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

 

FORM 10-K

 

 

 

(626) 302-2222
(Registrant’s telephone number, including area code)

 

 

 

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  þ      No  o

 

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

 

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

 

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

 

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

 

 

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

 

The aggregate market value of registrant’s voting stock held by non-affiliates was approximately $16.7 billion on or about June 30, 2008, based upon prices reported on the New York Stock Exchange. As of February 25, 2009, there were 325,811,206 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

Parts I and II

 

(1) Designated portions of the registrant’s Annual Report to Shareholders for the year ended December 31, 2008

 

 

TABLE OF CONTENTS

 

 

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International’s current expectations and projections about future events based on Edison International’s knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by Edison International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words “expects,” “believes,” “anticipates,” “estimates,” “projects,” “intends,” “plans,” “probable,” “may,” “will,” “could,” “would,” “should,” and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. See “Risk Factors” in Part I, Item 1A of this report and “Introduction” in the MD&A for cautionary statements that accompany those forward-looking statements and identify important factors that could cause results to differ. Readers should carefully review those cautionary statements as they identify important factors that could cause results to differ, or that otherwise could impact Edison International or its subsidiaries.

 

Additional information about risks and uncertainties, including more detail about the factors described in this report, is contained throughout this report, in the MD&A that appears in the Annual Report, the relevant portions of which are filed as Exhibit 13 to this report, and which is incorporated by reference into Part II, Item 7 of this report, and in Notes to Consolidated Financial Statements. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International’s business. Forward-looking statements speak only as of the date they are made and Edison International assumes no duty to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the SEC.

 

Except when otherwise stated, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to “Edison International (parent)” or “parent company” mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.

PART I

 

rule became effective, and compliance with these standards became mandatory, on June 18, 2007. Both SCE and EME believe that they have taken all steps to be compliant with current NERC reliability standards that apply to their operations. Edison International anticipates that the FERC will adopt more stringent reliability standards in the future. The financial impact of complying with future standards cannot be determined at this time.

 

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.

 

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 believes that SCE and EME are in substantial compliance with environmental regulatory requirements. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which these subsidiaries conduct their businesses and could require substantial additional capital or operational expenditures or the ceasing of operations at certain of their facilities. There is no assurance that the financial position and results of operations of the subsidiaries would not be materially adversely affected. SCE and EME are unable to predict the precise extent to which additional laws and regulations may affect their 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 any of Edison International’s subsidiaries fails to comply with applicable environmental laws, it may be subject to injunctive relief, penalties and fines imposed by federal and state regulatory authorities.

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 under “Environmental Remediation.” For details about the environmental liabilities and other business risks arising 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 Affecting EME.”

 

The principal environmental laws and regulations affecting Edison International’s business are identified below.

 

Climate Change

 

Federal Legislative Initiatives

 

To date, the U.S. has pursued a voluntary GHG emissions reduction program to meet its obligations as a signatory to the UN Framework Convention on Climate Change. As a result of increased attention to climate change in the U.S., however, numerous bills have been introduced in the U.S. Congress that would reduce (and/or tax) GHG emissions in the U.S. Enactment of climate change legislation within the next several years now seems likely. See “Other Developments — Environmental Matters — Climate Change — Federal Legislative Initiatives” in the MD&A for further discussion.

 

Regional Initiatives

 

A number of regional initiatives have been undertaken or are in process related to GHG emissions. Implementing regulations for such regional initiatives are likely to vary from state to state and may be more stringent and costly than federal legislative proposals currently being debated in Congress. It cannot yet be determined whether or to what extent any federal legislative system would seek to preempt regional or state initiatives, although such preemption would greatly simplify compliance and eliminate regulatory duplication. See “Other Developments — Environmental Matters — Climate Change — Regional Initiatives” in the MD&A for further discussion.

 

State-Specific Legislation

 

In September 2006, California enacted two laws regarding GHG emissions. The first, known as AB 32 or the California Global Warming Solutions Act of 2006, establishes a comprehensive program to achieve reductions of GHG emissions. AB 32 requires the CARB to develop regulations which may include market-based compliance mechanisms targeted to reduce California’s GHG emissions to 1990 levels by 2020. The CARB’s mandatory program will take effect commencing in 2012 and will implement incremental reductions so that GHG emissions will be reduced to 1990 levels by 2020. See “Other Developments — Environmental Matters — State-Specific Legislation” in the MD&A for further discussion.

 

California law also currently requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010. For additional discussion of renewable procurement standards, see “Southern California Edison Company — SCE: Regulatory Matters — Procurement of Renewable Resources” in the MD&A. Additionally, the AB 32 scoping plan suggests a 33% by 2025 renewables portfolio standard be adopted. See “Other Developments — Environmental Matters — Climate Change — State Specific Legislation” in the MD&A for further discussion.

 

In addition, the CPUC is addressing climate change-related issues in other regulatory proceedings. In 2007, the CPUC expanded the scope of its GHG rulemaking to include GHG emissions associated with the transmission, storage, and distribution of natural gas in California. This proceeding could affect SCE as a natural gas customer.

Litigation Developments

 

Climate change regulation may also be affected by litigation in federal and state courts, as well as actions by licensing authorities.

 

Information regarding these developments appears in the MD&A under the heading “Other Developments — Environmental Matters — Climate Change — Litigation Developments.”

 

Emissions Data Reporting

 

SCE is a member of the California Climate Action Registry (CCAR), a non-profit, voluntary membership organization established by state law to allow members to report and certify their greenhouse gas emissions. SCE has been reporting annually to the CCAR since 2002. SCE’s 2007, independently certified GHG emissions, as reported to the CCAR were approximately 6.8 million metric tons from SCE-owned generation. EME’s 2007, not independently verified, GHG emissions were approximately 47.4 million metric tons.

 

Edison International became a founding reporter to The Climate Registry, formed in May 2008. The Climate Registry is a multi-national organization, which allows organizations to voluntarily inventory, verify, and publicly report their GHG emissions. Both SCE and EME will be filing verified emissions information for 2008 in June 2009 with The Climate Registry. Both SCE’s and EME’s reported emissions are pro-rated to their ownership interests in the emitting facilities.

 

Responses to Energy Demands and Future GHG Emission Constraints

 

Irrespective of the outcome of federal legislative deliberations, Edison International believes that substantial limitations on GHG emissions are inevitable, through increased costs, mandatory emission limits or other mechanisms, and that demand for energy from renewable sources will also continue to increase. As a result, SCE and EME are utilizing their experience in developing and managing a variety of energy generation systems to create a generation profile, using sources such as wind, solar, geothermal, biomass and small hydro plants, that will be adaptable to a variety of regulatory and energy use environments. SCE leads the nation in renewable power delivery. Its renewables portfolio of owned and procured sources currently consists of: 1,136 MW from wind, 906 MW from geothermal, 356 MW from solar, 178 MW from biomass, and 200 MW from small hydro.

 

SCE has developed and promoted several energy efficiency and demand response initiatives in the residential market, including an ongoing meter replacement program to help reduce peak energy demand; a rebate program to encourage customers to invest in more efficient appliances; subsidies for purchases of energy efficient lighting products; appliance recycling programs; widely publicized tips to our customers for saving energy; and a voluntary demand response program which offers customers financial incentives to reduce their electricity use. SCE is also replacing its electro-mechanical grid control systems with computerized devices that allow more effective grid management.

 

In April 2008, the CPUC authorized SCE to spend approximately $47 million on studying and evaluating the feasibility of an integrated gasification combined cycle plant with carbon capture and sequestration, referred to as Clean Hydrogen Power Generation (CHPG). SCE may be able to recover the amounts spent in rates subject to a requirement to make reasonable efforts to obtain co-funding from other entities. The CPUC has not authorized SCE to build or operate a CHPG plant, as technical feasibility and commercial reasonableness have not yet been proven. During 2008, EME participated in the early development of new clean coal generation projects. Due to the projected increase in the capital costs of these projects and the lack of a regulatory framework addressing CO ₂ sequestration, EME is not actively developing specific new clean coal generation or gasification projects at this time, but intends to continue to evaluate the feasibility of these projects in the future.

 

Corporate Governance Processes

 

Edison International’s Board of Directors regularly receives reports regarding environmental issues that affect Edison International and its subsidiaries, including climate change issues. In addition, Edison International has

had an Environmental Policy Council, which has primary responsibility regarding environmental issues. The membership of the Council includes senior executives of SCE and EME and it is chaired by Edison International’s Executive Vice President of Public Affairs. The council reports directly to Edison International’s Chief Executive Officer. Additionally, Edison International’s Chief Executive Officer is a Director of the Energy Power Research Institute (EPRI), an independent, nonprofit organization that provides research and analyses to address challenges in electricity, including environmental challenges such as climate change.

 

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

 

Air Quality Regulation

 

The Federal CAA, state clean air acts and federal and state regulations implementing such statutes apply to plants owned by Edison International’s subsidiaries as well as to plants from which these subsidiaries may purchase power, and have their largest impact on the operation of coal-fired plants. These federal regulations require states to adopt implementation plans, known as SIPs, that are equal to or more stringent than the federal requirements, detailing how they will attain the standards that are mandated by the relevant law or regulation. See “Other Developments — Environmental Matters — Air Quality Regulation” in the MD&A for further discussion.

 

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, commonly referred to as CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986 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 connection with the ownership and operation of their facilities, Edison International’s subsidiaries may be liable for costs associated with hazardous waste compliance and remediation required by the laws and regulations identified herein.

 

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, Illinois and Pennsylvania also regulate certain discharges not regulated by the US EPA.

 

Clean Water Act — Cooling Water Standards and Regulations

 

On July 9, 2004, the US EPA published the final Phase II rule implementing Section 316(b) of the Clean Water Act establishing standards for cooling water intake structures at existing large power plants. The purpose of the regulation was to reduce substantially the number of aquatic organisms that are pinned against cooling water intake structures (impingement) or drawn into cooling water systems (entrainment). Depending on the findings of demonstration studies contemplated by the rule to demonstrate the costs and benefits of compliance, cooling towers and/or other mechanical means of reducing impingement and entrainment of aquatic organisms could have been required.

On January 27, 2007, the Second Circuit rejected the US EPA rule and remanded it to the US EPA. Among the key provisions remanded by the court were the use of cost benefit and restoration to achieve compliance with the rule. On July 9, 2007, the US EPA suspended the requirements for cooling water intake structures, pending further rulemaking. On December 2, 2008, the U.S. Supreme Court heard oral arguments on this case. A decision is expected in the first half of 2009. The US EPA has delayed rulemaking pending the decision of the Supreme Court.

 

The California State Water Resources Control Board is developing a draft state policy on ocean-based, once-through cooling. Further 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 — Prohibition on the Use of Ocean-Based Once-Through Cooling.”

 

The Illinois EPA is currently considering the adoption of a rule that would impose stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des Plaines River. See “Business of Edison Mission Group Inc. — Environmental Matters Affecting EME — Water Quality Regulation — Illinois Effluent Water Quality Standards” below and “Other Developments — Environmental Matters — Water Quality Regulation — State Water Quality Standards — Illinois” in the MD&A for further discussion.

 

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. To date, none of the regulatory agencies with jurisdiction over Edison International’s subsidiaries have claimed there is a proven link between exposure to EMF and human health effects.

 

Financial information for geographic areas for Edison International can be found in Notes 16 and 17 of Notes to Consolidated Financial Statements. Edison International’s consolidated financial statements for all years presented reflect the reclassification of the results of EME’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.

 

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 432 cities and communities and a population of more than 13 million people. In 2008, SCE’s total operating revenue was derived as follows: 42% commercial customers, 38% residential customers, 6% resale sales, 7% industrial customers, 6% public authorities, and 1% agricultural and other customers. During 2008, the sources of electric power that serviced SCE’s customers were approximately 28% owned by SCE and approximately 72% procured from third parties. At December 31, 2008, SCE had consolidated assets of $31.0 billion and total shareholder’s equity of $7.4 billion. SCE had 16,344 full-time employees at year-end 2008.

 

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 unbundled 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 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 California Coastal Commission issued a coastal permit for the construction of the San Onofre Units 2 and 3 in 1974. 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 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 CARB, 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.

 

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 ISO, 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 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.

 

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 and municipal districts that create municipal utilities or community choice aggregators. In addition, customers may install their own on-site power generation facilities. Competition with SCE is conducted mainly on the basis of price, as customers seek the lowest cost power available. The effect of competition on SCE generally is to reduce the 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.

 

SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities (which exist primarily in California but also in Nevada and Arizona), 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 3,520 circuit miles of 220 kV lines, 1,240 circuit miles of 500 kV lines, and 889 substations. SCE’s distribution system, which takes power from substations to the customer, includes approximately 71,500 circuit miles of overhead lines, 40,000 circuit miles of underground lines, 1.5 million poles, 719 distribution substations, 715,527 transformers, and 810,519 area and streetlights, all of which are located in California.

 

SCE owns and operates the following generating facilities: (1) an undivided 78.21% interest (1,760 MW) in San Onofre Units 2 and 3, which are large pressurized water nuclear generating 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; (3) a diesel-fueled generating plant (9 MW) located on Santa Catalina island off the southern California coast, (4) a natural gas-fueled two unit power plant (1,050 MW) located in Redlands, California, and (5) four gas-fueled, combustion turbine peaker plants located in the cities of Norwalk, Ontario, Rancho Cucamonga and Stanton, California (combined generating capacity of 186 MW).

 

SCE owns an undivided 56% interest (884.8 MW net) in Mohave, which consists of two coal-fueled generating units that no longer operate located in Clark County, Nevada near the California border. See “SCE: Regulatory Matters — Mohave Generating Station and Related Proceedings” in the MD&A for more information.

 

SCE owns an undivided 15.8% interest (601 MW) in Palo Verde Units 1, 2 and 3, which are large pressurized water nuclear generating units 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, as operating agent for SCE and other co-owners of these generating units.

 

At year-end 2008, the SCE-owned generating capacity (summer effective rating) was divided approximately as follows: 43% nuclear, 22% hydroelectric, 22% natural gas, 13% coal, and less than 1% diesel. The capacity factors in 2008 for SCE’s nuclear and coal-fired generating units were: 82% for San Onofre; 78% for Four Corners; and 86% 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 24% capacity factor in 2008. These plants were operationally available for 73% 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.

 

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 2009 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 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 $5.80 billion in principal amount was outstanding on February 27, 2009. Such lien and SCE’s title to its properties generally are also 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 certain other liens, prior rights and encumbrances which do not materially affect SCE’s right to use such properties in its business.

 

SCE’s rights in Four Corners, which is located on land of the Navajo Nation under an easement from the United States and a lease from the Navajo Nation, may be subject to 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.

 

Information about operating issues related to Palo Verde appears in the MD&A under the heading “SCE: Other Developments — Palo Verde Nuclear Generating Station Outage and Inspection”. Information about nuclear decommissioning can be found under the heading “SCE: Other Developments” in the MD&A and 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.

 

California law prohibits the CEC from siting or permitting a nuclear power plant in California until the CEC finds that there exists a federally approved and demonstrated technology or means for the disposal of high-level nuclear waste.

 

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 2008 were as follows: 44.0% purchased power; 23.5% CDWR; and 32.5% SCE-owned generation consisting of 17.6% nuclear, 7.1% gas, 5.2% coal, and 2.6% hydro.

 

Natural Gas Supply

 

SCE requires natural gas 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 and SCE’s four peaker plants. All of the physical gas purchased by SCE in 2008 was purchased, after competitive bidding, 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.

 

In 2007, SCE secured a one-year natural gas storage capacity contract with Southern California Gas Company for the 2007/2008 storage season. Storage capacity was secured to provide operational flexibility and to mitigate potential costs associated with the dispatch of facilities that had tolling agreements with SCE.

 

 

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

 

On January 1, 2005, SCE and the other Four Corners participants entered into a Restated and Amended Four Corners Fuel Agreement with the BHP Navajo Coal Company under which coal will be supplied to Four Corners Units 4 and 5 until July 6, 2016. The Restated and Amended Agreement contains an option to extend for not less than five additional years or more than 15 years.

 

SCE has property and casualty insurance policies, which include excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations. SCE believes that its insurance policies are appropriate in light of its past claims experience. However, no assurance can be given that SCE’s

insurance will be adequate to cover all losses. See “SCE: Other Developments — Wildfire Insurance Issues” in the MD&A for further discussion.

 

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.

 

SCE is subject to environmental regulation by federal, state and local authorities in the jurisdictions in which it operates. 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. For general information regarding the environmental laws and regulations that impact SCE, see “Business of Edison International — Environmental Matters Affecting Edison International.”

 

Climate Change

 

SCE will continue to monitor federal, regional, and state developments relating to climate change to determine their impact on its operations. Programs to reduce GHG emissions could significantly increase the cost of generating electricity from fossil fuels, especially coal, as well as the cost of purchased power. Any such cost increases should generally be borne by customers.

 

SCE is evaluating the CARB’s reporting regulations required by AB 32 to assess the total cost of compliance. SCE believes that all of its facilities in California meet the GHG emissions performance standard contemplated by SB 1368, but will continue to monitor the implementing regulations, as they are developed, for potential impact on existing facilities and projects under development. Due to the restrictions that the SB 1368 EPS places upon financial commitments with coal-fired facilities, SCE has filed a Petition for Modification of the EPS adopted by the CPUC in which it seeks clarification of the applicability of the EPS to its existing ownership of Four Corners. Information regarding current developments on climate change and climate change regulation appears in the MD&A under the heading “Other Developments — Environmental Matters — Climate Change.”

 

Air Quality Regulation

 

Ambient Air Quality Standards

 

US EPA’s 2006 fine particulate standard significantly expanded the number of regions within SCE’s service territory (i.e., the Mohave Desert region, San Bernardino and Riverside County areas) that now have non-attainment status and will require local air quality agencies to identify particulate emissions reductions from existing sources, as well as requiring fine particulate emission offsets when new or modified sources undergo New Source Review permitting.

 

SCE believes its Mountainview plant and four peaker plants, which are located in the SCAQMD, are in full compliance with the Best Available Control Technology, also referred to as BACT, and no further emissions reductions are being contemplated from these sources. Additionally, Four Corners is located in an area that meets or exceeds all of the National Ambient Air Quality Standards and has a Federal Implementation Plan in place that is intended to ensure that such standards continue to be met.

 

Regional Haze

 

Four Corners is awaiting a final determination on its BART analysis from the US EPA’s regional office. Until such determination is received, SCE is unable to estimate the required expenditures or potential regulatory recovery of those expenditures. See “Other Developments — Environmental Matters — Air Quality Regulation — Regional Haze — New Mexico” in the MD&A for further discussion.

Hazardous Substances and Hazardous Waste Laws

 

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 laws and regulations. Through an incentive mechanism, the CPUC allows SCE to recover in retail rates paid by its customers some of the environmental remediation costs at certain sites. Additional information about these laws and regulations appears in Note 6 of Notes to Consolidated Financial Statements.

 

Water Quality Regulation

 

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

 

The California State Water Resources Control Board is developing a draft state policy on ocean-based, once-through cooling. Further 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 — Prohibition on the Use of Ocean-Based Once-Through Cooling”

 

Electric and Magnetic Fields

 

In January 2006, the CPUC issued a 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.

 

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

 

EME is a holding company which operates primarily through its subsidiaries and affiliates which are engaged in the business of developing, acquiring, owning or leasing, operating, and selling energy and capacity from independent power production facilities. EME also conducts hedging and energy trading activities in power markets open to competition through EMMT, its subsidiary. EME is an indirect subsidiary of Edison International.

 

EME was formed in 1986 with two domestic operating power plants. EME’s subsidiaries or affiliates have typically been formed to own full or partial interests in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. EME’s operating projects primarily consist of coal-fired generating facilities, natural gas-fired generating facilities and wind farms. As of December 31, 2008, EME’s subsidiaries and affiliates owned or leased interests in 37 operating projects with an aggregate net physical capacity of 11,019 MW of which EME’s capacity pro rata share was 9,849 MW. At December 31, 2008, 3 wind projects with an EME capacity pro rata share totaling 223 MW of net generating capacity were under construction.

 

EME is in a capital intensive business and depends on access to the financial markets to fund capital expenditures, meet contractual obligations and support margin and collateral requirements. EME has expanded its business development activities to grow and diversify its existing portfolio of power projects, including building new power plants. In addition, EME has environmental compliance requirements and ongoing capital expenditures for its existing generation fleet. All of these activities require liquidity and access to capital markets at reasonable rates in the future.

 

Historically, investor-owned utilities and government-owned power agencies were the only producers of bulk electric power intended for sale to third parties in the United States. However, the United States electric industry, including companies engaged in providing generation, transmission, distribution and retail sales and service of electric power, has undergone significant deregulation over the last three decades, which has led to increased competition, especially in the generation sector. Most recently, through EPAct 2005, the U.S. Congress recognized that a significant market for electric power generated by independent power producers, such as EME, has developed in the United States and indicated that competitive wholesale electricity markets have become accepted as a fundamental aspect of the electricity industry.

 

As part of the developments discussed above, the FERC has encouraged the formation of ISOs and RTOs. In those areas where ISOs and RTOs have been formed, market participants have open access to transmission service typically at a system-wide rate. ISOs and RTOs may also operate real-time and day-ahead energy and ancillary service markets, which are governed by FERC-approved tariffs and market rules. The development of such organized markets into which independent power producers are able to sell has reduced their dependence on bilateral contracts with electric utilities. See further discussion of regulations under ‘” Regulation of EME — United States Federal Energy Regulation.”

 

In various regional markets, electricity market administrators have acknowledged that the markets for generating capacity do not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage new generating capacity to be constructed. Capacity auctions have been implemented in some markets, including PJM, to address this issue. This approach is currently expected to provide significant additional capacity revenues for independent power producers.

 

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 annual report, and the Homer City electric generating station located in Pennsylvania, which is referred to as the Homer City facilities in this annual report. The Illinois Plants and the

Homer City facilities sell power into PJM, an RTO which includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

 

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. It can also be affected by, among other things, market mitigation measures and energy market price caps.

 

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. For a discussion of legal challenges to the prices resulting from PJM’s capacity auctions, see “Regulatory Matters — PJM Matters — RPM Buyers’ Complaint.”

 

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

 

Sales may also be made from PJM into the MISO RTO, where there is a single rate for transmission access. The MISO, which commenced operation on April 1, 2005, includes all or parts of Illinois, Wisconsin, Indiana, Michigan, Ohio, and other states in the region. The MISO conducts a bilateral market and day-ahead and real-time markets based on locational marginal pricing similar to that of PJM.

 

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, investor-owned utilities and government-owned power agencies utilities, industrial companies, financial institutions, and other independent power producers. Some of EME’s competitors have a lower cost of capital than most independent power producers and, in the case of utilities, are often able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation without relying exclusively on market clearing prices to recover their investments. These companies may also have competitive advantages as a result of their scale and the location of their generation facilities.

 

Environmental regulations, particularly those that impose stringent state specific emission limits, could put EME’s coal-fired plants at a disadvantage compared with competing power plants operating in nearby states and subject only to federal emission limits. Potential future climate change regulations could also put EME’s coal-fired power plants at a disadvantage compared to both power plants utilizing other fuels and utilities that may be able to recover climate change compliance costs through rate mechanisms. In addition, EME’s ability to compete may be affected by governmental and regulatory activities designed to support the construction and operation of power generation facilities fueled by renewable energy sources.

Power Plants of EME

 

EME’s operating projects are located within the United States, except for the Doga project in Turkey. As of December 31, 2008, EME’s operations consisted of ownership or leasehold interests in the following operating projects:

 

 

 

 

 

 

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.

 

Renewable Projects

 

Wind Projects

 

EME has made significant investments in wind projects and plans to continue to do so over the next several years, subject to market conditions. Historically, wind projects have received federal subsidies in the form of production tax credits. Production tax credits for a ten-year period are available for new projects placed in service by December 31, 2012.

 

In seeking to find and invest in new wind projects, EME has entered into joint development agreements with third-party development companies that provide for funding by an EME subsidiary of development costs including through loans (referred to as development loans) and joint decision-making on key contractual agreements such as 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. In addition to joint development agreements, EME may purchase wind projects from third-party developers in various stages of development, construction or operation.

 

In general, EME funds development costs under joint development agreements through 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 to be 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.

 

As of December 31, 2008, EME had a development pipeline of potential wind projects with a projected installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development of a wind project may take a number of years due to factors that include local permit requirements, and availability and prices of equipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits and agreements necessary to support an investment.

There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed.

 

See “Edison Mission Group — EMG: Liquidity — Capital Expenditures — Expenditures for New Projects” and “Commitments, Guarantees and Indemnities — Turbine Commitments” in the MD&A for further discussion.

 

Solar Projects

 

During 2008, EME submitted bids in competitive solicitations to supply power from solar projects under development in the southwestern United States. Initial site and equipment selection have been completed along with preliminary economic feasibility studies. Further project development activities are underway to obtain transmission interconnection, site control, and construction costs estimates, and to negotiate power sales agreements. To support development activities, EME entered into an agreement with First Solar Electric, LLC to provide design, engineering, procurement, and construction services for solar projects for identified customers, subject to the satisfaction of certain contingencies and entering into definitive agreements for such services for each project.

 

Thermal Projects

 

During the first quarter of 2008, a subsidiary of EME was awarded by SCE, through a competitive bidding process, a ten-year power sales contract for the output of a 479 MW gas-fired peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. Deliveries under the power sales agreement are scheduled to commence in 2013. During the fourth quarter of 2008, EME and its subsidiary terminated a turbine supply agreement for the project to preserve capital and recorded a pre-tax charge of $23 million ($14 million, after tax). EME plans to purchase turbines for the project subject to resolution of uncertainty regarding the availability of required emission credits. For further discussion of the status of this project, see “Other Developments — Environmental Matters — Priority Reserve Legal Challenges” in the MD&A.

 

During 2004 and early 2005, EME sold assets totaling 6,452 MW, which constituted most of its international assets. Except for the Doga project, which was not sold, these international assets are accounted for as discontinued operations in accordance with SFAS No. 144 and, accordingly, all prior periods have been restated to reclassify the results of operations and assets and liabilities as discontinued operations. The sale of the international operations included:

 

 

See “Note 17 to the Consolidated Financial Statements.

 

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, EME contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with re-contracting the product at a price different from the original contracted price if the non-performing counterparty were unable to pay the resulting 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 a counterparty defaulted.

 

To manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that EME would expect to incur if a counterparty failed to perform pursuant to the terms of its contractual obligations. EME measures, monitors and mitigates credit risk to the extent possible. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other appropriate steps to limit or lower credit exposure.

 

EME has established processes to determine and monitor the creditworthiness of counterparties. EME manages the credit risk of its counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. A risk management committee regularly reviews the credit quality of EME’s counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

 

EME’s merchant operations expose it to commodity price risk. Commodity price risks are actively monitored by a risk management committee to ensure compliance with EME’s risk management policies. Policies are in place which define risk management processes, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by EME’s risk management committee. EME uses “gross margin at risk” to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions of the Illinois Plants, the Homer City facilities, and the merchant wind projects, and “value at risk” to identify, measure, monitor and control its overall risk exposure in respect of its trading positions. The use of these measures allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify risk factors. Value at risk measures the possible loss, and gross margin at risk measures the potential change in value, of an asset or position, in each case over a given time interval, under normal market

conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss triggers and 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.” See “Item 1A. Risk Factors — Risks Relating to EMG.”

 

In the past three fiscal years, EME’s merchant plants sold electric power generally into the PJM market by participating in PJM’s capacity and energy markets or by selling capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 50%, 51% and 58% of EME’s consolidated operating revenues for the years ended December 31, 2008, 2007 and 2006, respectively. Beginning in January 2007, EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Illinois Plants to Commonwealth Edison under load requirements services contracts. Sales under these contracts accounted for 12% and 19% of EME’s consolidated operating revenues for the years ended December 31, 2008 and 2007, respectively. For the year ended December 31, 2008, a third customer, Constellation Energy Commodities Group, Inc. accounted for 10% of EME’s consolidated operating revenues. Sales to Constellation are primarily generated from EME’s merchant plants and largely consist of energy sales under forward contracts.

 

EME maintains insurance policies consistent with those normally carried by companies engaged in similar business 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 sublimits. 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.

 

The EME Homer City property insurance program currently covers losses up to $1.325 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 will permit it to maintain its current insurance coverage through June 1, 2009.

 

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 — 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.

 

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 development, ownership and operation of its projects, and the use of electric energy, capacity and related products, including ancillary services from its projects. In addition, EME is subject to the market rules, procedures, and protocols of the markets in which it participates.

 

The laws and regulations that affect EME and its operations are in a state of flux. Complex 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 if a project 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 wholesale sales and interstate transmission of electric energy (other than transmission that is “bundled” with retail sales) under the FPA and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The enactment of PURPA and the adoption of regulations under PURPA 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 FPA and PUHCA 1935 for the owners of qualifying facilities. Independent power production has been further encouraged by the passage of the Energy Policy Act in 1992, which provided additional exemptions from PUHCA 1935 for EWGs and foreign utility companies, and the EPAct of 2005, which included provisions for the repeal of PUHCA 1935, amendments to PURPA, merger review reform, the introduction of new regulations regarding transmission operation improvements, FERC authority to impose civil penalties for violation of its regulations, transmission rate reform, incentives for various generation technologies and the extension of production tax credits for wind and other specified types of generation.

 

Federal Power Act

 

The FPA 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 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 FPA. EWGs certified in accordance with the FERC’s rules under PUHCA 2005 are subject to

the FPA and to the FERC’s ratemaking jurisdiction thereunder, but the FERC typically grants EWGs the authority to sell power at market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. As of December 31, 2008, EME’s power marketing subsidiaries, including EMMT, and a number of EME’s operating projects, including the Homer City facilities and the Illinois Plants, were authorized by the FERC to make wholesale market sales of power at market-based rates and were subject to the FERC ratemaking regulation under the FPA. EME’s future domestic non-qualifying facility independent power projects will also be subject to the FERC jurisdiction on rates.

 

The FPA also grants the FERC jurisdiction over the sale or transfer of specified assets, including wholesale power sales contracts and generation facilities, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. Dispositions of EME’s jurisdictional assets or certain types of financing arrangements may require FERC approval.

 

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 FPA and regulations of the FERC thereunder. Second, the FERC regulations promulgated under PURPA required 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 has determined 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 permitted qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility’s avoided costs.

 

Several of EME’s projects, including the Big 4 projects, the Westside projects, American Bituminous, and March Point, are qualifying cogeneration facilities. To be a qualifying cogeneration facility, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility’s total energy output, and must meet certain efficiency standards. If one of the projects in which EME has an interest were to lose its qualifying facility status, 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 FPA 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 refund claims from utility customers, 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, it might not be possible to recover the costs incurred in connection with the project through sales to other purchasers. 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.

 

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 FPA.

 

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.

Illinois Power Procurement

 

The Illinois Power Agency Act, signed into law on August 28, 2007, establishes a new process for Commonwealth Edison and the Ameren Illinois utilities to procure power for their bundled-rate customers. On July 1, 2008, the two utilities began procuring power for bundled-rate customers by means of existing full requirements contracts that have not yet expired, certain multi-year swap contracts that they entered into with their affiliates pursuant to the Illinois Power Agency Act, and a competitive request for proposal procurement of standard wholesale power products run by independent procurement administrators with the oversight and approval of the Illinois Commerce Commission. The Illinois Power Agency Act provides further that starting in June 2009, a newly created Illinois Power Agency will be responsible for the administration, planning and procurement of power for Commonwealth Edison and the Ameren Illinois utilities’ bundled-rate customers using a portfolio-managed approach that is to include competitively procured standard wholesale products and renewable energy resources. The Illinois Commerce Commission will continue in its role of oversight and approval of the power planning and procurement for bundled retail customers of the utilities.

 

On January 7, 2009, the Illinois Commerce Commission approved a procurement plan for 2009 that was proposed by the Illinois Power Agency. The plan, which is based on five-year demand forecasts, proposes a laddered procurement strategy for the period beginning in 2009 and ending in 2014. In 2009, the Illinois Power Agency is expected to acquire through a single request for proposals roughly one third of the forecasted demand for bundled load for Commonwealth Edison and Ameren. Renewable requirements, in the first year, will be purchased by way of one-year renewable energy credits; longer contracts may be included in future procurements if required by law or if approved by the Illinois Commerce Commission. The Illinois Power Agency issued its request for proposals in February 2009 and plans to conduct its procurement between mid-March and mid-April 2009.

 

PJM Matters

 

On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-term pricing signal for capacity resources. The RPM provides a mechanism for PJM to satisfy the region’s need for generation capacity, the cost of which is allocated to load-serving entities through a locational reliability charge. Also on June 1, 2007, PJM implemented marginal losses for transmission for its competitive wholesale electric market. For further discussion regarding the RPM and recent auctions, see “EMG: Market Risk Exposures — Commodity Price Risk — Capacity Price Risk” in the MD&A.

 

RPM Buyers’ Complaint

 

On May 30, 2008, a group of entities referring to themselves as the “RPM Buyers” filed a complaint at the FERC asking that PJM’s RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust and unreasonable capacity prices.

 

On September 19, 2008, the FERC dismissed the RPM Buyers’ complaint, finding that the RPM Buyers had failed to allege or prove that any party violated PJM’s tariff and market rules, and that the prices determined during the transition period were determined in accordance with PJM’s FERC-approved tariff. On October 20, 2008, the RPM Buyers requested rehearing of the FERC’s order dismissing their complaint. This matter is currently pending before the FERC. EME cannot predict the outcome of this matter.

 

RPM CONE

 

On December 12, 2008, PJM submitted revised RPM Tariff sheets pursuant to Section 205 of the FPA, proposing RPM auction modifications (relating to CONE) values, including a proposal to modify how scarcity pricing revenues are incorporated in the Net Energy and Ancillary Services Revenue Offset, new rules for participation of demand side management resources in the RPM auctions, and a proposed holdback of 2.5% of the reliability requirement from the Base Residual Auction. The CONE is used to construct the demand curve for RPM auctions, and its level affects the clearing price for those auctions (which is determined at the intersection of the supply and demand curves).

On February 9, 2009, PJM and several other parties to the proceedings filed a proposed settlement with the FERC with a proposed effective date of March 27, 2009. The CONE values in the proposed settlement represent a 10% decrease from those contained in PJM’s December 12, 2008 filing. The proposed settlement would retain the 2.5% holdback proposed in PJM’s December 12 filing and would increase the length of forward commitment for new capacity resources to seven years, instead of the five years originally proposed by PJM.

 

There was a high level of opposition to PJM’s proposed modifications from buyers and consumers, and a similarly high level of opposition is expected with respect to the proposed settlement. The effect of the FERC’s actions on future RPM auctions cannot be determined at this time. The CONE as proposed for the May 2009 RPM auction for the 2012/2013 delivery year is higher than what is currently effective in the tariff.

 

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 that would impose additional costs or charges for the emission of CO ₂ could have a materially adverse effect on EME. EME will continue to monitor the federal, regional and state developments relating to regulation of GHG emissions to determine their impact on its operations. Requirements to reduce emissions of CO ₂ and other GHG emissions could significantly increase the cost of generating electricity from fossil fuels, especially coal, as well as the cost of purchased power.

 

Utility purchasers of power generated by EME’s power plants in California are subject to the EPS requirements of SB 1368. At this time, EME believes that all of its facilities in California meet the GHG EPS contemplated by SB1368, but will continue to monitor the regulations, as they are developed, for potential impact on existing facilities and projects under development.

 

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 is expected to 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 Interstate Rule

 

EME expects that compliance with the CAIR and the regulations and revised SIPs developed as a consequence of the CAIR will result in increased capital expenditures and operating expenses. EME’s approach to meeting these obligations will consist of a blending of capital expenditure and emission allowance purchases that will be based on an ongoing assessment of the dynamics of its market conditions.

 

Illinois

 

On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NO _x and SO ₂ emissions at the Illinois Plants. The agreement has been embodied in an Illinois rule called the Combined Pollutant Standard or CPS. All of Midwest Generation’s Illinois coal-fired electric generating units are subject to the CPS. For further discussion of the CPS, see information under the heading “Other Developments — Environmental Matters — Air Quality Regulation — Clean Air Interstate Rule — Illinois” in the MD&A.

Pennsylvania

 

On December 18, 2007, the Pennsylvania Environmental Quality Board approved the Pennsylvania CAIR. This rule has been submitted to the US EPA for approval as part of the Pennsylvania SIP. The Pennsylvania CAIR is substantively similar to the CAIR. EME Homer City will be subject to the federal CAIR rule during 2009 and expects to be able to comply with the NO _x requirement using its existing SCR system. The Pennsylvania CAIR, including both NO _x and SO ₂ limits, is expected to become effective in 2010. EME Homer City expects to comply with Pennsylvania CAIR through the continued operation of its scrubber on Unit 3 to reduce SO ₂ emissions and the purchase of SO ₂ allowances.

 

Clean Air Mercury Rule

 

EME’s coal-fired electric generating facilities are already subject to significant unit-specific mercury emission reduction requirements under Illinois and Pennsylvania law. As discussed in the MD&A, under the heading “Other Developments — Environmental Matters — Air Quality Regulation — Clean Air Mercury Rule,” in February 2008, the D.C. Circuit Court vacated the CAMR and in February 2009, the U.S. Supreme Court declined to review the D.C. Circuit’s decision. Until CAMR is replaced by a new mercury rule, mercury regulation will come from state regulatory bodies. As described below, EME’s coal-fired electric generating facilities are already subject to significant unit-specific mercury emission reduction requirements under Illinois and Pennsylvania law (although, as noted below, a Pennsylvania court has recently invalidated Pennsylvania’s mercury regulations). Until new federal standards are developed, EME will not be able to determine whether it will be necessary to undertake measures beyond those required by state regulations.

 

Illinois

 

The final state rule for the reduction of mercury emissions in Illinois was adopted and became effective on December 21, 2006. The rule requires a 90% reduction of mercury emissions from coal-fired power plants averaged across company-owned Illinois stations and a minimum reduction of 75% for individual generating sources by July 1, 2009. The rule requires each station to achieve a 90% reduction by January 1, 2014 and, because emissions are measured on a rolling 12-month average, stations must install equipment necessary to meet the January 1, 2014, 90% reduction by January 1, 2013.

 

On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NOX and SO ₂ emissions at the Illinois Plants. The agreement has been embodied in an Illinois rule called the CPS. Midwest Generation’s compliance with the CPS supersedes the mercury rule described above for the Illinois Plants. The principal emission standards and control technology requirements for mercury under the CPS are as described below:

 

Beginning in calendar year 2015, and continuing thereafter on a rolling 12-month basis, Midwest Generation must either achieve an emission standard of .008 lbs mercury/GWh gross electrical output or a minimum 90% reduction in mercury for each unit (except Unit 3 at the Will County Station, which shall be included in calendar year 2016). In addition to these standards, Midwest Generation must install and operate the following specific control technologies:

 

 

Midwest Generation has installed activated carbon injection technology for the removal of mercury in 2008 for Crawford, Fisk and Waukegan Stations and is in the process of installing this technology in 2009 for Joliet, Powerton and Will County Stations. Capital expenditures relating to these controls were $37 million through 2008 and are expected to be $6 million in 2009.

Pennsylvania

 

On February 17, 2007, the PADEP published in the Pennsylvania Bulletin regulations that would require coal-fired power plants to reduce mercury emissions by 80% by 2010 and 90% by 2015. The rule does not allow the use of emissions trading to achieve compliance. The rule became final upon publication. The Pennsylvania CAMR SIP, which embodies PADEP’s mercury regulation, was pending approval by the US EPA prior to the February 8, 2008 Court of Appeals decision vacating the federal CAMR. On September 15, 2008, PPL Generation filed a Petition for Review with the Commonwealth Court seeking relief from Pennsylvania’s mercury rule for coal-fired power plants, alleging that the PADEP cannot regulate power plant emission sources under Section 111 of the CAA, but must instead consider emission controls on a case-by-case basis as required by Section 112. On January 30, 2009, the Court issued an opinion declaring Pennsylvania’s mercury rule unlawful, invalid and unenforceable, and enjoining Pennsylvania from continued implementation and enforcement of the rule. The PADEP has appealed this matter to the Pennsylvania Supreme Court. EME cannot predict the outcome of this matter.

 

If the Homer City facilities are required to meet the 2010 deadline for mercury emissions reductions, EME Homer City would plan to achieve compliance by operating an existing FGD system on one generating unit and utilizing an appropriate combination of sorbent injection and coal washing on the other two units. In order to meet reductions in emissions by the 2015 deadline, it is likely that additional environmental control equipment will need to be installed. If additional environmental equipment is required in the form of FGD equipment, EME would need to make commitments during 2011 or 2012. EME continues to study available environmental control technologies and estimated costs to reduce SO ₂ and mercury and to monitor developments related to mercury and other environmental regulations.

 

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. 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 as originally proposed but the 24-hour fine particulate standard is significantly more stringent. On February 24, 2009, the U.S. Court of Appeals for the D.C. Circuit remanded the annual fine particulate matter standard to the US EPA for review. The more stringent 24-hour fine particulate standard (and, depending on the course of the remand, a further revised annual standard) may require states to impose further emission reductions beyond those necessary to meet the existing standards. Edison International anticipates that any such further emission 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.

 

On March 12, 2008, the US EPA issued a final rule to make revisions in the primary and secondary national ambient air quality standards for ozone. With regard to the primary and standards for ozone, US EPA reduced the level of the 8-hour standard to 0.075 parts per million (ppm). The US EPA solicited comment on alternative levels down to 0.060 ppm and up to and including retaining the current 8-hour standard of 0.080 ppm (effectively 0.084 ppm using current data rounding conventions). The rule may require states to impose further emission reductions beyond those necessary to meet the existing standards, Edison International anticipates that any such further emission 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 /MMBtu of heat input. This limitation is commonly referred to as the East St. Louis State Implementation Plan. 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.

 

The Illinois Plants have complied with the NO _x regulations by installing advanced burner technology and by purchasing additional allowances. Midwest Generation plans to continue to purchase allowances as it implements the agreement it reached with the Illinois EPA, but expects to purchase fewer allowances as the required technology improvements are implemented.

 

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. The SIP for 8-hour ozone was to be submitted to the US EPA by June 15, 2007, but is currently expected to be submitted in early 2009. The SIP for fine particulates was to be submitted to the US EPA by April 5, 2008, but is currently expected to be submitted in 2010.

 

The CPS requires Midwest Generation to install air pollution controls that will contribute to attainment with the ozone and fine particulate matter per National Ambient Air Quality Standards. Edison International does not know at this time whether the reductions required by the CPS will be sufficient for compliance with future ozone and particulate matter regulations. See “— Clean Air Interstate Rule — Illinois” for further discussion.

 

Pennsylvania

 

In June 2007, the PADEP requested a redesignation of Clearfield and Indiana counties to attainment with respect to the 8-hour ozone standard. The PADEP also submitted a maintenance plan indicating that the existing (and upcoming) regulations controlling emissions of volatile organic compounds and NO _x will result in continued compliance with the 8-hour ozone standard. Accordingly, Edison International believes that the Homer City facilities will likely not need to install additional pollution control as a result of the 8-hour ozone standard.

 

With respect to fine particulates, Pennsylvania has not proposed new regulations to achieve compliance with the National Ambient Air Quality Standard for fine particulates. The SIP with respect to this standard was due to the US EPA by April 5, 2008, but has not been submitted. Edison International is unable to predict the timing of the SIP or its potential effect on the Homer City facilities.

 

Hazardous Substances and Hazardous Waste Laws

 

With respect to EME’s potential liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, EME accrues a liability to the extent the costs are probable and can be reasonably estimated. Midwest Generation has accrued approximately $4 million at December 31, 2008 for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites, the scope of work and the estimated costs for investigation and/or remediation where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements of federal, state, or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination discovered at the sites that requires remediation. Given the prior history of the operations at its facilities, EME cannot be certain that the existence or extent of all contamination at its sites has been fully identified. However, based on available information, management believes that future costs in excess of the amounts disclosed on all known and quantifiable environmental contingencies will not be material to EME’s financial position.

 

Water Quality Regulation

 

Clean Water Act — Cooling Water Standards and Regulations

 

EME has collected impingement and entrainment data at its potentially affected Midwest Generation facilities in Illinois to begin the process of determining what corrective actions might need to be taken under the

previous rule. Because there are no defined compliance targets absent a new rule, EME is currently in the process of generally reviewing a wide range of possible control technologies. Although the rule to be generated in the new rulemaking process could have a material impact on EME’s operations, until the final compliance criteria have been published, EME cannot reasonably determine the financial impact.

 

Illinois Effluent Water Quality Standards

 

The Illinois EPA is considering the adoption of a rule that would impose stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des Plaines River. Midwest Generation’s Fisk, Crawford, Joliet and Will County stations all use water from the affected waterways for cooling purposes and the rule, if implemented, is expected to affect the manner in with those stations use water for station cooling. See “Other Developments — Environmental Matters — Water Quality Regulation — State Water Quality Standards — Illinois” in the MD&A for more information.

 

Coal Combustion Wastes

 

US EPA regulations currently classify coal combustion wastes as solid wastes that are exempt from hazardous waste requirements under what is known as the Bevill Amendment. The exemption applies to fly ash, bottom, slag, and flue gas emission control wastes generated from the combustion of coal or other fossil fuels. The US EPA has studied coal combustion wastes extensively and in 2000 concluded that fossil fuel combustions wastes do not warrant regulation as a hazardous waste under Subtitle C of the Resource Conservation and Recovery Act. However, the US EPA also concluded, in 2000 and again in a 2007 Notice of Data Availability and request for public comment, that coal combustion wastes disposed of in surface impoundments and landfills, or used for minefill, do require regulation under Subtitle D (as solid wastes) under the Resource Conservation and Recovery Act. The current classification of coal combustion wastes as exempt from hazardous waste requirements enables beneficial uses of coal combustion wastes, such as for cement production and fill materials. The Illinois Plants currently sell a significant portion of their coal combustion wastes for beneficial uses.

 

Legislation has been introduced in the U.S. House of Representatives and the US EPA is reviewing options for regulation of coal ash. The US EPA and many state regulatory agencies, including the Illinois EPA and the PADEP, are reviewing existing ash storage and disposal units and the adequacy of existing regulatory standards. EME is monitoring state legislative and regulatory activity, specifically in Illinois, Pennsylvania and West Virginia, but cannot predict the outcome of this activity.

 

Additional regulation of the storage, disposal, and beneficial uses of coal combustion wastes would affect the costs and the manner in which EME conducts its business, and would likely require EME to make additional capital expenditures with no assurance that the increased costs could be recovered from customers.

 

At December 31, 2008, EME and its subsidiaries employed 1,889 people, including:

 

 

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, EMG. The projects were then contributed to EME. During the first half of 2006, Edison Capital made a dividend of its remaining wind projects to EMG, 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.

 

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.

 

 

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, 2008, in the aggregate at approximately $1.5 billion against $2.5 billion invested in leveraged leases. The lenders have a priority lien against the assets but the loans are 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 December 31, 2008, Edison Capital had an investment balance of $12 million in the Latin America fund, $2 million in the Asia fund, and $19 million in the emerging Europe fund. As of December 31, 2008, 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.

 

At December 31, 2008, Edison Capital had a net investment of $7 million in approximately 313 affordable housing projects with approximately 25,000 units rented to qualifying low-income tenants in 35 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 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 2008, Edison Capital had not experienced any significant recapture of tax credits from its affordable housing projects.

 

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.”

 

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 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. Financial market and economic conditions may have an adverse effect on Edison International’s subsidiaries. See “Risks Relating to SCE” and “Risks Relating to EME” below for further discussion.

 

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. Edison International is currently engaged in attempts to settle such challenges, but if it is unable to do so on acceptable terms and 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.

 

Edison International’s subsidiaries are subject to extensive environmental regulations that may involve significant and increasing costs and adversely affect them.

 

Edison International’s subsidiaries are subject to extensive environmental regulation and permitting requirements that involve significant and increasing costs. SCE and EMG devote significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with existing and anticipated environmental regulatory requirements. However, the current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. The U.S. Congress is deliberating over competing proposals to regulate GHG emissions. In addition, the attorneys general of several states, including California, certain environmental advocacy groups, and numerous state regulatory agencies in the United States have been focusing considerable attention on GHG emissions from coal-fired power plants and their potential role in climate change. The adoption of laws and regulations to implement GHG controls could adversely affect operations, particularly of the coal-fired plants. The continued operation of SCE and EMG facilities, particularly the coal-fired facilities, may require substantial capital expenditures for environmental controls. 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 these subsidiaries conduct business. Current and future state laws and regulations in California could increase

the required amount of power that must be procured from renewable resources. Furthermore, changing environmental regulations could make some units uneconomical to maintain or operate. If the affected subsidiaries cannot comply with all applicable regulations, they could be required to retire or suspend operations at such facilities, or to restrict or modify the operations of these facilities, and their business, results of operations and financial condition could be adversely affected.

 

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 would be materially adversely affected.

 

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, many of whom may be adversely affected by the current conditions in the financial markets. 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.

 

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 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.

 

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

 

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection which is currently approximately $12.5 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 above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further revenue. If this were to occur, 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. There can be no assurance of SCE’s ability to recover uninsured costs in the event federal appropriations are insufficient.

SCE’s financial condition and results of operations could be materially adversely affected if it is unable to successfully manage the risks inherent in operating and improving its facilities.

 

SCE owns and operates extensive electricity facilities that are interconnected to the United States western electricity grid. SCE is also undertaking large-scale new infrastructure construction. The construction of infrastructure involves numerous risks, including risks related to permitting, governmental approvals, and construction delays. 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 and liabilities, 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.

 

The global financial crisis may have a material adverse impact on EME’s access to capital necessary to fund contractual obligations and the ability of EME’s counterparties to perform their contractual obligations.

 

Financial market and economic conditions have had, and may continue to have, an adverse effect on EME’s business and financial condition. The capital markets were not available to EME during the fourth quarter of 2008, and market uncertainty has continued into 2009. EME’s ability to raise capital has been, and could continue to be, adversely affected by volatile and unpredictable global market and economic conditions. Even after the capital markets recover, recent disruptions in the credit markets may have lasting effects on the availability of credit, cost of borrowing, and terms and conditions of new borrowings.

 

In September 2008, Lehman Commercial Paper Inc., a lender in EME’s credit agreement representing a commitment of $36 million, declined requests for funding under that agreement. Thereafter, in October 2008, it filed for bankruptcy protection. While the Lehman Commercial Paper bankruptcy is not expected to have a material adverse effect on EME, the situation may worsen if other lenders under the credit agreement file for bankruptcy or otherwise fail to perform their obligations.

Liquidity is essential to EME’s business. 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. Lack of available capital may affect EME’s ability to complete environmental improvements of the Illinois Plants as prescribed by the CPS, which could lead to the eventual shutdown of a material part of the Illinois Plants. Lack of available capital could also affect EME’s ability to complete the development of sites for renewable projects deploying current turbine commitments, which could lead to postponement or cancellation of the turbine commitments subject to the provisions of the related contracts. In addition to the potential effect on EME’s liquidity, the global financial crisis could have a negative effect on the markets in which EME and its subsidiaries sell power, purchase fuel and perform other trading and marketing activities. In recent years, global financial institutions have been active participants in such markets. As such financial institutions consolidate and operate under more restrictive capital constraints in response to the financial crisis, there could be less liquidity in the energy and commodity markets, which could have a negative effect on EME’s ability to hedge and transact with creditworthy counterparties. In addition, EME is exposed to the risk that its counterparties, including customers, suppliers and business partners, may fail to perform according to the terms of their contractual arrangements. Deterioration in the financial condition of EME’s counterparties as a result of the global financial crisis, and the resulting failure to pay amounts owed or to perform obligations in excess of posted collateral, could have a negative effect on EME’s business and financial condition.

 

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 price 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 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.

 

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.

 

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 the effect that risk management decisions may have on its businesses, operating results or financial position.

 

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 solar) 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.

In support of its development activities, EME has entered into commitments to purchase wind turbines for future projects and may 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.

 

Historically, wind projects have received federal subsidies in the form of production tax credits. Currently, production tax credits are available for new wind projects placed in service by December 31, 2012. If the deadline for production tax credits is not extended again, EME’s development activities related to wind projects slated for completion after December 31, 2012, could be adversely affected.

 

EME’s development activities are subject to risks including, without limitation, risks related to project siting, financing, construction, permitting, governmental approvals and the negotiation of project agreements, including power-purchase agreements. Moreover, recent economic conditions may affect the willingness of local utilities to enter into new power-purchase agreements due to uncertainties over future load requirements, among other factors. As a result of these risks, EME may not be successful in developing new projects or the timing of such development may be delayed beyond the date that turbines are ready for installation. Projects under development may be adversely affected by delays in turbine deliveries or start-up problems related to turbine performance. 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 cancel turbine orders, or sell turbines that were purchased and such cancellation and/or sales may result in substantial losses.

 

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 EME will ultimately realize a satisfactory rate of return.

 

A substantial portion of wind turbines purchased by EME may not perform as expected during start-up or operations, thereby adversely affecting the expected return on investment.

 

EME has purchased a significant number of wind turbines in support of its renewable energy activities. The turbines of one turbine manufacturer have experienced rotor blade cracks, and the turbines of another turbine manufacturer have also experienced blade problems. EME cannot provide assurance that repairs or replacements of the affected turbines will be timely or effective or that expected performance levels will be achieved. Significant delays in meeting commercial operation deadlines and/or reductions in project output could subject projects to damages under their power purchase agreements and, potentially, the risk of termination under some agreements. Turbine problems have also impacted EME’s ability to secure project financing for these projects. EME cannot predict at this time the amount of damages that will be recovered by EME from the turbine suppliers. Furthermore, limited data is presently available regarding the performance of new wind turbines of a size over 2 MW over an extended period of time. Accordingly, EME cannot provide assurance that it will earn its expected return over the life of the projects.

 

Competition could adversely affect EME’s business.

 

The independent power industry is characterized by numerous capable competitors, some of whom may have more extensive 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 merchant 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 larger competitors, as well as new market entrants. In addition, 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.

 

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 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, guarantees 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.

 

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 regulations with respect to, among other things, air quality, water quality, waste disposal, and noise. EME is required to obtain, and comply with 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. See “— Risks relating to Edison International — Edison International’s subsidiaries are subject to extensive environmental regulations that may involve significant and increasing costs and adversely affect them” above for additional discussion of environmental regulation risks.

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

 

As of December 31, 2007, EME’s consolidated debt was $3.8 billion. In addition, EME’s subsidiaries have $3.9 billion of long-term power plant lease obligations that are due over a period ranging up to 27 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 or to plan for and react to business and industry changes. 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 (including environmental improvements required by the CPS, which could in turn lead to unit shutdowns), 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.

 

In addition, in connection with the entry into new financings or amendments to existing financing arrangements, EME’s 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.

 

Restrictions in the instruments governing EME’s indebtedness and the indebtedness and lease obligations of its subsidiaries limit EME’s and its subsidiaries’ ability to enter into specified transactions that EME or they otherwise may enter into.

 

The instruments governing EME’s indebtedness and the indebtedness of its subsidiaries contain financial and investment covenants. Restrictions contained in these documents or documents EME or its subsidiaries enter in the future could affect, and in some cases significantly limit or prohibit, EME’s ability and the ability of its subsidiaries 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 EME’s ability and the ability of its subsidiaries to take advantage of business opportunities as they arise, to grow its business or to compete effectively. In addition, these restrictions may significantly impede the ability of EME’s subsidiaries to make distributions to EME.

 

The creditworthiness of EME’s customers, suppliers, transporters and other business partners could affect EME’s business and operations.

 

EME is exposed to risks associated with the creditworthiness of its key customers, suppliers and business partners, many of whom may be adversely affected by the current conditions in the financial markets. Deterioration in the financial condition of EME’s counterparties increases the possibility that EME may incur losses from the failure of counterparties to perform according to the terms of their contractual arrangements.

 

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

 

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 emission 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 will at times be volatile and subject to fluctuations in value primarily due to changes in electricity prices.

 

 

Staff, they had at times failed to provide complete and accurate information in response to FERC Staff inquiries, as required by FERC’s regulation (18 CFR § 35.41(b) (2007)). The settlement agreement required the payment of $7 million in civil penalties for violation of 18 CFR § 35.41(b) (2007) and development and implementation of a comprehensive regulatory compliance program at an estimated cost of $2 million. The order and settlement agreement operate to terminate the investigation with no assertion of findings of violation of FERC’s rules with respect to the bidding practices that were the subject of the investigation.

 

On June 18 and 19, 2008, various parties, including the Attorney General of the State of Illinois and a number of state regulatory agencies filed various motions and protests seeking to intervene in the FERC investigation docket for the purpose of seeking clarification that the order and settlement agreement did not foreclose third party rights to seek redress against EMMT, Midwest Generation and EME for any alleged market manipulation as a result of the bidding behavior or, in the alternative, obtaining an order reopening the investigation docket to allow further investigation into the bidding behavior. On October 7, 2008, the FERC issued an order denying the motions to intervene and dismissing the requests for rehearing and other relief. On December 8, 2008, the FERC denied the intervening parties’ further requests for rehearing.

 

Also on December 8, 2008, two of the intervening parties, filed an appeal with the United States Court of Appeals for the District of Columbia Circuit, appealing the FERC’s October 7, 2008 order denying intervention. The appellate case is pending and the outcome cannot be determined at this time.

 

Information about the potential environmental proceeding against Midwest Generation appears in the MD&A under the heading “EMG: Other Developments — Midwest Generation Potential Environmental Proceeding.”

 

Information about the SCE Navajo Nation litigation appears in the MD&A under the heading “SCE: Other Developments — Navajo Nation Litigation.”

 

 

As set forth in Article IV of Edison International’s Bylaws, the elected officers of Edison International are chosen annually by and serve at the pleasure of Edison International’s Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the officers of Edison International have been actively engaged in the business of Edison International, SCE, and/or the nonutility companies for more than five years, except for Mr. Adler, and have served in their present positions for the periods stated below. Additionally, those officers who have had other or additional principal positions in the past five years had the following business experience during that period:

 

 

 

 

 

As set forth in Article IV of SCE’s Bylaws, the elected officers of SCE are chosen annually by and serve at the pleasure of SCE’s Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the above officers of SCE have been actively engaged in the business of SCE, Edison International and/or the nonutility companies for more than five years and have served in their present positions for the periods stated below. Additionally,

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

 

 

 

As set forth in Article IV of their respective Bylaws, the elected officers of the nonutility companies are chosen annually by and serve at the pleasure of the respective Boards of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. The above officer of the nonutility companies has been actively engaged in the business of the respective nonutility companies, Edison International, and/or SCE for more than five years and has served in his present position for the period stated below. Additionally, the above officer who has had other or additional principal positions in the past five years, had the following business experience during that period:

 

PART II

 

 

 

 

 

 

 

PART III

 

 

 

 

 

See “Exhibit Index” beginning on page 62 of this report.

 

Edison International will furnish a copy of any exhibit listed in the accompanying Exhibit Index upon written request and upon payment to Edison International of its reasonable expenses of furnishing such exhibit, which shall be limited to photocopying charges and, if mailed to the requesting party, the cost of first-class postage.

Report of Independent Registered Public Accounting Firm on

 

Financial Statement Schedules

 

To the Board of Directors

of Edison International

 

 

Our audits of the consolidated financial statements and of the effectiveness of internal control over financial reporting referred to in our report dated March 2, 2009 appearing in the 2008 Annual Report to Shareholders of Edison International (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

 

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

 

March 2, 2009