This MD&A 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, or that otherwise could impact Edison International or its subsidiaries, include, but are not limited to:

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º the cost of capital and the ability to borrow funds and access to capital markets on reasonable terms;

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º the availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;

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º the 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;

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

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º the ability of SCE to recover its costs in a timely manner from its customers through regulated rates;

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º decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions;

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º changes in interest rates, rates of inflation including those rates which may be adjusted by public utility regulators, and foreign exchange rates;

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º 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 ISOs and regional transmission organizations;

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º environmental laws and regulations, both at the state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business;

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º risks associated with operating nuclear and other power generating facilities, including operating risks, nuclear fuel storage, equipment failure, availability, heat rate, output, availability and cost of spare parts, and cost of repairs and retrofits;

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º the cost and availability of labor, equipment and materials;

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º the 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;

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º the potential for penalties or disallowances caused by noncompliance with applicable laws and regulations;

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º effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;

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º creditworthiness of suppliers and other project participants and their ability to deliver goods and services under their contractual obligations to EME and its subsidiaries or to pay damages if they fail to fulfill those obligations;

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º the outcome of disputes with the IRS and other tax authorities regarding tax positions taken by Edison International;

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º the continued participation of Edison International's subsidiaries in tax-allocation and payment agreements;

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º supply and demand for electric capacity and energy, and the resulting prices and dispatch volumes, in the wholesale markets to which EME's generating units have access;

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º the cost and availability of coal, natural gas, fuel oil, nuclear fuel, and associated transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;

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º the cost and availability of emission credits or allowances for emission credits;

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

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

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º the risk of counterparty default in hedging transactions or power- purchase and fuel contracts;

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º the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities and technologies;

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º the difficulty of predicting wholesale prices, transmission congestion, energy demand and other aspects of the complex and volatile markets in which EMG and its subsidiaries participate;

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º general political, economic and business conditions;

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º weather conditions, natural disasters and other unforeseen events;

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º the risks inherent in undertaking large, complex generation projects and transmission and distribution infrastructure replacement and expansion projects including those related to siting, financing, construction, permitting, and governmental approvals; and

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º the risk that competing transmission systems will be built by merchant transmission providers in SCE's service territory.

Additional information about risks and uncertainties, including more detail about the factors described above, are discussed throughout this MD&A and in the "Risk Factors" section included in Part I, Item 1A of Edison International's Annual Report on Form 10-K. 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 Securities & Exchange Commission.

This MD&A for the three- and nine-month periods ended September 30, 2009 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2008, and as compared to the three- and nine month periods ended September 30, 2008. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2008 (the year-ended 2008 MD&A), which was included in Edison International's 2008 Annual Report to shareholders and incorporated by reference into Edison International's Annual Report on Form 10-K for the year ended December 31, 2008 filed with the Securities and Exchange Commission.

In this MD&A, except when stated to the contrary, 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.

The company-by-company discussion of SCE, EMG, and Edison International (parent) in this MD&A includes discussions of liquidity, market risk exposures, and other matters (as relevant to each principal business segment). The remaining sections discuss Edison International on a consolidated basis. The consolidated sections should be read in conjunction with the discussion of each company's section.

Areas of Business Focus

2010 FERC Rate Case

On September 30, 2009, FERC issued an order accepting SCE's proposed 2010 base transmission rates, subject to refund and settlement procedures, and made the rates effective March 1, 2010. The proposed base transmission rates will increase SCE's revenue requirement by $107 million, or 24%, over the 2009 base transmission revenue requirement primarily due to an increase in transmission rate base. The proposed rates, if approved, are expected to result in an approximate 1% increase to SCE's overall system average rate.

Cost of Capital Mechanism

The CPUC determines SCE's cost of capital in a multi-year proceeding occurring every three years. This cost of capital mechanism allows for an annual adjustment to SCE's capital costs if certain thresholds are reached. On October 15, 2009, the CPUC approved SCE's request to forgo an expected 2010 cost of capital increase under the annual adjustment provision and extended SCE's existing capital structure and authorized rate of return 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 set for 2013 and beyond.

Business Development and Capital Commitments

SCE

SCE's growth strategy includes infrastructure reliability investments and expanding the capability of its distribution and transmission infrastructure, constructing and replacing generation assets, and deploying advanced metering infrastructure. SCE continues to advance its growth strategy included in its 2009 - 2013 capital investment plan. SCE's significant planned projects are as follows:

Transmission and Distribution Projects

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º Devers-Colorado River Project - A transmission project that, as modified, would install a high voltage (500 kV) transmission line from Romoland, California to the Colorado River switchyard east 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 2009 - 2013, SCE expects to spend $637 million for the project, excluding the previously proposed Arizona portion of the project. The originally proposed project would have continued the transmission line through a portion of west Arizona, but due to a denial by the Arizona Corporation Commission the project was modified. SCE no longer plans to pursue construction of the Arizona portion at this time but continues to evaluate its transmission needs in western Arizona.

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º Tehachapi Transmission Project - An eleven segment project consisting of new and upgraded transmission lines and associated substations built primarily to enable the development of renewable energy generated primarily by wind farms in remote areas of eastern Kern County, California. Tehachapi segments one through three are under construction and are expected to be placed in service at various dates over the next two years. SCE continues to seek the necessary licensing permits for Tehachapi segments four through eleven, which are expected to be placed in service between 2011 and 2015, subject to receipt of licensing and regulatory approvals. SCE expects to spend $2.0 billion over the period 2009 - 2013 on this project.

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º 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. Over the period 2009 - 2013, SCE expects to spend $464 million for the project. On October 1, 2009, SCE filed a request for incentives at FERC for the Eldorado-Ivanpah Transmission Project. SCE requested 100% abandoned plant recovery, 100% CWIP recovery, and a 150 basis point ROE project adder.

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º EdisonSmartConnect™ - SCE's advanced metering project that will install "smart" meters in approximately 5.3 million households and small businesses throughout its service territory. SCE began full deployment of meters in 2009, and anticipates completion of the deployment in 2012. SCE estimates capital costs of $1.2 billion over the period 2009 - 2012.• Other capital investments consisting of $1.8 billion for transmission development and $10.1 billion for distribution projects to improve reliability and expand capability of its infrastructure over the period 2009 - 2013.

Generation Projects

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º San Onofre Steam Generator Replacement Project - Recently, SCE took delivery of the first two of four steam generators which are expected to be placed in service in the fourth quarter of 2009. The project is intended to enable San Onofre to operate until the end of its initial license period in 2022, and beyond if license renewal proves feasible. SCE expects to spend $459 million over the period 2009 - 2011.

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º Solar Photovoltaic Program - In June 2009, the CPUC issued a final decision approving a 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 rooftop and other space in SCE's service territory. The final decision also ordered SCE to solicit power purchase agreements from independent power producers for an additional 250 MW of rooftop solar photovoltaic power. SCE expects to spend $817 million over the period 2009 - 2013.

SCE's 2009 - 2013 total capital investment plan includes capital spending in the range of $16.8 billion to $19.8 billion. See "SCE: Liquidity-Capital Expenditures" for further discussion.

EMG

EME is continuing to focus on a selective growth strategy, primarily on development of future renewable projects deploying turbines secured under current turbine supply agreements including turbines in storage. At September 30, 2009, EME has contracts for the purchase of 785 MW of wind turbines. In October 2009, EME completed:

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º turbine financing for approximately $206 million for wind turbine purchase obligations related to the 240 MW Big Sky wind project. This project is scheduled for completion in early 2011. In addition, the turbine deposit for 22 wind turbines (46 MW) was converted into a deposit against future turbine orders; and

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º the acquisition of a 150 MW Cedro Hill wind project. EME plans to install 100 turbines (150 MW) to be purchased under its turbine supply agreement with General Electric Company to construct this project, which is scheduled for completion during the fourth quarter of 2010. EME plans to obtain project financing for this project prior to completion of construction.

EME plans to defer major construction expenditures for other new wind projects until construction and related project financing is available for such projects. Such financings generally require power

purchase agreements. EME continues to participate in requests for proposals issued by potential customers and to negotiate contracts where projects have been short-listed. If EME is unable to finance its projects on acceptable terms and conditions, certain turbine orders may be terminated. Such an event would likely result in a material charge. EME may store turbines that are delivered until needed for the construction of new wind projects. At September 30, 2009, EME has 67 wind turbines (163 MW) in storage.

Environmental Developments

Midwest Generation Environmental Compliance Plans and Costs

As discussed in the year-ended 2008 MD&A under the heading "Edison International: Management Overview-Areas of Business Focus-Environmental Developments-Air Quality Regulations in Illinois", Midwest Generation is subject to various commitments with respect to environmental compliance for the Illinois Plants under the CPS. Midwest Generation continues to review all technology and unit shutdown combinations, including interim and alternative compliance solutions. During 2009, Midwest Generation conducted tests of NOx removal technology based on selective non-catalytic reduction and flue gas desulfurization technology based on dry sodium sorbent injection that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has preliminarily concluded that installation of selective non-catalytic reduction technology in lieu of selective catalytic reduction technology should meet the NOx portion of the CPS. Testing of flue gas desulfurization technology based on injection of dry sodium sorbent demonstrated significant reductions in SO2; however, further analysis and evaluation are required to determine the appropriate path forward to comply with the SO2 portion of the CPS. These technologies may be deployed at the Illinois Plants in a manner which could optimize compliance, subject to approval of construction permits by the Illinois Environmental Protection Agency. A decision regarding whether or not to proceed with the alternative compliance program will occur following further analysis and evaluation of results. Under current conditions, Midwest Generation cannot predict what specific method will be used or the total costs that will be incurred to comply with the CPS.

Midwest Generation New Source Review Lawsuit

In August 2009, the US EPA and the State of Illinois filed a lawsuit in Illinois federal court based on claims contained in a previously disclosed 2007 NOV regarding alleged violations of the New Source Performance Standards of the CAA, the CAA's Title V operating permit requirements and applicable opacity and particulate matter standards. The lawsuit seeks, among other things, monetary penalties and an injunction requiring Midwest Generation to install the best available control technology at all units subject to the lawsuit. See "Legal Proceedings-Midwest Generation New Source Review Lawsuit" for further discussion.

Greenhouse Gas Regulation

Legislative, regulatory and legal developments related to potential controls over GHG emissions in the United States are ongoing. Actions to limit or reduce GHG emissions could significantly increase the cost of generating electricity from fossil fuels as well as the cost of purchased power. In the case of utilities, like SCE, these costs are generally borne by customers, whereas the increased costs for competitive generators, like EME, must be recovered through market prices for electricity.

Legislation to regulate GHG emissions continues to be considered by the Congress; however, the timing, content, and potential effects on Edison International and its subsidiaries of any climate change legislation that may be enacted remain uncertain. In June 2009, the American Clean Energy and Security Act was passed by the U.S. House of Representatives. The bill, which was endorsed by Edison International, would establish a 20% mandatory federal combined efficiency and renewable electricity

standard for certain retail electricity suppliers (SCE is already subject to a California law that requires California utilities to procure at least 20% of their annual electricity sales from renewable resources by 2010) and establish a cap-and-trade system for carbon emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate GHG emissions from all covered entities would be established and decline over time. Emitters of GHGs would be required to have allowances for GHG emissions emitted during a relevant measurement period. The bill would provide for stated portions of required allowances to be allocated (including allocation to merchant generators) free of charge in declining amounts over time. Emitters of GHGs would have to purchase the remainder of their required allowances in the open market, although a portion may be provided by so-called offset credits (for alternative GHG conservation efforts).

In April 2009, the US EPA responded to the 2007 U.S. Supreme Court decision in Massachusetts v. EPA by issuing a proposed finding that the current and projected concentrations of the mix of six key GHGs, including carbon dioxide, in the atmosphere threaten the public health and welfare of current and future generations and that such GHGs were air pollutants covered by the CAA. In September 2009, the US EPA issued its Final Mandatory Greenhouse Gas Reporting Rule, which will require all sources within specified categories, including electric generation facilities, to begin emissions monitoring in January 2010, and to submit annual reports to the US EPA by March 31 of each year, with the first report due on March 31, 2011. In September 2009, the US EPA also issued a proposed rule, known as the "tailoring rule," that if adopted would require new facilities with a potential to emit over 25,000 tons of GHGs per year (major GHG sources), or exisiting major GHG sources emitting over 25,000 tons of GHGs per year that are modified and, as a result, increase their potential GHG emissions by over 10,000 tons per year, to obtain pre-construction permits that would demonstrate that they are using best available control technologies to minimize their GHG emissions. If controls are required to be installed at the facilities of Edison International subsidiaries in the future in order to reduce GHG emissions pursuant to regulations issued by the US EPA or others, the potential impact will depend on the nature of the controls applied, which remains uncertain.

Three courts recently addressed the question of whether power plants that emit GHGs constituted public nuisances that could be held liable for damages or other remedies. In one case (in which Edison International is a named defendant), a California federal district court dismissed the plaintiffs' claims. In the other two, federal courts of appeals permitted the suits to go forward. These differing results remain subject to appeal and thus the ultimate impact of these cases remains uncertain. Edison International cannot predict whether these recent appellate decisions 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 for these sorts of claims. For further discussion, see "Other Developments-Environmental Matters-Climate Change-Litigation Developments."

In California, the Governor issued an executive order in September directing the CARB to adopt a regulation by July 31, 2010 that would require utilities to procure at least 33% of their annual electricity sales from renewable resources by 2020. The Order provides that the regulation could increase the targeted percentage of annual electricity sales to be obtained from renewable resources, as well as accelerate or expand the timeframe for compliance based on a thorough assessment of relevant factors. The resulting CARB regulations would be in addition to existing California law that requires California utilities to procure at least 20% of their annual electricity sales from renewable resources by 2010.

Commodity Prices

Economic conditions and mild weather during the summer months, among other factors, contributed to declines in electrical demand for Northern Illinois and PJM West Hub locations during the nine

months ended September 30, 2009. The electrical load, calculated from published data by PJM, for these locations declined 7% and 4% during the nine months ended September 30, 2009, respectively, compared to the corresponding period of 2008. The decline in price of natural gas, which often serves as the marginal fuel source in the region, together with lower electrical demand resulted in significantly lower energy prices. Furthermore, spot energy prices affecting the Illinois Plants were adversely impacted, particularly during some off-peak periods, by congestion affecting the Northern Illinois control area. The average 24-hour PJM market price for energy at the Northern Illinois Hub and the PJM West Hub declined to $28.62/MWh and $38.65/MWh, respectively, during the nine months ended September 30, 2009 as compared to $52.68/MWh and $73.86/MWh, respectively, during the nine months ended September 30, 2008. As reflected in the net income summary below, these factors had an adverse impact on the results of operations during the third quarter and nine months ended September 30, 2009. Lower electrical load has also generally decreased congestion in the eastern power grid, thereby resulting in lower trading income in the third quarter and nine months ended September 30, 2009.

Fluctuations in commodity prices and demand for electricity do not impact SCE's results of operations due to the recovery of purchased power costs in rates and the decoupling of electric sales from rates. As a result of lower commodity prices, SCE projects that it will recover its under-collected purchased power costs recorded in the ERRA balancing account without an increase in rates. See "SCE: Regulatory Developments-Current Regulatory Developments-Energy Resource Recovery Account Proceedings" in the year-ended 2008 MD&A.

Global Settlement

As previously disclosed, Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002. The Global Settlement and termination of the Edison Capital cross-border leases resulted in an Edison International consolidated after-tax earnings charge of $274 million through the second quarter of 2009. See "Other Developments-Federal and State Income Taxes," "Off-Balance Sheet Transactions-Leveraged Leases," and "Edison International (parent)-Liquidity-Intercompany Tax-Allocation Agreement" for further discussion.

Earnings Performance

The table below presents Edison International's earnings for the three-and
nine-month periods ended September 30, 2009 and 2008, and the relative
contributions by its subsidiaries.

                                                Three Months Ended       Nine Months Ended
                                                  September 30,            September 30,

In millions                                     2009         2008         2009         2008

Earnings (Loss) from Continuing Operations:
          SCE                                 $     346    $     235   $     1,053    $  542
          EMG                                        61          208          (445 )     479
          Edison International (parent) and
          other                                      (3 )        (10 )          34       (22 )

Edison International Earnings from
. . .