BUSINESS OF EDISON INTERNATIONAL

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 SCE, a California public utility corporation, and of nonutility companies. SCE comprises the largest portion of the assets and revenue of Edison International. The principal nonutility companies are: EME, which is an independent power producer engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities and also conducts price risk management and energy trading activities in power markets open to competition; MEHC, which holds the common stock of EME; and Edison Capital, which has investments in energy and infrastructure projects worldwide and in affordable housing projects located throughout the United States. Beginning in 2006, MEHC and Edison Capital are presented on a consolidated basis as EMG in order to reflect the integration of management and personnel at MEHC and Edison Capital.

Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. At December 31, 2006, Edison International and its subsidiaries had an aggregate of 16,139 full-time employees, of which 26 were employed directly by Edison International.

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’s internet website address is http://www.edisoninvestor.com. Edison International makes available, free of charge on its internet website, 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 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 http://www.sec.gov. The information contained in our website, or connected to that site, is not incorporated by reference into this report.

Edison International has three business segments for financial reporting purposes: an electric utility operation segment (SCE), a nonutility power generation segment (MEHC (parent) and EME), and a financial services provider segment (Edison Capital). Financial information about these segments and about geographic areas, for fiscal years 2006, 2005, and 2004, is contained in Note 17 of Notes to Consolidated Financial Statements and incorporated herein by this reference. Additional information about each of these business segments appears below under the headings “Business of Southern California Edison Company,” “Business of Edison Mission Group Inc.,” and “Business of Edison Capital.”

Regulation of Edison International

A comprehensive energy bill was passed by the United States House of Representatives and Senate in July 2005 and was signed by the President on August 8, 2005. Known as “EPAct 2005,” this comprehensive legislation includes provisions for the repeal of the PUHCA 1935 and amendments to the PURPA, for merger review reform, for the introduction of new regulations regarding “Transmission Operations Improvements,” for FERC authority to impose civil penalties for violation of its regulations, for transmission rate reform, for incentives for various generation technologies and for the extension through December 31, 2007 of production tax credits for wind and other specified types of generation. The FERC finalized rules to implement the Congressionally mandated repeal of PUHCA 1935, that became effective February 8, 2006, and enacted the PUHCA 2005. PUHCA 2005 is primarily a “books and records access” statute and does not give the FERC any new substantive authority under the Federal Power Act or Natural Gas Act. The FERC also issued final rules to implement the electric company merger and acquisition provisions of EPAct 2005.

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Edison International is not a public utility under the laws of the State of California and is not subject to regulation as such by the CPUC. See “Business of Southern California Edison Company—Regulation of SCE” below for a description of the regulation of SCE by the CPUC. The CPUC decision authorizing SCE to reorganize into a holding company structure, however, contains certain conditions, which, among other things: (1) ensure the CPUC access to books and records of Edison International and its affiliates which relate to transactions with SCE; (2) require Edison International and its subsidiaries to employ accounting and other procedures and controls to ensure full review by the CPUC and to protect against subsidization of nonutility activities by SCE’s customers; (3) require that all transfers of market, technological, or similar data from SCE to Edison International or its affiliates be made at market value; (4) preclude SCE from guaranteeing any obligations of Edison International without prior written consent from the CPUC; (5) provide for royalty payments to be paid by Edison International or its subsidiaries in connection with the transfer of product rights, patents, copyrights, or similar legal rights from SCE; and (6) prevent Edison International and its subsidiaries from providing certain facilities and equipment to SCE except through competitive bidding. In addition, the decision provides that SCE shall maintain a balanced capital structure in accordance with prior CPUC decisions, 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 determined to be necessary to meet SCE’s service obligations, shall be given first priority by the boards of directors of Edison International and SCE.

On October 27, 2005, the CPUC issued an Order Instituting Rulemaking to allow the CPUC to re-examine the relationships of the major California energy utilities with their parent holding companies and non-regulated affiliates. The OIR was issued in part in response to the repeal of the PUHCA 1935. On December 14, 2006 the CPUC issued a decision. Additional information about the Order Instituting Rulemaking appears in the MD&A under the heading “SCE: Regulatory Matters – Current Regulatory Developments – Holding Company Order Instituting Rulemaking.”

Environmental Matters Affecting Edison International

Because Edison International does not own or operate any assets, except 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 result in the imposition of numerous restrictions on the operation of existing facilities by Edison International’s subsidiaries, on the timing, cost, location, design, construction, and operation of new facilities by Edison International’s subsidiaries, and on the cost of mitigating the effect of past operations on the environment. These laws and regulations, relating to air and water pollution, waste management, hazardous chemical use, noise abatement, land use, aesthetics, nuclear control, and climate change substantially affect future planning and will continue to require modifications of existing facilities and operating procedures by Edison International’s subsidiaries. Edison International is unable to predict with certainty the extent to which additional regulations may affect its operations and capital expenditure requirements.

Edison International’s projected environmental capital expenditures and additional information about environmental matters affecting Edison International appear in the MD&A under the heading “Other Developments—Environmental Matters” and in Note 6 of Notes to Consolidated Financial Statements

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under “Environmental Remediation.” For details about the environmental liabilities and other business risks from environmental regulation of SCE and EME, see “Business of Southern California Edison Company—Environmental Matters Affecting SCE” and “Business of Edison Mission Group Inc.—Environmental Matters and Regulations Affecting EME.”

Financial Information About Geographic Areas

Financial information for geographic areas for Edison International can be found in Notes 17 and 18 of Notes to Consolidated Financial Statements. Edison International’s consolidated financial statements for all years presented reflect the reclassification of the results of MEHC’s international power generation portfolio that was sold or held for sale as discontinued operations in accordance with an accounting standard related to the impairment and disposal of long-lived assets.

BUSINESS OF SOUTHERN CALIFORNIA EDISON COMPANY

SCE was incorporated in 1909 under the laws of the State of California. SCE is a public utility primarily engaged in the business of supplying electric energy to a 50,000-square-mile area of central, coastal and southern California, excluding the City of Los Angeles and certain other cities. This SCE service territory includes approximately 430 cities and communities and a population of more than 13 million people. In 2006, SCE’s total operating revenue was derived as follows: 41% commercial customers, 37% residential customers, 4% resale sales, 7% industrial customers, 5% other electric revenue, 5% public authorities, and 1% agricultural and other customers. At December 31, 2006, SCE had consolidated assets of $26.1 billion and total shareholder’s equity of $6.4 billion. SCE had 14,362 full-time employees at year-end 2006.

Regulation of SCE

SCE’s retail operations are subject to regulation by the CPUC. The CPUC has the authority to regulate, among other things, retail rates, issuance of securities, and accounting practices. SCE’s wholesale operations are subject to regulation by the FERC. The FERC has the authority to regulate wholesale rates as well as other matters, including retail transmission service pricing, accounting practices, and licensing of hydroelectric projects.

Additional information about the regulation of SCE by the CPUC and the FERC, and about SCE’s competitive environment, appears in the MD&A under the heading “SCE: Regulatory Matters” and in this section under the sub heading “—Competition of SCE.”

SCE is subject to the jurisdiction of the United States NRC with respect to its nuclear power plants. United States NRC regulations govern the granting of licenses for the construction and operation of nuclear power plants and subject those power plants to continuing review and regulation.

The construction, planning, and siting of SCE’s power plants within California are subject to the jurisdiction of the California Energy Commission (for plants 50 mw or greater) and the CPUC. SCE is subject to the rules and regulations of the California Air Resources Board, State of Nevada, and local air pollution control districts with respect to the emission of pollutants into the atmosphere; the regulatory requirements of the California State Water Resources Control Board and regional boards with respect to the discharge of pollutants into waters of the state; and the requirements of the California Department of Toxic Substances Control with respect to handling and disposal of hazardous materials and wastes. SCE is also subject to regulation by the US EPA, which administers certain federal statutes relating to environmental matters. Other federal, state, and local laws and regulations relating to environmental protection, land use, and water rights also affect SCE.

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The construction, planning and siting of SCE’s transmission lines and substation facilities require the approval of many governmental agencies and compliance with various laws, depending upon the attributes of each particular project. These agencies include utility regulatory commissions such as the CPUC and other state regulatory agencies depending on the project location; the California location and other environmental, land management and resource agencies such as the Bureau of Land Management, the U.S. Fish and Wildlife Service, the U.S. Forest Service, and the California Department of Fish and Game; Regional Water Quality Control Boards; and the States’ Offices of Historic Preservation. 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 will also be necessary for the project to proceed. The agencies’ approval processes, implemented through their respective regulations and other statutes that impose requirements on the approvals of such projects, may adversely affect and delay the schedule for these projects.

The California Coastal Commission issued a coastal permit for the construction of the San Onofre Units 2 and 3 in 1974. This permit, as amended, requires mitigation for impacts to fish and the San Onofre kelp bed. California Coastal Commission jurisdiction will continue for several years due to ongoing implementation and oversight of these permit mitigation conditions, consisting of restoration of wetlands and construction of an artificial reef for kelp. SCE has a coastal permit from the California Coastal Commission to construct a temporary dry cask spent fuel storage installation for San Onofre Units 2 and 3. The California Coastal Commission also has continuing jurisdiction over coastal permits issued for the decommissioning of San Onofre Unit 1, including for the construction of a temporary dry cask spent fuel storage installation for spent fuel from that unit.

The United States Department of Energy has regulatory authority over certain aspects of SCE’s operations and business relating to energy conservation, power plant fuel use and disposal, electric sales for export, public utility regulatory policy, and natural gas pricing.

SCE is subject to CPUC affiliate transaction rules and compliance plans governing the relationship between SCE and its affiliates. See “Business of Edison International—Regulation of Edison International” above for further discussion of these rules.

Competition of SCE

Because SCE is an electric utility company operating within a defined service territory pursuant to authority from the CPUC, SCE faces 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. California law currently provides only limited opportunities for customers to choose to purchase power directly from an energy service provider other than SCE. SCE also faces some competition from cities 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 size of SCE’s customer base, thereby creating upward pressure on SCE’s rate structure to cover fixed costs, which in turn may cause more customers to leave SCE in order to obtain lower rates.

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Properties of SCE

SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, which deliver power from generating sources to the distribution network, consist of approximately 7,200 circuit miles of 33 kilovolt (kV), 55 kV, 66 kV, 115 kV, and 161 kV lines and 3,475 circuit miles of 220 kV lines (all located in California), 1,238 circuit miles of 500 kV lines (1,040 miles in California, 86 miles in Nevada, and 112 miles in Arizona), and 858 substations. SCE’s distribution system, which takes power from substations to the customer, includes approximately 60,000 circuit miles of overhead lines, 39,000 circuit miles of underground lines, 1.5 million poles, 588 distribution substations, 704,000 transformers, and 790,000 area and streetlights, all of which are located in California.

SCE owns and operates the following generating facilities: (1) an undivided 78.21% interest (1,690 MW) in San Onofre Units 2 and 3, which are large pressurized water nuclear units located on the California coastline between Los Angeles and San Diego; (2) 36 hydroelectric plants (1,178.9 MW) located in California’s Sierra Nevada, San Bernardino and San Gabriel mountain ranges, three of which (2.7 MW) are no longer operational and will be decommissioned; and (3) a diesel-fueled generating plant (9 MW) located on Santa Catalina island off the southern California coast.

SCE also owns an undivided 56% interest (884.8 MW net) in Mohave, which consists of two coal-fueled generating units located in Clark County, Nevada near the California border. The plant ceased operating on December 31, 2005. On June 19, 2006, SCE announced that it had decided not to move forward with its efforts to return Mohave to service. Additional information regarding Mohave appears in the MD&A under the heading “SCE: Regulatory Matters—Mohave Generating Station and Related Proceedings.”

In addition, SCE acquired in 2004 Mountainview, which consisted of a natural gas-fueled two unit power plant in the early stages of construction in Redlands, California. The first unit commenced commercial operations in December 2005, and the second unit commenced commercial operations in January 2006. Mountainview has a generating capacity of 1,050 MW.

SCE also owns an undivided 15.8% interest (601 MW) in Palo Verde, which is located near Phoenix, Arizona, and an undivided 48% interest (720 MW) in Units 4 and 5 at Four Corners, which is a coal-fueled generating plant located near the City of Farmington, New Mexico. Palo Verde and Four Corners are operated by Arizona Public Service Company.

At year-end 2006, the SCE-owned generating capacity (summer effective rating) was divided approximately as follows: 43% nuclear, 23% hydroelectric, 20% natural gas, 14% coal, and less than 1% diesel. The capacity factors in 2006 for SCE’s nuclear and coal-fired generating units were: 72% for San Onofre; 87% for Four Corners; and 71% for Palo Verde. For SCE’s hydroelectric plants, generating capacity is dependent on the amount of available water. SCE’s hydroelectric plants operated at a 50% capacity factor in 2006. These plants were operationally available for 91% of the year.

San Onofre, Four Corners, certain of SCE’s substations, and portions of its transmission, distribution and communication systems are located on lands of the United States or others under (with minor exceptions) licenses, permits, easements or leases, or on public streets or highways pursuant to franchises. Certain of such documents obligate SCE, under specified circumstances and at its expense, to relocate transmission, distribution, and communication facilities located on lands owned or controlled by federal, state, or local governments.

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Thirty-one of SCE’s 36 hydroelectric plants (some with related reservoirs) are located in whole or in part on United States lands pursuant to 30- to 50-year FERC licenses that expire at various times between 2007 and 2039 (the remaining five plants are located entirely on private property and are not subject to FERC jurisdiction). 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 purposes greater consideration in the licensing process. SCE’s has filed applications for the relicensing of certain hydroelectric projects with an aggregate capacity of approximately 915 MW. Annual licenses have been issued to SCE hydroelectric projects that are undergoing relicensing and whose long-term licenses have expired. Federal Power Act Section 15 requires that the annual licenses be renewed until the long-term licenses are issued or denied.

Substantially all of SCE’s properties are subject to the lien of a trust indenture securing first and refunding mortgage bonds, of which approximately $4.5 billion in principal amount was outstanding on February 28, 2007. Such lien and SCE’s title to its properties are subject to the terms of franchises, licenses, easements, leases, permits, contracts, and other instruments under which properties are held or operated, certain statutes and governmental regulations, liens for taxes and assessments, and liens of the trustees under the trust indenture. In addition, such lien and SCE’s title to its properties are subject to certain other liens, prior rights and other encumbrances, none of which, with minor or insubstantial exceptions, affect SCE’s right to use such properties in its business, unless the matters with respect to SCE’s interest in Four Corners and the related easement and lease referred to below may be so considered.

SCE’s rights in Four Corners, which is located on land of the Navajo Nation of Indians under an easement from the United States and a lease from the Navajo Nation, may be subject to possible defects. These defects include possible conflicting grants or encumbrances not ascertainable because of the absence of, or inadequacies in, the applicable recording law and the 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.

Nuclear Power Matters of SCE

Information about operating issues related to San Onofre appears in the MD&A under the heading “SCE: Regulatory Matters—Current Regulatory Developments—San Onofre Nuclear Generating Station Steam Generators and Changes in Ownership.” Information about Palo Verde appears in the MD&A under the headings “SCE: Regulatory Matters—Current Regulatory Developments—Palo Verde Generating Station Steam Generators” and “SCE: Other Developments—Palo Verde Nuclear Generating Station Outage and Inspection”. Information about nuclear decommissioning can be found in Notes 1 and 6 of Notes to Consolidated Financial Statements. Information about nuclear insurance can be found in Note 6 of Notes to Consolidated Financial Statements.

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SCE Purchased Power and Fuel Supply

SCE obtains the power needed to serve its customers from its generating facilities and from purchases from qualifying facilities, independent power producers, renewable power producers, the California ISO, and other utilities. In addition, power is provided to SCE’s customers through purchases by the CDWR under contracts with third parties. Sources of power to serve SCE’s customers during 2006 were as follows: 44.6% purchased power; 25.6% CDWR; and 29.8% SCE-owned generation consisting of 16.9% nuclear, 6.8% coal, and 6.1% hydro.

Natural Gas Supply

SCE’s natural gas requirements in 2006 were to meet contractual obligations for power tolling agreements (power contracts in which SCE has agreed to provide the natural gas needed for generation under those power contracts) and to serve demand for gas at Mountainview, which commenced operations in December 2005. All of the physical gas purchased by SCE in 2006 was purchased under North American Energy Standards Board agreements (master gas agreements) that define the terms and conditions of transactions with a particular supplier prior to any financial commitment.

SCE contracted for firm access rights onto the Southern California Gas Company system at Wheeler Ridge for 198,863 million British thermal units per day in a 13-year contract entered into in August 1993, effective November 1, 1993. SCE had the unilateral right to renew this contract for an equivalent term upon the expiration of its initial term on October 31, 2006. SCE has elected to not exercise its unilateral right to renew this contract.

In 2005, SCE secured a one-year natural gas storage capacity contract with Southern California Gas Company for the 2005/2006 storage season. Storage capacity was secured to provide operation flexibility and to mitigate potential costs associated with the dispatch of SCE’s tolling agreements. SCE has negotiated another one-year natural gas capacity contract with Southern California Gas Company for the 2006/2007 storage season.

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

Spent Nuclear Fuel

Information about Spent Nuclear Fuel appears in Note 6 of Notes to Consolidated Financial Statements.

Coal Supply

SCE has purchased coal pursuant to long-term contracts to provide stable and reliable fuel supplies to its two coal-fired generating stations, Four Corners and Mohave. However, Mohave ceased operating on December 31, 2005 and on June 19, 2006, SCE announced that it had decided not to move forward with its efforts to return Mohave to service. Additional information regarding Mohave appears in the MD&A under the heading “SCE: Regulatory Matters—Mohave Generating Station and Related Proceedings.” SCE entered into a coal contract, dated September 1, 1966, with the Utah Construction & Mining Company, the predecessor to the current owner of the Navajo mine, the BHP Navajo Coal Company, to supply coal to Four Corners Units 4 and 5. The initial term of this coal supply contract for Four Corners was through 2004 and included extension options for up to 15 additional years. On January 1, 2005 SCE and the other Four Corners participants entered into a Restated and Amended Four Corners Fuel Agreement under which coal will be supplied until July 6, 2016. The Restated and Amended Agreement contains an option to extend for not less than five additional years or more than 15 years.

Seasonality of SCE

Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is generally significantly higher than other quarters.

Environmental Matters Affecting SCE

SCE is subject to environmental regulation by federal, state and local authorities in the jurisdictions in which it operates in the United States. This regulation, including in the areas of air and water pollution, waste management, hazardous chemical use, noise abatement, land use, aesthetics, nuclear control and climate change, continues to result in the imposition of numerous restrictions on SCE’s operation of existing facilities, on the timing, cost, location, design, construction, and operation by SCE of new facilities, and on the cost of mitigating the effect of past operations on the environment.

SCE believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operations. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies could affect the costs and the manner in which SCE conducts its business and could cause it to make substantial additional capital or operational expenditures. There is no assurance that SCE would be able to recover these increased costs from its

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customers or that SCE’s financial position and results of operations would not be materially adversely affected. SCE is unable to predict the extent to which additional regulations may affect its operations and capital expenditure requirements.

Typically, environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital or operational expenditures. Furthermore, if SCE fails to comply with applicable environmental laws, it may be subject to injunctive relief, penalties and fines imposed by regulatory authorities.

The laws and regulations discussed below primarily impact SCE’s coal-fired, gas-fired and nuclear generation facilities. The air quality and climate change laws and regulations primarily impact SCE’s coal-fired facilities, Mohave and Four Corners. The discussions below focus on the Four Corners plant in light of the fact that Mohave has suspended operation and SCE is no longer pursuing efforts to return it to service. Developments in the air quality and climate change areas may also have an impact on SCE’s gas-fired plants, but this impact is less likely to be substantial because SCE’s gas-fired plants were recently constructed or are now under development with current generating and pollution control technology and because of the lower emissions, including lower CO ₂ emissions, from natural gas as compared to coal. SCE’s gas-fired generation facilities include Mountainview and five gas-fired peaker units currently under development. The water quality discussion primarily impacts San Onofre.

Air Quality Regulation

Various air quality regulations, including the Federal Clean Air Act and similar state and local statutes apply to SCE’s plants, and have their largest impact on the operation of the coal-fired plants, Mohave and Four Corners. These regulations are expected to have a lesser impact on SCE operations in the future in light of the decision by SCE not to move forward in its efforts to return Mohave to service.

Suspension of Mohave Operations and SCE Decision to Discontinue Its Participation in Efforts to Resume Operations

Information regarding the suspension of Mohave operations and SCE’s decision to discontinue its participation in efforts to resume such operations appears in the MD&A under the heading “Other Developments—Environmental Matters—Air Quality Standards—Suspension of Mohave Operations and SCE Decision to Discontinue Its Participation in Efforts to Resume Operations.” Additional information regarding Mohave appears in the MD&A under the heading “SCE: Regulatory Matters—Mohave Generating Station and Related Proceedings.”

Clean Air Act Interstate Rule

At this time, the US EPA’s CAIR, does not have an impact on SCE’s facilities. CAIR, issued by the US EPA on March 10, 2005,

applies to 28 eastern states and the District of Columbia, and is intended to address ozone attainment issues by reducing regional SO ₂ and NOx emissions. The CAIR has been challenged in court by state, environmental, and industry groups, which may result in changes to the substance of the rule and to the timetables for implementation. While the US EPA has not adopted a rule comparable to CAIR for the western United States, where SCE has facilities, SCE cannot predict what action the US EPA will take in the future with regard to the western United States, and what impact those actions would have on its facilities.

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Mercury Regulation

The US EPA’s CAMR was issued on March 15, 2005 and published in the Federal Register on May 18, 2005. CAMR creates a national framework for a market-based cap-and-trade program to reduce mercury emissions from existing coal-fired power plants down to a national cap of 38 tons by 2010 and to 15 tons by 2018. Emissions of mercury are to be reduced primarily by taking advantage of mercury reductions achieved by reducing SO ₂ and NO _x emissions under the CAIR. States may join the trading program by adopting the CAMR model trading rules in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR’s suggested cap-and-trade program. Any program adopted by a state must be approved by the US EPA.

Contemporaneous with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired power plants had to be regulated as a hazardous air pollutant pursuant to Section 112 of the federal Clean Air Act, which would have imposed technology-based standards. Both the US EPA’s recession action and the CAMR are being challenged in the courts. Depending on the results of these challenges, the CAMR rules and timetables may change. SCE is working with Arizona Public Service Company, the operator of Four Corners, to assess the potential impact of the CAMR on Four Corners and cannot currently estimate the expenditures that may be required.

Regional Haze

The goal of the 1999 regional haze regulations is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions in 60 years. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install BART or implement other control strategies to meet regional haze control requirements. The US EPA issued a final rulemaking on regional haze on June 15, 2005. Under the rule, by December 2007, each state must file with the US EPA, as part of its SIP, plans for regional haze improvement. The US EPA has

proposed alternate rules for the area where Four Corners is located. SCE is working with Arizona Public Service Company, the operator of Four Corners, to evaluate the impact of these rules on Four Corners and cannot currently predict such impact.

Climate Change

To date, the US has chosen to pursue a voluntary GHG emissions reduction program to meet its obligations as a signatory to the UN Framework Convention on Climate Change. Currently a number of bills are proposed or under discussion in Congress to mandate reductions of GHG emissions. At this point, SCE is unable to determine whether any of these proposals will be enacted into law or to estimate their potential effect on SCE.

There have been petitions from states and other parties to compel the US EPA to regulate GHG under CAIR. In Massachusetts v. U.S. EPA , the United States Supreme Court currently is considering whether, under existing law, including the Clean Air Act, the US EPA is authorized or compelled to regulate greenhouse gas emissions. Oral arguments were heard in November 2006, and a decision is pending. In addition, other global climate-related lawsuits have been filed around the nation against various private parties, include utilities, oil and chemical companies, and automobile manufacturers, under various theories including public nuisance for damages caused by the alleged contribution to global warming resulting from CO ₂ emissions from coal-fired power plants owned and operated by these companies or their subsidiaries by the alleged contribution of those parties to global warming.

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Information regarding current developments on climate change and GHG regulation appears in the MD&A under the heading “Other Developments—Environmental Matters—Climate Change.”

Hazardous Substances and Hazardous Waste Laws

Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury, natural resource damages, and investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, and the Resource Conservation and Recovery Act, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several.

In addition, the federal Toxic Substances Control Act and accompanying regulations govern the manufacturing, processing, distribution in commerce, use, and disposal of listed compounds, including polychlorinated biphenyls, a toxic substance. Federal, state, and local laws, regulations and ordinances also govern the removal, encapsulation or disturbance of asbestos-containing materials when these materials are in poor condition or in the event of construction, remodeling, renovation or demolition of a building and other structures containing asbestos.

In connection with the ownership and operation of its facilities, SCE may be liable for costs associated with hazardous waste compliance and remediation required by the laws and regulations identified herein. The CPUC allows SCE to recover in retail rates paid by its customers partial environmental remediation costs at certain sites through an incentive mechanism. Additional information about these laws and regulations appears in Note 6 of Notes to Consolidated Financial Statements.

Water Quality Regulation

Regulations under the federal Clean Water Act require permits for the discharge of pollutants into United States waters and permits for the discharge of storm water flows from certain facilities. The Clean Water Act also regulates the thermal component (heat) of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities. 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. SCE incurs additional expenses and capital expenditures in order to comply with guidelines and standards applicable to certain of its facilities.

Cooling Water Intake Structures

Information regarding the cooling water intake structure standards appears in the MD&A under the heading “Other Developments—Environmental Matters—Water Quality Regulation—Clean Water Act—Cooling Water Intake Structures.”

The U.S. Court of Appeals for the Second Circuit recently struck down major provisions of the US EPA Phase II regulations in Riverkeeper, Inc. v. EPA , and remanded the regulations to US EPA for further consideration and action. While SCE believed that this rule, as originally drafted, would not have a

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material impact on SCE’s operations at San Onofre, until the US EPA adopts final rules consistent with the court’s decision, SCE cannot determine the full financial impact of this rule.

Electric and Magnetic Fields

Electric and magnetic fields naturally result from the generation, transmission, distribution and use of electricity. Since the 1970s, concerns have been raised about the potential health effects of EMF. After 30 years of research, a health hazard has not been established to exist. Potentially important public health questions remain about whether there is a link between EMF exposures in homes or work and some diseases, and because of these questions, some health authorities have identified EMF exposures as a possible human carcinogen.

In January 2006, the CPUC issued its decision updating its policies and procedures related to EMF emanating from regulated utility facilities. The decision concluded that a direct link between exposure to EMF and human health effects has yet to be proven, and affirmed the CPUC’s existing “low-cost/no-cost” EMF policies to mitigate EMF exposure for new utility transmission and substation projects.

BUSINESS OF EDISON MISSION GROUP INC.

EMG is a wholly owned subsidiary of Edison International. EMG is the holding company for its principal wholly owned subsidiaries, MEHC and Edison Capital.

Business of Mission Energy Holding Company

MEHC was formed to hold the common stock of EME. On July 2, 2001, EMG contributed to MEHC all the outstanding common stock of EME. The contribution of EME’s common stock to MEHC has been accounted for as a transfer of ownership of companies under common control. MEHC’s only substantive liabilities are its obligations under the senior secured notes and corporate overhead, including fees of its legal counsel, auditors and other advisors. MEHC does not have any substantive operations other than through EME and its subsidiaries and other investments. Beginning in 2006, MEHC and Edison Capital are presented on a consolidated basis as EMG in order to reflect the integration of management and personnel at MEHC and Edison Capital.

Business of Edison Mission Energy

Since the second quarter of 2004, MEHC (parent) and EME are presented as one business segment on a consolidated basis due primarily to the elimination of EME’s so-called “ring fencing” provisions in EME’s certificate of incorporation and bylaws discussed in the MD&A under the heading “EMG: Liquidity—MEHC (parent)’s Liquidity.”

EME is an independent power producer engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also conducts price risk management and energy trading activities in power markets open to competition. EME is a wholly owned subsidiary of MEHC. Edison International is EME’s ultimate parent company.

EME was formed in 1986 with two domestic operating power plants. As of December 31, 2006, EME’s continuing operations consisted of owned or leased interests in 29 domestic operating power plants with an aggregate net physical capacity of 10,473 MW, of which EME’s capacity pro rata share was 9,303 MW.

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Competition and Market Conditions of EME

The United States electric industry, including companies engaged in providing generation, transmission, distribution and ancillary services, has undergone significant deregulation, which has led to increased competition. Until the enactment of PURPA, utilities and government-owned power agencies were the only producers of bulk electric power intended for sale to third parties in the United States. PURPA encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from specified types of non-utility power producers, known as qualifying facilities, under specified conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options available to independent power producers with respect to their regulatory status and by liberalizing transmission access. In addition, in EPAct 2005, Congress made several changes to PURPA and other statutory provisions recognizing that a significant market for electric power produced by independent power producers, such as EME, has developed in the United States, and indicating that competitive wholesale electricity markets have become accepted as a fundamental aspect of the electricity industry.

As part of the regulatory developments discussed above, the FERC encouraged the formation of ISOs and RTOs. In those areas where ISOs and RTOs have been formed, market participants have expanded access to transmission service. 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. See further discussion of regulations under “—Regulation of EME—United States Federal Energy Regulation.”

EME’s largest power plants are its fossil fuel power plants located in Illinois, which are collectively referred to as the Illinois plants in this report, and the Homer City electric generating station located in Pennsylvania, which is referred to as the Homer City facilities in this report. The Illinois plants and the Homer City facilities sell power into PJM. PJM operates a wholesale spot energy market and determines the market-clearing price for each hour based on bids submitted by participating generators which indicate the minimum prices a bidder is willing to accept to be dispatched at various incremental generation levels. PJM conducts both day-ahead and real-time energy markets. PJM’s energy markets are based on locational marginal pricing, which establishes hourly prices at specific locations throughout PJM. Locational marginal pricing is determined by considering a number of factors, including generator bids, load requirements, transmission congestion and transmission losses. PJM requires all load serving entities to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM also determines the amount of capacity available from each specific generator and operates capacity markets. PJM’s capacity markets have a single market-clearing price. Load serving entities and generators, such as EME’s subsidiaries Midwest Generation, with respect to the Illinois plants and EME Homer City, with respect to the Homer City facilities may participate in PJM’s capacity markets or transact capacity sales on a bilateral basis.

The Homer City facilities have direct, high voltage interconnections to both PJM and the New York Independent System Operator, which controls the transmission grid and energy and capacity markets for New York State and is commonly referred to as the NYISO. As in PJM, the market-clearing price for the NYISO’s day-ahead and real-time energy markets is set by supplier generation bids and customer demand bids.

On April 1, 2005, the MISO commenced operation, linking portions of Illinois, Wisconsin, Indiana, Michigan, and Ohio, as well as other states in the region, in the MISO, where there is a bilateral market

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and day-ahead and real-time markets based on locational marginal pricing similar to that of PJM. While EME does not own generating facilities within MISO, its opening has further facilitated transparency of prices and provided additional market liquidity to support risk management and trading strategies.

For a discussion of the market risks related to the sale of electricity from these generating facilities, see “EMG: Market Risk Exposures” in the MD&A.

EME is subject to intense competition from energy marketers, utilities, industrial companies and other independent power producers. For a number of years until the recent upturn in its price, natural gas has been the fuel of choice for new power generation facilities for economic, operational and environmental reasons. While natural gas-fired facilities will continue to be an important part of the nation’s generation portfolio, some regulated utilities are now constructing clean coal units and units powered by renewable resources, often with subsidies or under legislative mandate. These utilities generally have a lower cost of capital than most independent power producers and often are 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.

Where EME sells power from plants from which the output is not committed to be sold under long-term contracts, commonly referred to as merchant plants, EME is subject to market fluctuations in prices based on a number of factors, including the amount of capacity available to meet demand, the price and availability of fuel and the presence of transmission constraints. Some of EME’s competitors, such as electric utilities and distribution companies have their own generation capacity, including nuclear generation. These companies, generally larger than EME, have a lower cost of capital and may have competitive advantages as a result of their scale and the location of their generation facilities.

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In addition to the facilities and power plants that EME owns, EME uses the term “its” in regard to facilities and power plants that EME or an EME subsidiary operates under sale-leaseback arrangements.

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Business Development of EME

Wind Projects

EME expects to make significant investments in wind projects during the next several years. Historically, wind projects have received federal subsidies in the form of production tax credits. In August 2005, production tax credits were made available for new wind projects placed in service by December 31, 2007 under EPAct 2005. In December 2006, the production tax credit was extended for one year to apply to new wind projects placed in service by December 31, 2008.

In seeking to find and invest in new wind projects, EME has teamed with third-party development companies through agreements that provide for funding of development costs through loans and joint decision-making on key contractual agreements (e.g., power purchase contracts, site agreements and permits). Joint development agreements and development loans may be for a specific project

or a group of identified and future projects and generally grant EME the exclusive right to acquire related projects. At December 31,

2006, joint development agreements were in place for multiple potential projects located in Pennsylvania, Illinois, Maine, Maryland, New York, West Virginia and Wisconsin.

In general, EME funds development costs under joint development agreements through loans (referred to as development loans) which are secured by project specific assets. A project’s development loans are repaid upon the completion of the project. If the project is purchased by EME, repayment is made from proceeds received from EME in connection with the purchase. In the event

EME declines to purchase a project, repayment is made from proceeds received from the sale of the project to third parties or from

other sources as available.

In addition to joint development agreements, EME may purchase wind projects from third-party developers in various stages of development, construction or operation. In order to support investment in wind projects, EME has negotiated turbine supply agreements in advance of specific project requirements. As of December 31, 2006, EME has purchased turbines for future wind projects totaling 487 MW.

See “Commitments, Guarantees and Indemnities—Other Commitments” in the MD&A for further discussion.

Thermal Projects

EME also expects to make investments in thermal projects during the next several years. As part of this development effort, EME has begun the process of obtaining permits for two sites in southern California for peaker plants. Generally, it is expected that the thermal projects in which EME invests will sell electricity under long-term power purchase contracts. EME actively participates in bids to utilities in response to requests for proposals to build new generation and may acquire existing generation in selected markets.

In June 2006, subsidiaries of EME and BP America Inc. formed Carson Hydrogen Power LLC for the development of a power project to be located in Carson, California. Carson Hydrogen is a development stage enterprise for a planned industrial gasification project that will integrate proven gasification, power generation and enhanced oil recovery technologies. On November 29, 2006, the project was allocated $90 million of qualifying gasification project credits under Section 48B of the Internal Revenue Code. Carson Hydrogen is conducting preliminary development, including engineering, financial analysis and commercial arrangements, required for project implementation.

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Discontinued Operations of EME

Information regarding EME’s discontinued operations appears in Note 18 of Notes to Consolidated Financial Statements.

Hedging and Trading Activities of EME

EME’s power marketing and trading subsidiary, EMMT, markets the energy and capacity of EME’s merchant generating fleet and, in addition, trades electric power and energy and related commodity and financial products, including forwards, futures, options and swaps. EMMT segregates its marketing and trading activities into two categories:

In conducting EME’s hedging and trading activities, EMMT contracts with a number of utilities, energy companies and financial institutions. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

To manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME would record if its counterparties failed to perform pursuant to the terms of their contractual obligations. EME has established controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever possible to mitigate its exposure to counterparty risk. EME requires counterparties to pledge collateral when deemed necessary. EME uses published credit ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. The credit quality of EME’s counterparties is reviewed regularly by EME’s risk management committee. In addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower credit exposure. Despite this, there can be no assurance that EME’s actions to mitigate risk will be wholly successful or that collateral pledged will be adequate.

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EME’s merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored by EME’s risk management committee to ensure compliance with EME’s risk management policies. Policies are in place which define risk tolerances, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by the risk management committee. EME uses “value at risk” to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois plants, its Homer City facilities and its proprietary positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify risk factors. Value at risk measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and reliance on a single risk measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

In executing agreements with counterparties to conduct hedging or trading activities, EME generally provides credit support when necessary through margining arrangements (agreements to provide or receive collateral, letters of credit or guarantees based on changes in the market price of the underlying contract under specific terms). To manage its liquidity, EME assesses the potential impact of future price changes in determining the amount of collateral requirements under existing or anticipated forward contracts. There is no assurance that EME’s liquidity will be adequate to meet margin calls from counterparties in the case of extreme market changes or that the failure to meet such cash requirements would not have a material adverse effect on its liquidity. See “Item 1A. Risk Factors—Risks Relating to MEHC.”

Significant Customers

In the past three fiscal years, EME derived a significant source of its operating revenues from electric power sold into the PJM market from the Homer City facilities and the Illinois plants in the past three fiscal years. Sales into the PJM pool accounted for approximately 58%, 69% and 23% of EME’s consolidated operating revenues for the years ended December 31, 2006, 2005 and 2004, respectively. For the year ended December 31, 2004, approximately 15% of EME’s consolidated operating revenues generated at the Homer City facilities and Illinois plants were from sales to BP Energy Company, a third-party customer. In 2004, EME also derived a significant source of its revenues from the sale of energy and capacity generated at the Illinois plants to Exelon Generation Company LLC primarily under three power purchase agreements. These power purchase agreements had all expired by the end of 2004. Exelon Generation Company LLC accounted for approximately 35% of EME’s consolidated operating revenues for the year ended December 31, 2004.

Insurance of EME

EME maintains insurance policies consistent with those normally carried by companies engaged in similar businesses and owning similar properties. EME’s insurance program includes all-risk property insurance, including business interruption, covering real and personal property, including losses from boilers, machinery breakdowns, and the perils of earthquake and flood, subject to specific sub limits. EME also carries general liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations, automobile liability insurance and excess liability insurance. Limits and deductibles in respect of these insurance policies are comparable to those carried by other electric generating facilities of similar size. However, no assurance can be given that EME’s insurance will be adequate to cover all losses.

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The Homer City facilities property insurance program currently covers losses up to $1 billion. Under the terms of the participation agreements entered into on December 7, 2001 as part of the sale-leaseback transaction of the Homer City facilities, EME Homer City is required to maintain specified minimum insurance coverages if and to the extent that such insurance is available on a commercially reasonable basis. Although the insurance covering the Homer City facilities is comparable to insurance coverages normally carried by companies engaged in similar businesses, and owning similar properties, the insurance coverages that are in place do not meet the minimum insurance coverages required under the participation agreements. Due to the current market environment, the minimum insurance coverage is not commercially available at reasonable prices. EME Homer City has obtained a waiver under the participation agreements which permit it to maintain its current insurance coverage through June 1, 2007.

Seasonality of EME

Due to higher electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the Illinois plants and the Homer City facilities 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, earnings from the Illinois plants and the Homer City facilities are seasonal and have significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. See “EMG: Market Risk Exposures—MEHC’s Commodity Price Risk—Energy Price Risk Affecting Sales from the Illinois Plants” and “—Energy Price Risk Affecting Sales from the Homer City Facilities” in the MD&A for further discussion regarding market prices.

EME’s third quarter equity in income from its energy projects is materially higher than equity in income related to other quarters of the year due to warmer weather during the summer months and because a number of EME’s energy projects located on the West Coast have power sales contracts that provide for higher payments during the summer months.

Discontinued Operations of EME

Information regarding EME’s discontinued operations appears in Note 18 of the Notes to the Financial Statements.

Regulation of EME

General

EME’s operations are subject to extensive regulation by governmental agencies. EME’s operating projects are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the ownership and operation of its projects, and the use of electric energy, capacity and related products, including ancillary services from its projects. Federal laws and regulations govern, among other things, transactions by and with purchasers of power, including utility companies, the operation of a power plant and the ownership of a power plant. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Energy-producing projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning, land use and operation of a project. Federal, state and local environmental requirements generally require that a wide variety of permits and other approvals be obtained before the

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commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with these permits and approvals.

EME is subject to a varied and complex body of laws and regulations that are in a state of flux. Intricate and changing environmental and other regulatory requirements could necessitate substantial expenditures and could create a significant risk of expensive delays or significant loss of value in a project if it were to become unable to function as planned due to changing requirements or local opposition.

United States Federal Energy Regulation

The FERC has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy (other than transmission that is “bundled” with retail sales) under the Federal Power Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. Prior to February 8, 2006, the SEC had regulatory powers with respect to upstream owners of electric and natural gas utilities under PUHCA 1935, which was repealed as of that date by EPAct 2005. The enactment of PURPA and the adoption of regulations under that Act by the FERC provided incentives for the development of cogeneration facilities and small power production facilities using alternative or renewable fuels by establishing certain exemptions from the Federal Power Act and PUHCA 1935 for the owners of qualifying facilities. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing additional exemptions from PUHCA 1935 for EWGs and foreign utility companies. See “Business of Edison International—Regulation of Edison International” above.

The Energy Policy Act of 2005

Information on the EPAct 2005 appears under the heading “Business of Edison International—Regulation of Edision International.”

Federal Power Act

The Federal Power Act grants the FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission services in interstate commerce (other than transmission

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that is “bundled” with retail sales), including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the FERC to revoke or modify previously approved rates after notice and opportunity for hearing. These 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. Most qualifying facilities, as that term is defined in PURPA, are exempt from the ratemaking and several other provisions of the Federal Power Act. EWGs certified in accordance with the FERC’s rules under PUHCA 2005 and other non-qualifying facility independent power projects are subject to the Federal Power Act and to the FERC’s ratemaking jurisdiction thereunder, but the FERC typically grants EWGs the authority to charge market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. In addition, the Federal Power Act grants the FERC jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale power sales contracts and, after EPAct 2005, generation facilities, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the FERC typically also grants blanket approval for certain obligations, such as those related to the issuance of securities.

As of December 31, 2006, a number of EME’s operating projects, including the Homer City facilities and the Illinois plants, were subject to the FERC ratemaking regulation under the Federal Power Act. EME’s future domestic non-qualifying facility independent power projects will also be subject to the FERC jurisdiction on rates.

PJM Reliability Pricing Model

On August 31, 2005, PJM filed under sections 205 and 206 of the Federal Power Act a proposal for a RPM to replace its existing construct. PJM’s proposal offered RPM as a way to address deficiencies in PJM’s current structure in a comprehensive and integrated manner. On April 20, 2006, the FERC issued an Initial Order on RPM, finding PJM’s existing capacity construct to be unjust and unreasonable as a long-term capacity solution, because it fails to set prices adequate to ensure energy resources to meet PJM’s reliability responsibilities. Although the FERC did not find the RPM proposal, as filed by PJM, to be a just and reasonable replacement for the current capacity construct, because some elements of the proposal need further development and elaboration, it did find that certain elements of the RPM proposal, with some adjustment and clarification, could form the basis for a just and reasonable capacity market. Accordingly, in the order the FERC provided guidance on PJM’s RPM proposal, noted other features that need to be included in a just and reasonable capacity market, and established further proceedings to resolve these issues. On September 29, 2006, a comprehensive settlement agreement among PJM and many of its stakeholders, including EME, embodying a proposed capacity market construct for PJM, was submitted to FERC for approval. On December 22, 2006, the FERC issued an order conditionally approving the RPM settlement. EME continues to review and evaluate the FERC order, but believes at this time that the implementation of the settlement will benefit the Illinois plants and the Homer City facilities.

FERC Order Regarding PJM Marginal Losses

On May 1, 2006, the FERC issued an order in response to a complaint filed by Pepco Holdings, Inc. against PJM regarding marginal losses for transmission. The FERC concluded that PJM had violated its tariff by not implementing marginal losses and further directed PJM to implement marginal losses by October 2, 2006. On June 19, 2006, the FERC issued an order delaying implementation of marginal losses in PJM until June 1, 2007. On August 3, 2006, PJM filed its Tariff and Operating Agreement changes to implement marginal losses. On November 6, 2006, the FERC issued an order accepting those Tariff and Operating Agreement changes.

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Implementation of marginal losses will adjust the algorithm that calculated locational marginal prices to include a component for marginal transmission losses in addition to the already included component for congestion. This may reduce market prices for sellers in the Western PJM and Northern Illinois regions, including the Homer City facilities and the Illinois plants.

Public Utility Regulatory Policies Act of 1978

PURPA provides two primary benefits to qualifying facilities. First, all cogeneration facilities that are qualifying facilities are exempt from certain provisions of the Federal Power Act and regulations of the FERC thereunder. Second, the FERC regulations promulgated under PURPA require that electric utilities purchase electricity generated by qualifying facilities at a price based on the purchasing utility’s avoided cost, (unless, pursuant to EPAct 2005, the FERC determines that the relevant market meets certain conditions for competitive, nondiscriminatory access), and that the utilities sell back-up power to the qualifying facility on a nondiscriminatory basis. The FERC’s regulations also permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility’s avoided costs. While it had been common for utilities to enter into long-term contracts with qualifying facilities in order to, among other things, facilitate project financing of independent power facilities and to reflect the deferral by the utility of capital costs for new plant additions, increasing competition and the development of new power markets have resulted in a trend toward shorter term power contracts that would place greater risk on the project owner.

If one of the projects in which EME has an interest were to lose its status as a qualifying cogeneration facility, the project would no longer be entitled to the qualifying facility-related exemptions from regulation. As a result, the project could become subject to rate regulation by the FERC under the Federal Power Act and additional state regulation. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility status in the project’s power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. If a power purchaser were to cease taking and paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of qualifying facility status, EME cannot provide assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, EME’s business and financial condition could be adversely affected if regulations or legislation were modified or enacted that changed the standards applicable to EME’s facilities for maintaining qualifying facility status or that eliminated or reduced the benefits and exemptions currently enjoyed by EME’s qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to, among other things, fines and penalties, or claims by a utility customer for the refund of payments previously made.

EPAct 2005 made several important amendments to PURPA, including the elimination of qualifying facility ownership restrictions, elimination of the requirement that electric utilities enter into new contracts to purchase electricity from qualifying facilities that have access to wholesale power markets that meet specified criteria or sell energy to existing qualifying facilities in states where there is retail electricity competition and no obligation under state law to make power sales, the granting of new authority to the FERC to ensure recovery by electric utilities of all prudently incurred costs associated with purchases of energy and capacity from qualifying facilities, and certain obligations upon electric utilities for interconnection and metering for qualifying facilities. The FERC has initiated several proceedings to promulgate rules and regulations to implement the mandates of EPAct 2005 with respect to PURPA, and EME is continuing to evaluate the effect of the legislation and proposed regulations on its business activities.

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EME endeavors to monitor regulatory compliance by its qualifying facility projects in a manner that minimizes the risks of losing these projects’ qualifying facility status. However, some factors necessary to maintain qualifying facility status are subject to risks of events outside EME’s control. For example, loss of a thermal energy customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a qualifying facility could cause a facility to fail to meet the requirements regarding the minimum level of useful thermal energy output. Upon the occurrence of this type of event, EME would seek to replace the thermal energy customer or find another use for the thermal energy that meets the requirements of PURPA.

Natural Gas Act

Many of the operating facilities that EME owns, operates or has investments in use natural gas as their primary fuel. Under the Natural Gas Act, the FERC has jurisdiction over certain sales of natural gas and over transportation and storage of natural gas in interstate commerce. The FERC has granted blanket authority to all persons to make sales of natural gas without restriction but continues to exercise significant oversight with respect to transportation and storage of natural gas services in interstate commerce.

Transmission of Wholesale Power

Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others. This transmission service over the lines of intervening transmission owners is also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the FERC when the entity providing the transmission service is a jurisdictional public utility under the Federal Power Act.

The Energy Policy Act of 1992 laid the groundwork for a competitive wholesale market for electricity by, among other things, expanding the FERC’s authority to order electric utilities to transmit third-party electricity over their transmission lines, thus allowing qualifying facilities under PURPA, power marketers and those qualifying as EWGs under PUHCA 1935 to more effectively compete in the wholesale market.

In 1996, the FERC issued Order No. 888, also known as the Open Access Rules, which require utilities to offer eligible wholesale transmission customers open access on utility transmission lines on a comparable basis to the utilities’ own use of the lines and directed jurisdictional public utilities that control a substantial portion of the nation’s electric transmission networks to file uniform, non-discriminatory open access tariffs containing the terms and conditions under which they would provide such open access transmission service. The FERC subsequently issued Order Nos. 888-A, 888-B and 888-C to clarify the terms that jurisdictional transmitting utilities are required to include in their open access transmission tariffs and Order No. 889, which required those transmitting utilities to abide by specified standards of conduct when using their own transmission systems to make wholesale sales of power, and to post specified transmission information, including information about transmission requests and availability, on a publicly available computer bulletin board.

On February 15, 2007, the FERC issued Order No. 890 with the stated intent of promoting competition in wholesale power markets and strengthening the electric power grids. Order No. 890 is designed to strengthen the Open Access Rules embodied in Order No. 888, increase transparency in the rules applicable to planning and use of the transmission system, make undue discrimination in transmission easier to detect, and facilitate the FERC’s enforcement efforts in remedying such discrimination. Public utility transmission providers, including RTOs and ISOs, are required to make

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changes in their tariffs to comply with Order No. 890. Order No. 890 will take effect within 60 days of its publication in the Federal Register, which is expected to occur within 30 days of its issuance.

Environmental Matters and Regulations Affecting EME

The construction and operation of power plants are subject to environmental regulation by federal, state and local authorities. EME believes that it is in substantial compliance with existing environmental regulatory requirements. Typically, environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project, as well as require extensive modifications to existing projects, which may involve significant capital expenditures. If EME fails to comply with applicable environmental laws, it may be subject to injunctive relief or penalties and fines imposed by regulatory authorities.

Air Quality Regulation

Federal environmental regulations require reductions in emissions beginning in 2009 and require states to adopt implementation plans that are equal to or more stringent than the federal requirements. Compliance with these regulations and SIPs will affect the costs and the manner in which EME conducts its business, and will require EME to make substantial additional capital expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that EME’s financial position and results of operations would not be materially adversely affected as a result.

Clean Air Act

Information on the CAIR and its impact on EME appears in the MD&A under the heading “Other Developments—Environmental Matters—Air Quality Standards—Clean Air Act.”

Illinois

Information regarding Midwest Generation’s agreement with the Illinois EPA appears in MD&A under the heading “Other Developments—Environmental Matters—Air Quality Standards—Clean Air Act—Illinois.”

Pennsylvania

Information regarding Pennsylvania’s compliance with CAIR appears in MD&A under the heading “Other Developments—Environmental Matters—Air Quality Standards—Clean Air Act—Pennsylvania.”

Mercury Regulation

See “Business of Southern California Edison Company—Environmental Matters Affecting SCE—Mercury Regulation” for a general description of the CAMR.

Illinois

Information regarding Midwest Generation’s compliance with the State rule for reduction of mercury emissions in Illinois appears in the MD&A under the heading “Other Developments—Environmental Matters—Mercury Regulation—Illinois.”

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Pennsylvania

Information regarding the Homer City facilities’ compliance with the State rule for reduction of mercury emissions in Pennsylvania appears in the MD&A under the heading “Other Developments—Environmental Matters—Mercury Regulation—Pennsylvania.”

Ambient Air Quality Standards

The US EPA designated non-attainment areas for its 8-hour ozone standard on April 30, 2004, and for its fine particulate matter standard on January 5, 2005. Almost all of EME’s facilities are located in counties that have been identified as being in non-attainment with both standards. States are required to revise their SIPs for the ozone and particulate matter standards within three years of the effective date of the respective non-attainment designations. The revised SIPs are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates. Any additional obligations on EME’s facilities to further reduce their emissions of SO ₂ , NO _x and fine particulates to address local non-attainment with the 8-hour ozone and fine particulate matter standards will not be known until the states revise their SIPs. Depending upon the final standards that are adopted, EME may incur substantial costs or experience financial impacts resulting from required capital improvements or operational changes.

On September 22, 2006 the US EPA issued a final rule that implements the revisions to its fine particulate standard originally proposed on January 17, 2006. Under the new rule, the annual standard remains the same but the 24-hour fine particulate standard is significantly more stringent. The rule may require states to impose further emission reductions beyond those necessary to meet the existing standards. EME anticipates that any such further emissions reduction obligations would not be imposed under this standard until 2015 at the earliest, and intends to consider such rules as part of its overall plan for environmental compliance.

Illinois

Beginning with the 2003 ozone season (May 1 through September 30), EME has been required to comply with an average NO _X emission rate of 0.25 lb NO _X /mm British Thermal Units of heat input. This limitation is commonly referred to as the East St. Louis SIP. This regulation is a State of Illinois requirement. Each of the Illinois plants complied with this standard in 2004. Beginning with the 2004 ozone season, the Illinois Plants became subject to the federally mandated “NO _X SIP Call” regulation that provided ozone-season NO _X emission allowances to a 19-state region east of the Mississippi. This program provides for NO _X allowance trading similar to the SO ₂ (acid rain) trading program already in effect.

During 2004, the Illinois plants stayed within their NO _X allocations by augmenting their allocation with early reduction credits generated within the fleet. In 2005, the Illinois plants used banked allowances, along with some purchased allowances, to stay within their NO _X allocations. In 2006, the Illinois plants used purchased allowances to stay within their NOx allocations. Midwest Generation plans to continue to purchase allowances as it implements the agreement it reached with the Illinois EPA.

The Illinois EPA has begun to develop SIPs to meet National Ambient Air Quality Standards for 8-hour ozone and fine particulates with the intent of bringing non-attainment areas, such as Chicago, into attainment. The SIPs are expected to deal with all emission sources, not just power generators, and to address emissions of NO _X , SO ₂ , and volatile organic compounds. These SIPs are to be submitted to the US EPA by June 15, 2007 for 8-hour ozone, and by April 5, 2008 for fine particulates.

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Midwest Generation’s agreement with the Illinois EPA and the pending CPS include emission controls that will contribute to ozone and fine particulate attainment. Midwest Generation expects, but cannot guarantee, that the reductions required under the agreement and the pending CPS will be sufficient for compliance with future ozone and particulate matter regulations. Additional information regarding Midwest Generation’s agreement with the Illinois EPA appears in the MD&A under the heading “Air Quality Standards—Clean Air Act—Illinois.”

Pennsylvania

The Homer City facilities comply with current ozone requirements due to the selective catalytic reduction systems installed at each unit. Particulate requirements are met using a combination of scrubber reductions from Unit 3 and the purchase of SO ₂ allowances. Pennsylvania has not yet proposed new regulations to implement the National Ambient Air Quality Standards for 8-hour ozone or for fine particulates. These SIPs are to be submitted to the US EPA by June 15, 2007 and April 5, 2008, respectively. Although the final form of the SIPs is not yet known, at this time EME anticipates that current treatment will be sufficient to meet the SIP requirements for 8-hour ozone, and that the SIP for fine particulates will require the continued use of the existing scrubber supplemented by the purchase of SO ₂ allowances.

Regional Haze

See “Business of Southern California Edison Company—Environmental Matters Affecting SCE—Regional Haze” for a general description of the regional haze regulations. States are required to revise their SIPs to demonstrate reasonable further progress towards meeting regional haze goals. Emission reductions achieved through other ongoing control programs may be sufficient to demonstrate reasonable progress toward the long-term goal, particularly for the first 10 to 15 year phase of the program. States must develop SIPs by December 2007. It is possible that sources subject to the CAIR will be able to satisfy their obligations under the regional haze regulations through compliance with the CAIR. However, until the SIPs are revised, EME cannot predict whether it will be required to install BART or implement other control strategies, and cannot identify the financial impacts of any additional control requirements.

The CPS, discussed in the MD&A under the heading “Other Developments— Environmental Matters— Air Quality Standards—Clean Air Act—Illinois,” addresses emissions reductions at BART affected sources. In Pennsylvania, the PADEP considers the CAIR to meet the BART requirements and the Homer City facilities are only required to consider reductions in emissions of suspended particulate matter (PM10), which at this time have not been developed by the state.

New Source Review Requirements

Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address Clean Air Act NSR compliance issues at the nation’s coal-fired power plants. The NSR regulations impose certain requirements on facilities, such as electric generating stations, in the event that modifications are made to air emissions sources at a facility. The US EPA’s strategy included both the filing of a number of suits against power plant owners, and the issuance of a number of administrative notices of violation to power plant owners alleging NSR violations. Neither EME nor any of its subsidiaries have been named as a defendant in these lawsuits and have not received any administrative Notices of Violation alleging NSR violations at any of their facilities.

On October 13, 2005, the US EPA proposed a change to the NSR program. The proposal put forth several options for a new emissions test based on the impact of a facility modification on a facility’s

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maximum hourly emissions or its emissions per unit of energy produced. The existing NSR emissions test is based on the impact of a modification on a generating station’s net annual emissions.

In October 2005, the US EPA announced a revised NSR strategy to take account of recent US EPA rulemakings, such as the CAIR and regional haze rules, affecting coal-fired power plants. Under the revised strategy, while the US EPA will continue to pursue filed cases and cases in active negotiation, it intends to shift its future enforcement focus from coal-fired power plants to other sectors where compliance assurance activities have the potential to produce significant environmental benefits.

Prior to EME’s purchase of the Homer City facilities, the US EPA requested information under Section 114 of the Clean Air Act from the prior owners of the plant concerning physical changes at the plant. This request was part of the US EPA’s industry-wide investigation of compliance by coal-fired plants with the Clean Air Act NSR requirements. On February 21, 2003, Midwest Generation received a request for information under Section 114 regarding past operations, maintenance and physical changes at the Illinois plants from the US EPA. On July 28, 2003, Commonwealth Edison Company received a substantially similar request for information from the US EPA related to the same plants. In a request dated February 1, 2005, the US EPA submitted a request for additional information to Midwest Generation. Midwest Generation has provided responses to these requests. Other than these requests for information, no NSR enforcement-related proceedings have been initiated by the US EPA with respect to any of EME’s facilities.

EME will continue to monitor developments with respect to changes to the NSR program and NSR enforcement to assess what implications, if any, they will have on its facilities, its results of operations or financial position.

Water Quality Regulation

Clean Water Act—Cooling Water Intake Structures

See “Business of Southern California Edison Company—Environmental Matters Affecting SCE—Water Quality Regulation” for a general description of Section 316(b) of the Clean Water Act and the challenge to the US EPA regulations implementing Section 316(b). Information regarding cooling water intake structure standards, water quality issues in Illinois and Pennsylvania, and their effect on EME appear in the MD&A under the heading “Other Developments—Environmental Matters—Water Quality Regulation.”

Climate Change

For a discussion of the laws and regulations relating to climate change, see “Business of Southern California Edison Company—Environmental Matters Affecting SCE—Climate Change.”

Information regarding current developments on climate change and GHG regulation appears in the MD&A under the heading “Other Developments—Environmental Matters—Climate Change.”

The ultimate outcome of the climate change debate could have a significant economic effect on EME. Any legal obligation that would require EME to reduce substantially its emissions of CO ₂ or would impose additional costs or charges for the emission of CO ₂ could have a materially adverse effect on EME.

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Employees of EME

MEHC has no full-time employees. At December 31, 2006, EME and its subsidiaries employed 1,751 people, including:

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Business of Edison Capital

Edison Capital has investments worldwide in energy and infrastructure projects, including power generation, electric transmission and distribution, transportation, and telecommunications. Edison Capital also has investments in affordable housing projects located throughout the United States.

At the end of 2005, the employees of Edison Capital were transferred to EME and a services agreement was executed effective December 26, 2005 to provide for intercompany charges for services provided by EME to Edison Capital. During December 2005, Edison Capital dividended a portion of its wind projects to its parent company, Edison Mission Group Inc. The projects were then contributed to EME. During the first half of 2006, Edison Capital dividended its remaining wind projects to Edison Mission Group Inc., and the projects were subsequently contributed to EME.

At the present time, no new investments are expected to be made by Edison Capital and the focus will be on managing the existing investment portfolio.

Energy and Infrastructure Investments of Edison Capital

Edison Capital’s energy and infrastructure investments are in the form of domestic and cross-border leveraged leases, partnership interests in international infrastructure funds and operating companies in the United States.

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The rent paid by the lessee is expected to cover debt payments and provide a profit to Edison Capital. As lessor, Edison Capital also claims the tax benefits, such as depreciation of the asset or amortization of lease payments and interest deductions. All regulatory, operating, maintenance, insurance and decommissioning costs are the responsibility of the lessees. The lessees’ performance is secured not only by the project assets, but also by other collateral that was valued as of December 31, 2006, in the aggregate at approximately $1.9 billion against $2.5 billion invested in leveraged leases. The lenders have a priority lien against the assets but the loans are otherwise non-recourse to Edison Capital. Edison Capital’s leveraged lease investments depend upon the performance of the asset, the lessee’s performance of its contract obligations, enforcement of remedies and sufficiency of the collateral in the event of default, and realization of tax benefits.

Infrastructure Funds

Edison Capital holds a minority interest as a limited partner in three separate funds that invest in infrastructure assets in Latin America, Asia and countries in Europe with emerging economies. Edison Capital is also a member of the investment committee of each fund. At year-end 2006, Edison Capital had an investment balance of $25 million in the Latin America fund, $19 million in the

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Asia fund, and $20 million in the emerging Europe fund. As of December 31, 2006, Edison Capital did not have any additional investment commitments to these funds. The fund managers look to exit the investments on favorable terms which provide a return to the limited partners from appreciation in the value of the investment. The ability to exit investments on favorable terms depends upon many factors, including the economic conditions in each region, the performance of the asset, and whether there is a public or private market for these interests. For some fund investments there may also be foreign currency exchange rate risk.

Affo rdable Housing Investments of Edison Capital

At December 31, 2006, Edison Capital had a net investment of $29 million in approximately 335 affordable housing projects with approximately 27,000 units rented to qualifying low-income tenants in 36 states. These investments are usually in the form of majority interests in limited partnerships or limited liability companies. With a few exceptions, the projects are managed by third parties. For 105 projects, Edison Capital has guaranteed a minimum return to the syndicated investor. Edison Capital continues to consolidate the investment funds subject to the guaranteed minimum return. Edison Capital retained a minority interest in, and continues to monitor, all of the syndicated investments. Edison Capital is entitled to low-income housing tax credits, depreciation and interest deductions, and a small percentage of cash generated from the projects. Edison Capital’s tax credits from these projects could be recaptured by the Internal Revenue Service if, among other things, the project fails to comply with the requirements of the tax credit program, costs are excluded from the eligible basis used to compute the amount of tax credits, or the project changes ownership through foreclosure. In most cases, Edison Capital is indemnified by the project manager (or parties related to it) against some losses, but there is no assurance of collecting against such indemnities. As of year-end 2006, Edison Capital had not experienced any significant recapture of tax credits from its affordable housing projects.

Business Environment of Edison Capital

Edison Capital’s investments may be affected by the financial condition of other parties, the performance of assets, regulatory, economic conditions and other business and legal factors. Information regarding the business environment of Edison Capital appears in the MD&A under the heading “EMG: Market Risk Exposure—Edison Capital’s Credit and Performance Risk.”

Under tax allocation arrangements among Edison International and its subsidiaries, Edison Capital receives cash for federal and state tax benefits from its investments that are utilized on Edison International’s tax return. Information about Edison Capital’s tax allocation payments and tax exposures is contained in the MD&A under the heading “Edison Capital’s: Liquidity—Intercompany Tax-Allocation Payments” and “Other Developments—Federal Income Taxes.”

Risks Relating to E dison International

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 repay funds to Edison International.

Edison International is a holding company and, as such, Edison International 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

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ability to pay upstream dividends 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.

Edison International’s cash flows and earnings could be adversely affected by tax developments relating to Edison Capital’s lease transactions.

Edison Capital entered into certain types of lease transactions which have been challenged by the Internal Revenue Service. If Edison International is not successful in its defense of the tax treatment of those transactions, the payment of taxes could have a significant impact on cash flows. Also, the adoption of changes in accounting policies relating to the accounting for leases could cause a material effect on reported earnings by requiring Edison International to reverse earnings previously recognized as a current period adjustment and to report these earnings over the remaining life of the leases. More information regarding the lease transactions is contained in the MD&A under the heading “Other Developments—Federal Income Taxes.”

Edison International and its subsidiaries are subject to costs and other effects of legal proceedings as well as changes in or additions to applicable tax laws, rates or policies, rates of inflation, and accounting standards.

Edison International and its subsidiaries are subject to costs and other effects of legal and administrative proceedings, settlements, investigations and claims, as well as the effect of new, or changes in, tax laws, rates or policies, rates of inflation and accounting standards.

Risks Relating to SCE

SCE’s financial viability depends upon its ability to recover its costs in a timely manner from its customers through regulated rates.

SCE is a regulated entity subject to CPUC jurisdiction in almost all aspects of its business, including the rates, terms and conditions of its services, procurement of electricity for its customers, issuance of securities, dispositions of utility assets and facilities and aspects of the siting and operations of its electricity distribution systems. SCE’s ongoing financial viability depends on its ability to recover from its customers in a timely manner its costs, including the costs of electricity purchased for its customers, in its CPUC-approved rates and its ability to pass through to its customers in rates its FERC-authorized revenue requirements. SCE’s financial viability also depends on its ability to recover in rates an adequate return on capital, including long-term debt and equity. If SCE is unable to recover any material amount 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.

SCE’s revenues and earnings are substantially affected by regulatory proceedings known as general rate cases and cost of capital proceedings. General rate cases are expected to occur every three years. During those cases, the CPUC determines SCE’s rate base (the value of assets on which SCE earns a rate of return for investors), depreciation rates, operation and maintenance costs, and administrative and general costs that SCE may recover from its customers through its rates. Cost of capital proceedings are conducted annually. During those cases, the CPUC authorizes SCE’s capital structure and the return on

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common equity applicable to the rate base determined in the general rate case proceedings. More information about these proceedings is set forth in the MD&A under the heading “SCE: Regulatory Matters.”

SCE’s energy procurement activities are subject to regulatory and market risks that could adversely affect its financial condition, liquidity, and earnings.

SCE obtains energy, capacity, and ancillary services needed to serve its customers from its own generating plants and contracts with energy producers and sellers. California law and CPUC decisions allow SCE to recover in customer rates 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. In addition, SCE is subject to the risks of unfavorable or untimely CPUC decisions about the compliance of procurement activities with its procurement plan and the reasonableness of certain procurement-related costs.

Many of SCE’s power purchase contracts are tied to market prices for natural gas. Some of its contracts also are subject to volatility in market prices for electricity. SCE seeks to hedge its market price exposure to the extent authorized by the CPUC. SCE may not be able to hedge its risk for commodities on favorable terms or fully recover the costs of hedges in rates, which could adversely affect SCE’s liquidity and results of operation.

In its power purchase contracts and other procurement arrangements, SCE is exposed to risks from changes in the credit quality of its counterparties. If a counterparty were to default on its obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power.

SCE relies on access to the capital markets. If SCE were unable to access capital markets or the cost of capital were to substantially increase, its liquidity and operations could be adversely affected.

SCE’s ability to make scheduled payments of principal and interest, refinance debt, and fund its operations and planned capital expenditure projects depends on its cash flow and access to the capital markets. SCE’s ability to arrange financing and the costs of such capital are dependent on numerous factors, including its levels of indebtedness, maintenance of acceptable credit ratings, its financial performance, liquidity and cash flow, and other market conditions. Market conditions which could adversely affect SCE’s financing costs and availability include:

SCE may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on SCE’s liquidity and operations.

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SCE is subject to numerous environmental laws and regulations with respect to operation of its facilities. New laws and regulations could adversely affect SCE.

The operation of SCE’s power generation, transmission, and distribution facilities is subject to numerous environmental laws and regulations. Those laws and regulations require SCE to expend substantial sums to mitigate or remove the effect of its operations on the environment and can impede the development of new facilities. Violations of environmental laws and regulations can result in fines, penalties and liability to third parties. In addition, new environmental laws, regulations and standards may be adopted that would impose substantial costs on SCE or impair its future operations. Environmental advocacy groups and regulatory agencies have been focusing considerable attention on CO ₂ emissions and the effect of those emissions on global warming. The adoption of new laws and regulations to CO ₂ or other emissions could adversely affect the operation of SCE’s generating plants and other facilities and result in additional costs that could adversely affect SCE’s results of operations.

SCE is subject to extensive regulation and the risk of adverse regulatory decisions and changes in applicable regulations or legislation.

SCE operates in a highly regulated environment. SCE’s business is subject to extensive federal, state and local energy, environmental and other laws and regulations. The CPUC regulates SCE’s retail operations, and the FERC regulates SCE’s wholesale operations. The United States NRC regulates SCE’s nuclear power plants. The construction, planning, and siting 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 siting of transmission lines that are outside of California are subject to the regulation of the relevant state agency. Additional regulatory authorities with jurisdiction over some of SCE’s operations and construction projects include the California Air Resources Board, the California State Water Resources Control Board, the California Department of Toxic Substances Control, the California Coastal Commission, the US EPA, the Bureau of Land Management, the U.S. Fish and Wildlife Services, the U.S. Forest Service, Regional Water Quality Boards, the Bureau of Indian Affairs, the United States Department of Energy, the NRC, and various local regulatory districts.

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. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to SCE or SCE’s facilities in a manner that may have a detrimental effect on SCE’s business or result in significant additional costs because of SCE’s need to comply with those requirements.

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

Spent fuel storage capacity could be insufficient to permit long-term operation of SCE’s nuclear plants.

SCE operates and is majority owner of San Onofre and is part owner of Palo Verde. The United States 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 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.

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Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.

Federal law limits public liability from a nuclear incident to $10.8 billion. SCE and other owners of the San Onofre and Palo Verde nuclear generating stations have purchased the maximum private primary insurance available of $300 million per site. If the public liability limit is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators. In the event of such an under-insured nuclear incident, a tension could exist between the federal government’s attempt to impose revenue-raising measures upon SCE and the CPUC’s willingness to allow SCE to pass this liability along to its customers, resulting in undercollection of SCE’s costs.

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 its facilities.

SCE owns and operates extensive electricity facilities that are interconnected to the United States western electricity grid. The operation of SCE’s facilities and the facilities of third parties on which it relies involves numerous risks, including:

The occurrence of any of these events could result in lower revenues or increased expenses, or both, which may not be fully recovered through insurance, rates or other means in a timely manner or at all.

SCE’s insurance coverage may not be sufficient under all circumstances and SCE may not be able to obtain sufficient insurance.

SCE’s insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A loss for which SCE is not fully insured could materially and adversely affect SCE’s financial condition and results of operations. Further, due to rising insurance costs and changes in the insurance markets, insurance coverage may not continue to be available at all or at rates or on terms similar to those presently available to SCE.

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Risks Relating to EMG

MEHC depends upon cash flows from EME to service its debt.

MEHC’s principal asset is the common stock of EME. In July 2001, MEHC issued $800 million of 13.50% senior secured notes due 2008. The senior secured notes are secured by a first priority security interest in EME’s common stock. Any foreclosure on the pledge of EME’s common stock by the holders of the senior secured notes would result in a change in control of EME, which could have a material adverse effect on MEHC. Dividends from EME are limited based on its earnings and cash flow, the terms of restrictions contained in EME’s corporate credit facility, business and tax considerations and restrictions imposed by applicable law. A discussion of contractual restrictions that could constrain the ability of EMG’s subsidiaries to pay dividends or distributions to EME appears in the MD&A under the heading “EMG: —Liquidity MEHC—Dividend Restrictions in Major Financings.”

EME has substantial interests in merchant energy power plants which are subject to market risks related to wholesale energy prices.

EME’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.

The factors that influence the market prices for energy, capacity and ancillary services include:

In addition, unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, the wholesale power markets are subject to significant and unpredictable price fluctuations over relatively short periods of time.

There is no assurance that EME’s merchant energy power plants will be successful in selling power into their markets or that the prices received for their power will generate positive cash flows. If EME’s

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merchant energy power plants do not meet these objectives, they may not be able to generate enough cash to service their own debt and lease obligations, which could have a material adverse effect on EME.

EME’s financial results can be affected by changes in fuel prices, fuel transportation cost increases, and interruptions in fuel supply.

EME’s business is subject to changes in fuel costs, which may negatively affect its financial results and financial position by increasing the cost of producing power. The fuel markets can be volatile, and actual fuel prices can differ from EME’s expectations.

Although EME attempts to purchase fuel based on its known fuel requirements, it is still subject to the risks of supply interruptions, transportation cost increases, and fuel price volatility. In addition, fuel deliveries may not exactly match energy sales, due in part to the need to purchase fuel inventories in advance for reliability and dispatch requirements. The price at which EME can sell its energy may not rise or fall at the same rate as a corresponding rise or fall in fuel costs. See “EMG: Market Risk Exposures—MEHC’s Commodity Price Risk” in the MD&A.

EME may not be able to hedge market risks effectively.

EME is exposed to market risks through its ownership and operation of merchant energy power plants and through its power marketing business. These market risks include, among others, volatility arising from the timing differences associated with buying fuel, converting fuel into energy and delivering energy to a buyer. EME uses forward contracts and derivative financial instruments, such as futures contracts and options, to manage market risks and exposure to fluctuating electricity and fuel prices. However, EME cannot provide assurance that these strategies successfully mitigate market risks, or that they will not result in net losses.

EME may not cover the entire exposure of its assets or positions to market price volatility, and the level of coverage will vary over time. Fluctuating commodity prices may negatively affect EME’s financial results to the extent that assets and positions have not been hedged.

The effectiveness of EME’s hedging activities may depend on the amount of working capital available to post as collateral in support of these transactions, either in support of performance guarantees or as a cash margin. The amount of credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in a requirement to provide cash collateral and letters of credit in very large amounts. Without adequate liquidity to meet margin and collateral requirements, EME could be exposed to the following:

As a result of these and other factors, EME cannot predict with precision the effect that risk management decisions may have on its businesses, operating results or financial position. See the discussion in the MD&A under the heading “EMG: Liquidity—MEHC’s Margin, Collateral Deposits and Other Credit Support for Energy Contracts.”

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EME is exposed to credit and performance risk from third parties under supply and transportation contracts.

EME relies on contracts for the supply and transportation of fuel and other services required for the operation of its generation facilities. EME’s operations are exposed to the risk that counterparties will not perform their obligations. If a counterparty failed to perform under a contract, EME would need to obtain alternate suppliers for their requirements of fuel or other services, which could result in higher costs or disruptions in its operations. Furthermore, EME is exposed to credit risk because damages related to a breach of contract may not be recoverable. Accordingly, the failure of a supplier to fulfill its contractual obligations could have a material adverse effect on EME’s financial results.

EME is subject to extensive energy industry regulation.

EME’s operations are subject to extensive regulation by governmental agencies. EME’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. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. 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.

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. In addition, many of EME’s facilities are subject to rules, restrictions and terms of participation imposed and administered by various RTOs and ISOs. For example, ISOs and RTOs may impose bidding and scheduling rules, both to curb the potential exercise of market power and to facilitate market functions. Such actions may materially affect EME’s results of operations.

There is no assurance that the introduction of new laws or other future regulatory developments will not have a material adverse effect on EME’s business, results of operations or financial condition, nor is there any assurance that EME or its subsidiaries will be able to obtain and comply with all necessary licenses, permits and approvals for its projects. If projects cannot comply with all applicable regulations, EME’s business, results of operations and financial condition could be adversely affected.

EME is subject to extensive environmental regulation and permitting requirements that may involve significant and increasing costs.

EME’s operations are subject to extensive environmental regulation with respect to, among other things, air quality, water quality, waste disposal, and noise. EME is required to comply with these regulations, as well as conditions established by licenses, permits and other approvals, in order to construct, operate or modify its facilities. Failure to comply with these requirements could subject EME to civil or criminal liability, the imposition of liens or fines, or actions by regulatory agencies seeking to curtail EME’s operations.

EME devotes significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with environmental regulatory requirements. EME believes that it is currently in substantial compliance with environmental regulatory requirements and that maintaining

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compliance with current requirements will not materially affect its financial position or results of operations. However, the current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. Environmental advocacy groups and regulatory agencies in the United States have been focusing considerable attention on CO ₂ emissions from coal-fired power plants and their potential role in climate change. The adoption of laws and regulations to implement CO ₂ controls could adversely affect EME’s coal-fired plants. Also, coal plant emissions of NO _X and SO ₂ , mercury and particulates are subject to increased controls and mitigation expenses. Additionally, certain of the states in which EME operates are contemplating air pollution control regulations that are more stringent than existing and proposed federal regulations. The continued operation of EME’s facilities, particularly its coal-fired facilities, will require substantial capital expenditures for environmental controls.

For example, in December 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NO _X and SO ₂ emissions at Midwest Generation’s Illinois coal-fired power plants. Capital expenditures relating to controls contemplated by the agreement are expected (in 2006 dollars) to be in the range of approximately $2.7 billion to $3.4 billion through 2018. Additional information appears in the MD&A under the heading “Other Developments—Environmental Matters—Air Quality Standards—Clean Air Act—Illinois.” There is no assurance that these capital expenditures will not exceed the above estimates.

In addition, future environmental laws and regulations, and future enforcement proceedings that may be taken by environmental authorities, could affect the costs and the manner in which EME conducts its business. There is no assurance that EME would be able to recover these increased costs from its customers or that its business, financial position and results of operations would not be materially adversely affected. Furthermore, changing environmental regulations could make some units uneconomical to maintain or operate. If EME cannot comply with all applicable regulations, it could be required to retire or suspend operations at its facilities, or restrict or modify the operations of its facilities, and its business, results of operations and financial condition could be adversely affected.

Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project or generating facility. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures. EME cannot provide assurance that it will be able to obtain and comply with all necessary licenses, permits and approvals for its plants. If there is a delay in obtaining required approvals or permits or if EME fails to obtain and comply with such permits, the operation of EME’s facilities may be interrupted or become subject to additional costs.

EME’s development projects or future acquisitions may not be successful.

EME’s future financial condition, results of operation and cash flows will depend in large part upon its ability to successfully implement its long-term strategy, which includes the development and acquisition of electric power generation facilities, with an emphasis on renewable energy (primarily wind) and gas-fired power plants. EME may be unable to identify attractive acquisition or development opportunities and/or to complete and integrate them on a successful and timely basis. Furthermore, implementation of

this strategy may be affected by factors beyond EME’s control, such as increased competition, legal and regulatory developments, price volatility in electric or fuel markets, and general economic conditions.

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In support of its development activities, EME has entered into commitments of $489 million to purchase turbines for future projects and plans to make substantial additional commitments in the future. In addition, EME expends significant amounts for preliminary engineering, permitting, legal and other expenses before it can determine whether it will win a competitive bid, or whether a project is feasible or economically attractive.

EME’s development activities are subject to risks including, without limitation, risks related to project siting, financing, construction, permitting, and governmental approvals. EME may not be successful in developing new projects or the timing of such development may be delayed beyond the date such turbines are ready for installation. Furthermore, EME may not be able to obtain financing for new projects that are developed and may not be able to obtain sufficient equity capital or additional borrowings to enable it to fund equity commitments for future projects. If a project under development is abandoned, EME would expense all capitalized development costs incurred in connection with that project, and could incur additional losses associated with any related contingent liabilities. If EME is not successful in developing new projects, it may be required to sell turbines that were purchased and such sales may result in substantial losses. For example, in February 2007, EME was advised that it was an unsuccessful bidder in the request for offers conducted by SCE for the supply of generation capacity. EME plans to use the turbines which it had purchased and reserved for this bid for other generation supply opportunities, although there is no assurance that these efforts will be successful.

Finally, EME cannot provide assurance that its development projects or acquired assets will generate sufficient cash flow to support the indebtedness incurred to acquire them or the capital expenditures needed to develop them, or that the rate of return from such projects or assets will be sufficient to justify the decision to invest in them.

Competition could adversely affect EME’s business.

The independent power industry is characterized by numerous capable competitors, some of whom may have more extensive operating experience in the acquisition and development of power projects, larger staffs, and greater financial resources than EME. Several 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. This could affect EME’s ability to compete effectively in the markets in which those entities operate.

Newer plants owned by EME’s competitors are often more efficient than EME’s facilities. This may put some of EME’s facilities at a competitive disadvantage to the extent that its competitors are able to produce more power from each increment of fuel than EME’s facilities are capable of producing. Over time, some of EME’s facilities may become obsolete in their markets, or be unable to compete, because of the construction of newer, more efficient power plants.

In addition to the competition already existing in the markets in which EME presently operates or may consider operating in the future, EME is likely to encounter significant competition as a result of further consolidation of the power industry by mergers and asset reallocations, which could create powerful new competitors, and new market entrants such as investment companies. In addition, the EPAct 2005 and other regulatory initiatives may result in changes in the power industry to which EME may not be able to respond in as timely and effective manner as its competitors.

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EME may not be able to raise capital on favorable terms, to refinance existing EME corporate or subsidiary indebtedness or to fund operations, capital expenditures, future acquisitions and development activities, which could affect its results of operations.

The factors that influence EME’s ability to arrange for financing and its costs of capital include:

While EME believes that its sources of capital will be adequate to meet obligations for the foreseeable future, this belief is based on a number of material assumptions, including without limitation assumptions about EME’s ability to access the capital and commercial lending markets, the operating and financial performance of EME’s subsidiaries, and the ability of EME’s subsidiaries to pay dividends. Any of these assumptions could prove to be incorrect. EME cannot provide assurance that its projected sources of capital will be available when needed or that its actual cash requirements will not be greater than expected.

EME and its subsidiaries have a substantial amount of indebtedness, including long-term lease obligations.

As of December 31, 2006, consolidated debt of EME was $3.2 billion. In addition, EME’s subsidiaries have $4.3 billion of long-term power plant lease obligations that are due over a period ranging up to 29 years. The substantial amount of consolidated debt and financial obligations presents the risk that EME and its subsidiaries might not have sufficient cash to service their indebtedness or long-term lease obligations and that the existing corporate debt, project debt and lease obligations could limit the ability of EME and its subsidiaries to grow their business, to compete effectively or to operate successfully under adverse economic conditions. If EME’s or a subsidiary’s cash flows and capital resources were insufficient to allow it to make scheduled payments on its debt, EME or its subsidiaries might have to reduce or delay capital expenditures, sell assets, seek additional capital, or restructure or refinance the debt. The terms of EME’s or its subsidiaries’ debt may not allow these alternative measures, the debt or equity may not be available on acceptable terms, and these alternative measures may not satisfy all scheduled debt service obligations.

The ability of EME’s largest subsidiary, Midwest Generation, LLC, to make distributions is restricted.

Midwest Generation, which owns or leases the Illinois plants, has entered into financing documents that contain restrictions on its ability to pay dividends. See “EMG: Liquidity—Liquidity and Capital Resources” in the MD&A.

EME is the guarantor of the Powerton and Joliet (Units 7 and 8) leases and is obligated under intercompany notes to make debt service payments to Midwest Generation. Each intercompany note is a general corporate obligation of EME and payments on it are made from distributions from subsidiaries and other sources of cash received by EME. Accordingly, EME must continue to make payments under the intercompany notes regardless of whether or not Midwest Generation makes distributions to EME. If

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EME were not able to satisfy its obligations under the intercompany notes, it would result in a default under the financing documents of EME and Midwest Generation. This could have a material adverse effect on the results of operations and cash flow of EME.

Restrictions in EME’s certificate of incorporation, its credit facilities and the MEHC financing documents limit the ability of EME and its subsidiaries to enter into specified transactions that they otherwise may enter into and may significantly impede their ability to refinance their debt.

The financing documents entered into by MEHC contain financial and investment covenants restricting EME and its subsidiaries. EME’s certificate of incorporation binds it to the provisions in MEHC’s financing documents by restricting EME’s ability to enter into specified transactions and engage in specified business activities without shareholder approval. The instruments governing EME’s indebtedness also contain financial and investment covenants. Restrictions contained in these documents could affect, and in some cases significantly limit or prohibit, EME and its subsidiaries’ ability to, among other things, incur, refinance, and prepay debt, make capital expenditures, pay dividends and make other distributions, make investments, create liens, sell assets, enter into sale and leaseback transactions, issue equity interests, enter into transactions with affiliates, create restrictions on the ability to pay dividends or make other distributions and engage in mergers and consolidations. These restrictions may significantly impede the ability of EME and its subsidiaries to take advantage of business opportunities as they arise, to grow their business and compete effectively, or to develop and implement any refinancing plans in respect of their indebtedness. See “—EME and its subsidiaries have a substantial amount of indebtedness, including long-term lease obligations” above, for further discussion.

In addition, in connection with the entry into new financings or amendments to existing financing arrangements, EME’s and its subsidiaries’ financial and operational flexibility may be further reduced as a result of more restrictive covenants, requirements for security and other terms that are often imposed on sub-investment grade entities.

EME’s projects may be affected by general operating risks and hazards customary in the power generation industry. EME may not have adequate insurance to cover all these hazards.

The operation of power generation facilities involves many operating risks, including:

These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of or damage to the environment, and suspension of operations. The occurrence of one or more of the events listed above could decrease or

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eliminate revenues generated by EME’s projects or significantly increase the costs of operating them, and could also result in EME’s being named as a defendant in lawsuits asserting claims for substantial damages, potentially including environmental cleanup costs, personal injury, property damage, fines and penalties. Equipment and plant warranties and insurance may not be sufficient or effective under all circumstances to cover lost revenues or increased expenses. A decrease or elimination in revenues generated by the facilities or an increase in the costs of operating them could decrease or eliminate funds available to meet EME’s obligations as they become due and could have a material adverse effect on EME. A default under a financing obligation of a project entity could result in a loss of EME’s interest in the project.

The accounting for EME’s hedging and proprietary trading activities may increase the volatility of its quarterly and annual financial results.

EME engages in hedging activities in order to mitigate its exposure to market risk with respect to electricity sales from its generation facilities, fuel utilized by those facilities and emissions allowances. EME generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. EME also uses derivative contracts with respect to its limited proprietary trading activities, through which EME attempts to achieve incremental returns by transacting where it has specific market expertise. These derivative contracts are recorded on its balance sheet at fair value pursuant to SFAS No. 133. Some of these derivative contracts do not qualify under SFAS No. 133 for hedge accounting and changes in their fair value are therefore recognized currently in earnings as unrealized gains or losses. As a result, EME’s financial results, including gross margin, operating income and balance sheet ratios, will at times be volatile and subject to fluctuations in value primarily due to changes in electricity and fuel prices. See “MEHC’s Accounting for Energy Contracts” in the MD&A.

None.