resulting from increased capital expenditures including capitalized software costs.

•

Lower net interest expense and other of $116 million primarily due to:

•

Lower other expenses of $71 million primarily due to a final charge of $60 million ($49 million after-tax) recorded in 2008 resulting from the CPUC decision on SCE's PBR mechanism, as well as a $14 million decrease in civic, political and related activity expenditures primarily related to spending on Proposition 7 in 2008. These decreases were partially offset by an $8 million increase in donations.



•

Higher other income of $61 million due to an increase in AFUDC – equity earnings primarily resulting from a $50 million one-time gain resulting from the transfer of the Mountainview power plant to utility rate base authorized in SCE's 2009 GRC and a $12 million increase resulting from a higher level of construction work in progress associated with SCE's capital expenditure program.



•

Higher interest expense of $8 million primarily due to higher outstanding balances on long-term debt partially offset by lower interest expense on short-term borrowings. Due to an increase in cash flow from operations, including the positive cash impact from the Global Settlement and other tax timing differences, SCE was able to defer some of its expected financings in 2009 to support its growth programs.

43

---

Table of Contents

See "—Income Taxes" below for discussion of lower income taxes during 2009 compared to the same period in 2008.

Utility Cost-Recovery Activities

2010 vs. 2009

Utility cost-recovery activities excludes 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 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 and changes in SCE's hedge portfolio mix; lower bilateral energy purchase expense of $50 million primarily due to decreased kWh purchases associated with overall lower kWh demand; and lower net ISO-related and other energy costs of $50 million primarily due to milder weather experienced during 2010 compared to 2009. These decreases were partially offset by the purchase of replacement power costs related to the San Onofre Unit 2 extended outage and higher QF and renewable purchased power expense of $85 million primarily due to higher natural gas prices.

•

Higher fuel expense of $10 million related to a $25 million increase at the Mountainview power plant resulting from higher natural gas prices and a $10 million decrease at Four Corners resulting from a planned outage in 2010.

•

Higher operation and maintenance expense of $71 million primarily due to an increase in spending for various public purpose programs.

2009 vs. 2008

Utility cost-recovery activities excludes the impact of the consolidation of the Big 4 projects in 2009 and 2008 for comparability purposes. In addition to the 2009 amounts noted above, the following amounts were excluded for 2008: $692 million for purchased power expense to reflect the elimination of sales between the VIEs and SCE; $813 million for fuel expense; and $90 million for operation and maintenance expense. Utility cost-recovery activities were primarily affected by:

•

Lower purchased power expense of $1.4 billion primarily due to: lower bilateral energy and QF purchases of $1.6 billion primarily due to lower natural gas prices and decreased kWh purchases; and lower firm transmission rights costs of $65 million due to implementation of CAISO's MRTU market; and a change in net realized losses due to settled natural gas prices being significantly lower than average fixed prices. Realized losses on economic hedging activities were $344 million in 2009 and $60 million in 2008.

•

Lower fuel expense of $234 million primarily due to lower costs at the Mountainview plant resulting from lower natural gas costs in 2009 compared to 2008.

•

Higher operation and maintenance expense of $105 million primarily related to the presentation of $185 million of medical, dental, and vision expenses and its share of Palo Verde operation and maintenance expenses which beginning in 2009 are reflected in cost-recovery activities consisting with the balancing account ratemaking treatment authorized in SCE's 2009 GRC. In addition, SCE recorded higher pension and PBOP expenses of $60 million due to the volatile market conditions experienced in 2008. These increases were partially offset by $50 million of lower energy efficiency costs and $85 million of lower transmission access and reliability service charges.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $10 billion, $9.5 billion and $9.3 billion for 2010, 2009 and 2008. The 2010 and 2009 increases reflect a rate increase of $777 million and $564 million, respectively, and a sales volume decrease

44

---

Table of Contents

of $255 million and $380 million, respectively. The 2010 rate increase was due to higher system average rates for 2010 compared to the same periods in 2009 mainly due to the implementation of the CPUC 2009 GRC decision and approved FERC transmission rate changes. The 2010 sales volume decrease was primarily due to milder weather experienced during 2010 compared to the same period in 2009. Economic conditions continued to contribute to the sales volume decrease. The 2009 rate increase reflects a rate change effective April 4, 2009 due to the implementation of both revenue allocation and rate design changes authorized in Phase 2 of the 2009 GRC and the FERC transmission rate changes authorized in the 2009 FERC Rate Case. The 2009 sales volume decrease was due to the economic downturn as well as the milder weather experienced in 2009 compared to the same period in 2008. As a result of the CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk related to retail electricity sales (see "Item 1. Business—Southern California Edison Company—Overview of Ratemaking Mechanisms").

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, CDWR bond-related costs and a portion of direct access exit fees. The amounts collected and remitted to CDWR were $1.2 billion, $1.8 billion and $2.2 billion for years ended December 31, 2010, 2009 and 2008, respectively. Effective January 1, 2010, the CDWR-related rates were decreased to reflect lower power procurement expenses and to refund operating reserves that CDWR can release as these contracts begin to terminate. The remaining power contracts that CDWR allocated to SCE will terminate by the end of 2011. SCE's revenue and related purchased power expense is expected to increase as these CDWR contracts are replaced by power purchase agreements entered into by SCE.

Income Taxes

The table below provides an analysis of the principal factors impacting SCE's effective tax rate.

LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, complete planned capital projects, and implement its business strategy are dependent upon its cash flow and access to the capital markets to finance its activities. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its

45

---

Table of Contents

customers through regulated rates, changes in commodity prices and volumes, collateral requirements, dividend payments made to Edison International, and the outcome of tax and regulatory matters.

SCE expects to fund its continuing obligations and projected capital expenditures for 2011 and dividends to Edison International through cash and equivalents on hand, operating cash flows, tax benefits and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities if additional funding and liquidity are necessary to meet operating and capital requirements.

Available Liquidity

As of December 31, 2010, SCE had approximately $257 million of cash and equivalents. SCE had two credit facilities: a $2.4 billion five-year credit facility that matures in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that matures in March 2013.

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, 2010, SCE's debt to total capitalization ratio was 0.46 to 1.

Capital Investment Plan

SCE's capital expenditures for 2011 – 2014 include a capital forecast in the range of $15.6 billion to $17.5 billion. The 2011 planned capital expenditures for projects under CPUC jurisdiction are recovered through the authorized revenue requirement in SCE's 2009 GRC or through other CPUC-authorized mechanisms. Recovery of the 2012 – 2014 planned capital expenditures for projects under CPUC jurisdiction and not already approved through other CPUC-authorized mechanisms, is subject to the outcome of the 2012 CPUC GRC or other CPUC approvals. The 2011 planned capital expenditures for projects under FERC jurisdiction are recovered through the authorized FERC revenue requirement. Recovery of the 2012 – 2014 planned capital expenditures under FERC jurisdiction will be requested in future FERC transmission filings, as applicable.

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 capital expenditures (including accruals) in 2010 were $3.8 billion. The estimated capital expenditures for the next four years may vary from SCE's current forecast in a range of $15.6 billion to $17.5 billion based on the average variability experienced in 2009 and 2010 of 10.5%. SCE's 2010 capital expenditures

46

---

Table of Contents

and the 2011 – 2014 capital expenditures forecast, including the two-year historical average variability to the current forecast, is set forth in the table below:

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. Of the total forecasted distribution expenditures, $2.0 billion are recoverable through rates authorized in SCE's 2009 CPUC GRC decision, and $7.1 billion are subject to review and approval in the 2012 CPUC GRC proceeding.

Transmission Projects

SCE's has planned the following significant transmission projects:

•

Tehachapi Transmission Project – an 11-segment project consisting of new and upgraded transmission lines and associated substations primarily built to enhance reliability and enable the delivery of renewable energy generated primarily by wind farms in remote areas of eastern Kern County, California. Tehachapi segments 1, 2 and a portion of segment 3 were completed and placed in service in 2009. The remainder of segment 3 is under construction and expected to be placed in service over the period 2012 – 2013. SCE continues to seek the necessary licensing permits for Tehachapi segments 4 through 11, which are expected to be placed in service between 2011 and 2015, subject to receipt of licensing and regulatory approvals. SCE expects to invest $1.3 billion over the period 2011 – 2014 on this project. The FERC approved a 125 basis point ROE project adder, a 50 basis point incentive for CAISO participation, 100% CWIP in rate base treatment, and the ability to seek recovery of 100% abandoned plant costs (if any) on this project.

•

Devers-Colorado River Project – a transmission project involving the installation of a high voltage (500 kV) transmission line from western Riverside County, California to the Colorado River switchyard west of Blythe, California. The project is currently expected to be placed in service in 2013, subject to final licensing and regulatory approvals. Over the period 2011 – 2013, SCE expects to invest $655 million for this project. The FERC approved a 100 basis point ROE project adder, a 50 basis point adder for CAISO participation, 100% CWIP in rate base treatment and the ability to seek recovery of 100% abandoned plant costs (if any) on this project.

•

Eldorado-Ivanpah Transmission Project – a proposed 220/115 kV substation near Primm, Nevada and an upgrade of a 35-mile portion of an existing transmission line connecting the new substation to the Eldorado Substation, near Boulder City, Nevada. The project is currently expected to be placed in service in 2013, subject to necessary licensing and regulatory approvals. SCE expects to invest $483 million over the period 2011 – 2013 on this project. The FERC approved a 50 basis point incentive for CAISO participation, 100% CWIP in rate base treatment, and the ability to seek recovery of 100% abandoned plant costs (if any) on this project.

47

---

Table of Contents

•

Red Bluff Substation Project – a substation project that consists of a new 500/220 kV substation that loops into the existing Devers-Palo Verde 500 kV transmission line near Desert Center in Riverside County, California. The project is currently expected to be placed in service in 2013, subject to final licensing and regulatory approvals. SCE expects to invest $225 million over the period 2011 – 2013 on this project. The FERC approved 100% CWIP in rate base treatment and the ability to seek recovery of 100% abandoned plant costs (if any) on this project.

•

Other capital investments consisting of $2.3 billion to maintain reliability and expand capability of its infrastructure over the period 2011 – 2014.

Generation Projects

Generation expenditures of $2.3 billion include:

•

Nuclear-related capital expenditures that are 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 required infrastructure and equipment replacement and ongoing efforts to renew FERC licenses. Infrastructure expenditures generally include projects such as dam improvements, flowline and substation refurbishments, and powerline replacements. Equipment replacement expenditures generally include projects for transformers, automation, switchgear, hydro turbine repowers, generator rewinds, and small generator replacements.

EdisonSmartConnect^TM

SCE's EdisonSmartConnect^TM project involves installing state-of-the-art "smart" meters in approximately 5.3 million households and small businesses through its service territory. In March 2008, SCE was authorized by the CPUC to recover $1.63 billion in customer rates for the deployment phase of EdisonSmartConnect^TM. 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.

Solar Rooftop Program

In June 2009, the CPUC approved SCE's Solar Photovoltaic Program to develop up to 250 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 its investment. In February 2011, SCE filed an application with the CPUC to reduce the maximum utility owned solar projects from 250 MW to 125 MW and to allow SCE to purchase power from new solar projects up to 125 MW in a separate solicitation not subject to the same parameters as the original Program. SCE filed this application to permit greater competition and reduce overall solar program customer costs. SCE's capital expenditures for the period 2011 – 2014 reflect this reduction in procurement obligations and related estimated cost savings.

Regulatory Proceedings

Energy Efficiency Shareholder Mechanism

In December 2010, the CPUC issued a decision approving a $24 million final payment for 2006 – 2008 performance under the Energy Efficiency Mechanism and also modifying the mechanism. The modified mechanism will also be applied to the 2009 energy efficiency program year. SCE anticipates filing an application with the CPUC for incentives related to the 2009 program year performance, in the first half of 2011.

Based on the modified mechanism, SCE may recognize a 2009 program year payment of up to an estimated $27 million by December 2011; however, there is no assurance that SCE will receive any payment for that period. Additionally, the CPUC may further modify or eliminate this mechanism. See "Item 1. Business—Southern California Edison Company—Regulation—Energy Efficiency Shareholder Risk/Reward Incentive Mechanism" for further information on the Energy Efficiency Mechanism for the 2009 program year and the potential 2010 – 2012 mechanism.

48

---

Table of Contents

Ratemaking Mechanism to Track Bonus Depreciation

The CPUC has proposed a resolution that establishes a memorandum account to track the base rate revenue requirement reduction, if any, associated with the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act from the effective date of the resolution to the effective date of SCE's 2012 GRC decision. The CPUC will determine at a future date whether rates should be changed to reflect any benefits attributable to these Acts. The impact on the 2011 base rate revenue requirement is dependent upon, the ratemaking mechanism adopted, the final IRS regulations, the timing and amount of actual capital expenditures, working capital requirements and work order closings.

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 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, 2010, SCE's 13-month weighted-average common equity component of total capitalization was 51% resulting in the capacity to pay $497 million in additional dividends.

During 2010, SCE made a total of $300 million of dividend payments to its parent, Edison International, and in February 2011 declared a $115 million dividend to Edison International which is payable in March 2011. Future dividend amounts and timing of distributions are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings.

Income Tax Matters

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. This initial benefit was based on an estimated cumulative catch-up deduction for certain repair costs that were previously capitalized and depreciated over the tax depreciable life of the property. The deduction reflected on the 2009 income tax return was consistent with this cash benefit. The amount claimed on the 2009 tax return may be revised in the future based on further guidance from the IRS. The income tax benefit from the change in accounting for repair costs represents a timing difference which will reverse over the estimated remaining tax life of the assets. This method change, and incremental deductions taken in 2009 and 2010, did not impact SCE's 2009 or 2010 results of operations. Regulatory treatment for future increases in income taxes related to this matter will be addressed in SCE's 2012 GRC. SCE has not recognized an earnings benefit or regulatory asset, as the regulatory treatment is pending.

Margin and Collateral Deposits

Derivative Instruments and Power Procurement Contracts

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. Collateral requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments, and other factors. Future collateral requirements may be higher (or lower) than requirements at December 31, 2010, 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.

Certain of these power procurement contracts contain a provision that requires SCE to maintain an investment grade credit rating from the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral. The table

49

---

Table of Contents

below illustrates the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of December 31, 2010.

Potential Regulation of Swaps under the Dodd-Frank Act

The Dodd-Frank Act may impact margin, capital and collateral requirements in the future. See "Edison International (Consolidated)—Liquidity and Capital Resources—Potential Regulation of Swaps under the Dodd-Frank Act" for further discussion.

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, 2010, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $209 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. Balancing account over and under collections represent differences between cash collected in current rates and the costs incurred related to these regulatory mechanisms. In general, SCE seeks to adjust rates on an annual basis to recover or refund the balances recorded in certain balancing accounts. However, some over collections relate to specific programs that the CPUC has established annual funding levels in which funds must be spent by a certain date and therefore these over collections are not necessarily included in annual rate changes. Balancing account under collections and over collections accrue interest based on a three-month commercial paper rate published by the Federal Reserve.

As of December 31, 2010, balancing account net over collections were $1.3 billion primarily related to base rate differences, fuel and power procurement-related costs (ERRA) and various public purpose related-program costs. SCE expects to refund the base rate and ERRA combined over collection of $516 million through a rate adjustment beginning on June 1, 2011. The remaining over collections are expected to decrease as costs are incurred, amounts are refunded to ratepayers, or used to fund future programs established by the CPUC. Balancing account over or under collections may fluctuate due to, among other things, changes in: sales volume driven by growth or declines in customer base and weather; procurement-related costs driven both by market prices and sales volumes; and timing of expenditures under certain public purpose programs.

50

---

Table of Contents

Historical Segment Cash Flows

The table below sets forth condensed historical cash flow information for SCE:

Condensed Statement of Cash Flows

Net Cash Provided by Operating Activities

Cash provided by operating activities decreased $683 million in 2010, compared to the same period in 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 ERRA balancing account cash flows (collections of approximately $300 million in 2010, compared to collections of approximately $450 million in 2009). The ERRA balancing account was over-collected by $345 million at December 31, 2010, over-collected by $46 million at December 31, 2009 and under-collected by $406 million at December 31, 2008.

•

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.

Cash provided by operating activities increased $2.4 billion in 2009, compared to the same period in 2008. The cash flows provided by operating activities were primarily due to the following:

•

$875 million cash inflow from the receipt of payments due to Global Settlement related to the settlement of affirmative claims, a portion of which is timing and will be payable in future periods.

•

$468 million net cash inflow due to the increase in balancing account cash flows composed of:

•

$1.3 billion net cash inflow due to the increase in ERRA balancing account cash flows (collections of approximately $450 million in 2009, compared to refunds of approximately $840 million in 2008).



•

$820 million net cash outflow related to increased spending in 2009 compared to 2008 for public purpose and solar initiative programs and increased pension and PBOP contributions. In addition, a $200 million refund payment was received in 2008 related to public purpose programs.

•

$250 million cash inflow benefit related to the American Recovery and Reinvestment Act of 2009 50% bonus depreciation provision.

51

---

Table of Contents

•

$192 million cash inflow benefit related to the change in its tax accounting method for certain repair costs incurred on SCE's transmission, distribution and generation assets.

•

Higher cash inflow due to the increase in pre-tax income primarily driven by higher authorized revenue requirements resulting from the implementation of the 2009 CPUC and FERC GRC decisions.

•

Timing of cash receipts and disbursements related to working capital items.

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).

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.

•

Paid $300 million in dividends to Edison International.

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.

•

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.

Cash provided by financing activities for 2008 was $2.0 billion consisting of the following significant events:

•

Borrowed $1.4 billion under the line of credit to increase SCE's cash position to meet working capital requirements, if needed, during uncertainty over economic conditions during the second half of 2008.

•

Issued $600 million of first refunding mortgage bonds due in 2038. The proceeds were used to repay SCE's outstanding commercial paper of approximately $426 million and for general corporate purposes.

•

Issued $500 million of first and refunding mortgage bonds due in 2014. The proceeds were used for general corporate purposes.

•

Issued $400 million of 5.50% first and refunding mortgage bonds due in 2018. The proceeds were used to repay SCE's outstanding commercial paper of approximately $110 million and borrowings under the credit facility of $200 million, as well as for general corporate purposes.

•

Paid $325 million in dividends to Edison International.

52

---

Table of Contents

•

Purchased $212 million of its auction rate bonds, converted the issue to a variable rate structure, and terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

•

Paid $36 million for the purchase and delivery of outstanding common stock for settlement of stock based awards (facilitated by a third party).

Net Cash Used by Investing Activities

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $3.8 billion, $3.0 billion and $2.3 billion for 2010, 2009 and 2008, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $219 million, $199 million and $7 million for 2010, 2009 and 2008, respectively.

Contractual Obligations and Contingencies

Contractual Obligations

SCE's contractual obligations as of December 31, 2010, for the years 2011 through 2015 and thereafter are estimated below.

53

---

Table of Contents

Contingencies

SCE has contingencies related to FERC Rate Case, the Navajo Nation Litigation, nuclear 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, 2010, SCE identified 23 sites for remediation and recorded an estimated minimum liability of $50 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. SCE uses derivative instruments, as appropriate, to manage its market risks.

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. SCE's authorized return on common equity was 11.5% for 2010, 2009 and 2008, respectively, and has been authorized to remain at 11.5% through December 2012 absent any future potential annual adjustment. SCE's authorized return on common equity is established in a multi-year cost of capital mechanism, which allows for annual adjustments if certain thresholds are reached. Variances in actual financing costs compared to authorized financing costs impact earnings either positively or negatively.

At December 31, 2010, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $8.3 billion, compared to a carrying value of $7.6 billion. A 10% increase in market interest rates would have resulted in a $404 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 $444 million increase in the fair market value of SCE's long-term debt.

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 ratepayer exposure to variability in market prices related to SCE's power and gas activities. SCE expects recovery of its related hedging costs through the ERRA balancing account, 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 ratepayer 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

54

---

Table of Contents

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

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale exception. Derivative instrument fair values are marked to market at each reporting period. Any fair value changes are expected to be recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no impact on purchased-power expense or earnings. SCE does not use hedge accounting for 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 $207 million and $251 million at December 31, 2010 and 2009, respectively. The following table summarizes the increase or decrease to the fair values of outstanding derivative instruments as of December 31, 2010, if the electricity prices or gas prices were changed while leaving all other assumptions constant:

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. As of December 31, 2010, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

55

---

Table of Contents

The credit risk exposure set forth in the table above is composed of $7 million of net account receivables and $316 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

Four counterparties comprise 88% of the net exposure in the table above. The largest single net exposure was with the CAISO, mainly related to the CRRs' fair value, comprising 47% of the total net exposure in the table above.

56

---

Table of Contents

EDISON MISSION GROUP

RESULTS OF OPERATIONS

The following table is a summary of EMG's results of operations. Effective January 1, 2010, Edison International combined the competitive power generation and financial services segments into one business segment. The change resulted from termination of cross-border leases during 2009 and the continued reduction of the remaining portfolio of the financial services segment. Accordingly, the financial services segment has been combined retroactively for all periods presented into the competitive power generation business segment. The combination of these business activities is consistent with the management structure of EMG and evaluation of performance by Edison International.

Results of Continuing Operations

This section discusses operating results for 2010, 2009 and 2008. EMG's continuing operations include the fossil-fueled facilities, renewable energy and gas-fired projects, energy trading, and gas-fired projects under contract, corporate interest expense and general and administrative expenses. EMG's discontinued operations include all of its former international operations, except the Doga project.

The following table is a summary of competitive power generation results of operations for the periods indicated.

57

---

Table of Contents

EMG's 2010 core earnings were lower than 2009 core earnings primarily due to the following pre-tax items:

•

$108 million decreased income from Midwest Generation and Homer City primarily as a result of unrealized losses in 2010 compared to unrealized gains in 2009 related to hedge contracts, and higher plant maintenance costs in 2010, partially offset by higher capacity revenues and a $24 million gain on the sale of bankruptcy claims against Lehman Brothers. Energy and fuel related unrealized losses in 2010 were $33 million compared to unrealized gains of $60 million in 2009. Results in 2010 included the benefit of power hedge contracts entered into during earlier periods at higher prices than current energy prices. For additional information about market conditions, see "EMG: Market Risk Exposures."

•

$33 million gain in the second quarter of 2009 from the sale of an interest in a leverage lease (Midlands Cogeneration Ventures).

The decrease was offset by the following pre-tax items:

•

$61 million increased energy trading revenues due to congestion and power trading.

•

$34 million decreased interest expense, net of interest income, primarily due to the increase in the capitalization of interest on projects under construction.

•

$25 million decreased corporate expenses due primarily to lower renewable energy development expenses.

•

$13 million increased income from distributions received from the March Point and Doga projects.

In addition to the preceding pre-tax items, core earnings in 2010 were lower due to $15 million of increased tax expenses that resulted from the recapture of Section 199 deductions realized in prior years resulting from the carryback of net operating tax losses.

Consolidated non-core items for EMG included:

•

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 IRS in 2009 as part of the Global Settlement and a revision to interest on federal disputed tax items.

•

An after-tax loss of $610 million recorded in 2009 ($920 million pre-tax) resulting from the Global Settlement with the IRS and termination of Edison Capital's cross-border leases.

•

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 for air emissions control technology that is not currently being pursued for use at the Powerton Station. These activities were previously suspended as Midwest Generation pursued testing and evaluation of the use of a dry sorbent injection system using Trona or similar sorbents, which is expected to require lower capital costs. The Illinois EPA recently issued a construction permit to authorize installation of a dry sorbent injection system, which Midwest Generation currently expects to use if this project is undertaken. For further discussion, see "Edison International Overview—Environmental Developments—Midwest Generation Environmental Compliance Plans and Costs."

Adjusted Operating Income (Loss) ("AOI")—Overview

The following section and table provide a summary of results of EMG's operating projects and corporate expenses for the three years ended December 31, 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.

58

---

Table of Contents

The following table shows the adjusted operating income of EMG's projects:

The following table reconciles AOI to operating income as reflected on EMG's consolidated statements of income:

59

---

Table of Contents