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

 

FORM 10-K

 

 

Commission File Number 1-9936

 

 

EDISON INTERNATIONAL

(Exact name of registrant as specified in its charter)

 

 

 

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

 

 

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

 

 

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

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

 

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

 

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

 

Indicate by check mark 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 $12.7 billion on or about June 30, 2007, based upon prices reported on the New York Stock Exchange. As of February 22, 2008, 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, 2007

 

Part III     

 

(2) Designated portions of the Proxy Statement relating to registrant’s 2008 Annual Meeting of Shareholders

 

 

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, MEHC, 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.

GLOSSARY

 

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

 

 

Glossary (continued)

 

 

Glossary (continued)

 

PART I

 

 

Edison International was incorporated on April 20, 1987, under the laws of the State of California for the purpose of becoming the parent holding company of SCE, a California public utility corporation, and of nonutility companies. SCE comprises the largest portion of the assets and revenue of Edison International. The principal nonutility companies are: EME, which is an independent power producer engaged in the business of developing, acquiring, owning or leasing, and selling energy and capacity from independent power production facilities and also conducts price risk management and energy trading activities in power markets open to competition; and Edison Capital, which has investments in energy and infrastructure projects worldwide and in affordable housing projects located throughout the United States. Beginning in 2006, EME and Edison Capital have been presented on a consolidated basis as EMG in order to reflect the integration of management and personnel at EME and Edison Capital.

 

Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. At December 31, 2007, Edison International and its subsidiaries had an aggregate of 17,275 full-time employees, of which 26 were employed directly by Edison International.

 

The principal executive offices of Edison International are located at 2244 Walnut Grove Avenue, P.O. Box 976, Rosemead, California 91770, and the telephone number is (626) 302-2222.

 

Edison International’s internet website address is http://www.edisoninvestor.com. Edison International makes available, free of charge on its internet website, its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after Edison International electronically files such material with, or furnishes it to, the SEC. Such reports are also available on the SEC’s internet website at http://www.sec.gov. The information contained in our website, or connected to that site, is not incorporated by reference into this report.

 

Edison International has three business segments for financial reporting purposes: an electric utility operation segment (SCE), a nonutility power generation segment (EME), and a financial services provider segment (Edison Capital). Financial information about these segments and about geographic areas, for fiscal years 2007, 2006, and 2005, is contained in Note 16 of Notes to Consolidated Financial Statements and incorporated herein by this reference. Additional information about each of these business segments appears below under the headings “Business of Southern California Edison Company” and “Business of Edison Mission Group Inc.”

 

A comprehensive energy bill was enacted in August 2005. Known as “EPAct 2005,” this comprehensive legislation included provisions for the repeal of the Public Utility Holding Company Act (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 (originally through December 31, 2007, and subsequently extended through December 31, 2008) of production tax credits for wind and other specified types of generation. The FERC finalized rules to implement the Congressionally mandated repeal of PUHCA 1935 that became effective February 8, 2006, and the enactment of PUHCA 2005. PUHCA 2005 is primarily a “books and records access” statute and does not give the FERC any new substantive authority under the Federal Power Act or Natural Gas Act. The FERC also issued final rules to implement the electric company merger and acquisition provisions of EPAct 2005.

 

On July 20, 2006, the FERC certified the North American Electric Reliability Corporation (NERC) as its Electric Reliability Organization to establish and enforce reliability standards for the bulk power system. On March 16, 2007, the FERC issued a final rule approving 83 reliability standards proposed by the NERC. The

final 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. 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.

 

In 2006, the CPUC issued a decision relating to the relationship between SCE and Edison International. The most significant provisions of this decision were: (1) SCE must elect either to continue to share regulatory affairs, lobbying and legal services with its affiliates, or to share certain “key” officers with the holding company, including the Chairperson, CEO, President, CFO and the chief regulatory officer; (2) “key” officers (as listed in the preceding item) must personally certify annually that they have complied with the affiliate transaction rules and have no knowledge of any unreported violations; (3) the utility must obtain and deliver to the CPUC a nonconsolidation opinion from outside counsel demonstrating that the existing ring-fencing around the utility is sufficient to prevent the utility from being drawn into a bankruptcy of its parent holding company; (4) the utility must file a waiver application if an adverse financial event reduces the utility’s actual equity ratio by more than one percent or more below the approved ratio; (5) the utility must file an annual report on utility capital needs and related financial practices; and (6) changes to the executive compensation reporting rules to increase disclosure obligations and certify that compensation has been accurately reported. SCE elected to continue to share regulatory affairs, lobbying and legal services with its affiliates. As a result, in 2007 Edison International’s Chairman resigned his position as Chairman of SCE and SCE’s CEO was elected Chairman of SCE. SCE has also complied with the other applicable requirements of the decision.

 

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. 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 current session of the U.S. Congress that would reduce GHG emissions in the U.S. Enactment of climate change legislation within the next several years now seems likely. However, there is still significant uncertainty about the cost of complying with any future GHG emission reduction requirements. These costs will depend upon many factors, including the required levels of GHG emission reductions, the timing of those reductions, whether emission credits will be allocated with or without cost to existing generators, and whether flexible compliance mechanisms, such as a GHG offset program similar to those sanctioned under the CAA for conventional pollutants, will be part of the policy.

 

In most of the federal proposals to date, emission allowances would be allocated and distributed without cost in the early years of the emission reduction program, followed by decreasing free allocations and increasing auctions of allowances. While debate continues at the national level over domestic climate policy and the appropriate scope and terms of any federal legislation, many states are developing state-specific measures or participating in regional legislative initiatives to reduce GHG emissions.

 

Regional Legislative Initiatives

 

On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to create a regional initiative to establish a cap and trade GHG program for electric generators, referred to as the Regional Greenhouse Gas Initiative (RGGI). In August 2006, the participating states issued a model rule to be used as a basis for individual state legislative and regulatory action to implement the program. Pennsylvania is not a signatory to the RGGI, although it has participated as an observer of the process.

 

In February 2007, the Governors of Arizona, California, New Mexico, Oregon and Washington launched the Western Climate Initiative to develop regional strategies to address climate change. The Western Climate Initiative is identifying, evaluating and implementing collective and cooperative ways to reduce greenhouse

gases in the region. In the spring of 2007, the Governor of Utah and the Premiers of British Columbia and Manitoba joined the Initiative. Other states and provinces have joined as observers. The Initiative partners set an overall regional goal in August 2007 for reducing GHG emissions to 15% below 2005 levels by 2020. By August 2008, the partners expect to complete the design of a market-based mechanism to help achieve that reduction goal.

 

On November 15, 2007, Illinois became a party to the Midwestern Accord, in which six Midwestern states, including Illinois, agreed to seek to develop regional GHG emission reduction goals within one year, and to develop a multi-sector cap-and-trade program to achieve these goals. The Accord called for such a program to be implemented in 30 months. On February 19, 2008, the six participating states announced that they will complete a model rule by the end of 2008 that will create the framework for the cap-and-trade program. Once this model rule has been drafted, each of the participating states could adopt the program through legislative action, executive order or other appropriate means. In February 2007, prior to the development of the Midwestern Accord, Illinois Governor Blagojevich announced a goal to reduce Illinois’ GHG emissions to 1990 levels by 2020 and to 60% below 1990 levels by 2050.

 

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. If state and/or regional initiatives are allowed to stand together with federal legislation, generators could be required to purchase allowances to satisfy their state and federal compliance obligations.

 

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 of regulatory and market mechanisms 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.

 

AB 32 also required the CARB to adopt regulations to require the reporting and verification of statewide GHG emissions on or before January 1, 2008. On December 6, 2007 the CARB approved regulations for the mandatory reporting of GHG emissions, including the reporting of GHG emissions for the electricity sector. The regulations include specific GHG emissions reporting requirements for electric generating facilities, cogeneration facilities, electricity retail providers, and electric power marketers, among others. Electric generating facilities with a total generating unit capacity of at least 1 MW that emit 2,500 metric tonnes or more of CO₂ in any calendar year are required to report CO₂, nitrous oxide (N₂O), and methane (CH₄) emissions from fuel combustion. Where applicable they will also report CO₂ process emissions from acid gas scrubbers, fugitive CO₂ emissions from geothermal power, CH₄ emissions from coal storage, hydrofluorocarbons (HFCs) from generator cooling units, and sulfur hexafluoride (SF₆) emissions from facility equipment. In addition, the facilities will report wholesale power exports, when known, and fuel use data. Cogeneration facilities with a total generating capacity of at least 1 MW that emit 2,500 metric tonnes or more of CO₂ in any calendar year from electricity generating activities, or that are operated by another reporting facility, are required to report CO₂, N₂O, and CH₄ emissions from fuel combustion at the facility, as well as the distribution of emissions for electricity generation, thermal energy production, and (when applicable) manufactured products. Process and fugitive emissions, where applicable, will be as specified for electricity generation units, and fuel use data will also be reported. Electricity retail providers are required to report the same emissions information as electric generating facilities for the generating facilities they operate, and fugitive SF₆ emissions related to the transmission and distribution systems they maintain. Electricity retail providers are also required to report imported and exported power in megawatt hours, by source when known. There are also additional requirements for retail providers related to implementing a possible load-based regulatory approach, including reporting ownership share, renewable energy contract dates, determination of native load power, in-state power purchases and sales, out-of-state owned power sold to out-of-state entities,

and other information. Electric power marketers are required to report the amount of power they import into and export out of California. Marketers that maintain transmission system substations inside California will also report fugitive SF₆ emissions at those substations. Most affected entities, including electric generating facilities, electricity retail providers, and electric power marketers, are required to report their emissions annually, beginning with their 2008 emissions reported in 2009. Emission reports are required to undergo third-party verification. The reporting requirements for electric generating facilities and cogeneration facilities will apply to the power plants owned by EME located in California. The reporting requirements for electricity retail providers will apply to SCE.

 

The CARB directed CARB staff to make some technical modifications to the proposed regulations issued on October 19, 2007. The CARB anticipates that the revised version of the regulations, including the directed changes, will be made available in February 2008 for public comment.

 

The second law, known as SB 1368, required the CPUC and the CEC, respectively, to adopt GHG emission performance standards, known as EPS, for investor owned and publicly owned utilities, respectively, for long-term procurement of electricity. These standards must equal the performance of a combined-cycle gas turbine generator. The CPUC adopted such a standard on January 25, 2007 (which limits emissions to 1,100 pounds of carbon dioxide per MWh). On August 29, 2007, the CEC adopted regulations pursuant to SB 1368 establishing and implementing a GHG EPS for baseload generation of local publicly owned electric utilities. The EPS adopted by the CPUC and CEC also prohibits SCE and other California LSEs from entering into long-term financial commitments with generators that emit more than 1,100 pounds of CO₂ per MWh, which would be most coal-fired plants.

 

California law 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.

 

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 be affected by litigation in federal and state courts. For example, on April 2, 2007, the United States Supreme Court issued an opinion in Massachusetts et. al. v. Environmental Protection Agency, et. al., ruling that the US EPA has the authority to regulate GHG emissions of new motor vehicles under the CAA and that it has a duty to determine whether GHG emissions of new motor vehicles contribute to climate change or offer a reasoned explanation for its failure to make such a determination when presented with a request for a rulemaking on the issue by the state claimants. The Court ruled that the US EPA’s failure to make the necessary determination or to offer a reasonable explanation for its refusal to do so was impermissible. While this case hinged on a provision of the CAA related to emissions of motor vehicles, a parallel provision of the CAA applies to stationary sources, such as electric generators, and there is litigation pending in the D.C. Circuit Court of Appeals, Coke Oven Task Force v. EPA, in which it is argued that the Massachusetts v. EPA case may be applied to stationary sources such as power plants.

 

On December 19, 2007, the Administrator of the US EPA announced that US EPA would not grant the waiver that California had been seeking under established CAA procedures to implement stringent GHG emission reduction requirements for motor vehicles. At least 16 other states have adopted or announced plans to adopt California’s regulations. On January 2, 2008, California sued the US EPA in the 9th Circuit U.S. Court of Appeals challenging the decision to deny California’s request for a waiver. While these developments apply only to automotive sources of GHG emissions, they reflect heightened regulatory scrutiny of, and public concern about, GHG emissions across all sectors of the economy, including power generation.

On October 18, 2007, the Kansas Department of Health and Environment rejected a permit to construct two proposed coal-fired electrical generators based on the impact to health and the environment arising from the proposed units’ emissions of carbon dioxide. This was the first reported rejection of a proposed coal plant permit based on a clean air statute. This decision has been appealed. In addition, there are a number of pending cases in which environmental groups are arguing that air permits for the construction of major coal-fired generating facilities cannot be issued unless the permits include best available control technology to control CO₂ emissions. The US EPA has taken the position that such controls are not required until it finalizes regulations relating to CO₂ emissions.

 

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

 

Response to Climate Change Initiatives

 

Edison International has devoted substantial effort to develop expertise and infrastructure in areas such as energy efficiency, demand response, and renewable sources of power. See “Other Developments — Environmental Matters — Climate Change — Responses to Energy Demands and Future GHG Emission Constraints” in the MD&A.

 

Air Quality Regulation

 

The Federal CAA state clean air acts and federal and state and 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. Many of the air quality laws require the States to develop and submit plans, known as State Implementation Plans or SIPs, to the federal regulator, the US EPA, detailing how they will attain the standards that are mandated by the relevant law or regulation.

 

Clean Air Interstate Rule

 

The CAIR, issued by the US EPA on March 10, 2005, applies to 28 eastern states (including Illinois and Pennsylvania) and the District of Columbia, and is intended to address ozone and fine particulate matter attainment issues by reducing regional SO₂ and NOx emissions. The CAIR reduces the current CAA Title IV Phase II SO₂ emissions allowance cap for 2010 and 2015 by 50% and 65%, respectively. The CAIR also requires reductions in regional NO_X emissions in 2009 and 2015 by 53% and 61%, respectively, from 2003 levels. The CAIR has been challenged in court by state, environmental, and industry groups, which may result in changes to the substance of the rule and to the timetables for implementation.

 

Mercury Regulation

 

By means of a rule published in May 2005, the US EPA established the CAMR, which created the framework for a national, market-based cap-and-trade program to reduce mercury emissions from existing coal-fired power plants to a national cap of 38 tons by 2010 and to 15 tons by 2018, primarily through reductions in mercury achieved by lowering SO₂ and NOx emissions under the CAIR. States were allowed, but not required, to join the trading program by adopting the CAMR model trading rules. States retained the right to promulgate alternative regulations equivalent to or more stringent than the CAMR cap-and-trade program, as long as the regulations were approved by the US EPA.

 

At the time that it published the CAMR, the US EPA also published a second rule, formally rescinding its previous finding that mercury emissions from electrical generating facilities had to be regulated as a hazardous air pollutant pursuant to Section 112 of the CAA, which would have imposed technology-based standards on emission sources. Both the CAMR and US EPA’s decision to remove oil and coal-fired plants from the list of sources to be regulated under Section 112 of the CAA were challenged in the U.S. Court of Appeals for the D.C. Circuit by various environmental groups and state attorneys general.

On February 8, 2008, the D.C. Circuit Court vacated both rules and remanded the matter to the US EPA. As a result, until the US EPA takes action in response to the remand, coal-fired electrical generating units will continue to be sources subject to the requirements of Section 112 of the CAA and will be obligated to comply, on a case-by-case basis, with technology-based standards to control emissions of all hazardous air pollutants, including mercury emissions. As described below, EME’s facilities are already subject to significant, unit-specific mercury emission reduction requirements under Illinois and Pennsylvania regulations, some of which were issued under US EPA procedures that were called into question by the D.C. Circuit’s opinion. (See “Business of Edison Mission Group Inc. — Environmental Matters Affecting EME — Air Quality Regulation — Mercury Regulation” below.) Edison International and EME are assessing the impact of this decision on the regulations in Illinois and Pennsylvania, including whether these regulations will prove to be less stringent than case-by-case Maximum Achievable Control Technology (also known as MACT) standards or than any MACT standards that may eventually be promulgated by the US EPA.

 

Regional Haze

 

In July 1999, the US EPA published the “Regional Haze Rule” to reduce haze and protect visibility in designated federal areas. The goal of the 1999 rule is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions by 2064. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install BART or implement other control strategies to meet regional haze control requirements. The US EPA issued a final rulemaking on regional haze on June 15, 2005. States were required to revise their SIPs by December 2007 to demonstrate reasonable further progress towards meeting regional haze goals. Emission reductions achieved through other ongoing control programs may be sufficient to demonstrate reasonable progress toward the long-term goal, particularly for the first 10 to 15 year phase of the program.

 

New Source Review Requirements

 

Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address CAA NSR compliance issues at the nation’s coal-fired power plants. The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made to air emissions sources at a facility. The US EPA’s strategy has includes both the filing of suits against a number of power plant owners, and the issuance of administrative NOVs to a number of power plant owners alleging NSR violations. On July 31, 2007, the US EPA issued such a NOV to Midwest Generation and Commonwealth Edison. See “EMG: Other Developments — Midwest Generation Potential Environmental Proceeding” in the MD&A.

 

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. States were required to revise their SIPs for the ozone and particulate matter standards within three years of the effective date of the respective non-attainment designations. The revised SIPs are likely to require additional emission reductions from facilities that are significant emitters of ozone precursors and particulates.

 

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. The rule may require states to impose further emission reductions beyond those necessary to meet the existing standards.

 

On July 11, 2007, the US EPA issued a proposed rule to make revisions to the primary and secondary national ambient air quality standards for ozone. The US EPA proposes to reduce the level of the 8-hour primary standard for ozone. The rule may require states to impose further emission reductions beyond those necessary to meet the existing standards. If adopted, Edison International anticipates that no such further emission reduction obligations will be imposed under the new rule until 2015.

Hazardous Substances and Hazardous Waste Laws

 

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

 

In 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. In particular, 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.

 

Clean Water Act — Cooling Water Intake Structures

 

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 or drawn into cooling water systems. Pursuant to the regulation, a demonstration study was required when applying for a new or renewed NPDES wastewater discharge permit. If one could demonstrate that the costs of meeting the presumptive standards set forth in the regulation were significantly greater than the costs that the US EPA assumed in its rule making or are significantly disproportionate to the expected environmental benefits, a site-specific analysis could be performed to establish alternative standards. Depending on the findings of the demonstration studies, 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. The US EPA is expected to begin another rulemaking process by the end of 2008.

 

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 430 cities and communities and a population of more than 13 million people. In 2007, SCE’s total operating revenue was derived as follows: 41% commercial customers, 37% residential customers, 4% resale sales, 7% industrial customers, 5% other electric revenue, 5% public authorities, and 1% agricultural and other customers. At December 31, 2007, SCE had consolidated assets of $27.5 billion and total shareholder’s equity of $7.2 billion. SCE had 15,442 full-time employees at year-end 2007.

 

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

 

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

 

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

 

The construction, planning, and siting of SCE’s power plants within California are subject to the jurisdiction of the California Energy Commission (for plants 50 MW or greater) and the CPUC. SCE is subject to the rules and regulations of the California Air Resources Board, 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 California Coastal Commission issued a coastal permit for the construction of the San Onofre Units 2 and 3 in 1974. This permit, as amended, requires mitigation for impacts to marine organisms and the San Onofre kelp bed. California Coastal Commission jurisdiction will continue for several years due to ongoing implementation and oversight of these permit mitigation conditions, consisting of restoration of wetlands and construction of an artificial reef for kelp. SCE has a coastal permit from the California Coastal Commission to construct a temporary dry cask spent fuel storage installation for San Onofre Units 2 and 3. The California Coastal Commission also has continuing jurisdiction over coastal permits issued for the decommissioning of

San Onofre Unit 1, including for the construction of a temporary dry cask spent fuel storage installation for spent fuel from that unit.

 

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

 

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

 

Because SCE is an electric utility company operating within a defined service territory pursuant to authority from the CPUC, SCE faces competition only to the extent that federal and California laws permit other entities to provide electricity and related services to customers within SCE’s service territory. California law currently provides only limited opportunities for customers to choose to purchase power directly from an energy service provider other than SCE. SCE also faces some competition from cities that create municipal utilities or community choice aggregators. In addition, customers may install their own on-site power generation facilities. Competition with SCE is conducted mainly on the basis of price, as customers seek the lowest cost power available. The effect of competition on SCE generally is to reduce the size of SCE’s customer base, thereby creating upward pressure on SCE’s rate structure to cover fixed costs, which in turn may cause more customers to leave SCE in order to obtain lower rates.

 

SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, which deliver power from generating sources to the distribution network, consist of approximately 7,200 circuit miles of 33 kilovolt (kV), 55 kV, 66 kV, 115 kV, and 161 kV lines and 3,500 circuit miles of 220 kV lines (all located in California), 1,240 circuit miles of 500 kV lines (1,040 miles in California, 90 miles in Nevada, and 110 miles in Arizona), and 858 substations. SCE’s distribution system, which takes power from substations to the customer, includes approximately 71,550 circuit miles of overhead lines, 40,000 circuit miles of underground lines, 1.5 million poles, 717 distribution substations, 710,980 transformers, and 804,771 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, and (4) a natural gas-fueled two unit power plant (1,050 MW) located in Redlands, California.

 

In 2007, SCE completed construction of four gas-fueled, combustion turbine peaker plants located in the cities of Norwalk, Ontario, Rancho Cucamonga and Stanton, California. All four plants commenced operations in August 2007. The peaker plants have a combined generating capacity of 186 MW.

 

SCE also owns an undivided 56% interest (884.8 MW net) in Mohave, which consists of two coal-fueled generating units located in Clark County, Nevada near the California border. The plant ceased operating on December 31, 2005. On June 19, 2006, SCE announced that it had decided not to move forward with its efforts to return Mohave to service.

 

SCE also 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.

At year-end 2007, the SCE-owned generating capacity (summer effective rating) was divided approximately as follows: 42% nuclear, 22% hydroelectric, 23% natural gas, 13% coal, and less than 1% diesel. The capacity factors in 2007 for SCE’s nuclear and coal-fired generating units were: 91% for San Onofre; 78% for Four Corners; and 80% 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 23% capacity factor in 2007. These plants were operationally available for 85% 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 2008 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 $4.68 billion in principal amount was outstanding on February 26, 2008. Such lien and SCE’s title to its properties are subject to the terms of franchises, licenses, easements, leases, permits, contracts, and other instruments under which properties are held or operated, certain statutes and governmental regulations, liens for taxes and assessments, and liens of the trustees under the trust indenture. In addition, such lien and SCE’s title to its properties are subject to certain other liens, prior rights and other encumbrances, none of which, with minor or insubstantial exceptions, affect SCE’s right to use such properties in its business, unless the matters with respect to SCE’s interest in Four Corners and the related easement and lease referred to below may be so considered.

 

SCE’s rights in Four Corners, which is located on land of the Navajo Nation of Indians under an easement from the United States and a lease from the Navajo Nation, may be subject to possible defects. These defects include possible conflicting grants or encumbrances not ascertainable because of the absence of, or inadequacies in, the applicable recording law and the record systems of the Bureau of Indian Affairs and the Navajo Nation, the possible inability of SCE to resort to legal process to enforce its rights against the Navajo Nation without Congressional consent, the possible impairment or termination under certain circumstances of the easement and lease by the Navajo Nation, Congress, or the Secretary of the Interior, and the possible invalidity of the trust indenture lien against SCE’s interest in the easement, lease, and improvements on Four Corners.

 

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 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 2007 were as follows: 43.3% purchased power; 27.1% CDWR; and 29.6% SCE-owned generation consisting of 21.1% nuclear, 5.8% coal, and 2.7% hydro.

 

Natural Gas Supply

 

SCE’s natural gas requirements in 2007 were to meet contractual obligations for power tolling agreements (power contracts in which SCE has agreed to provide the natural gas needed for generation under those power contracts) and to serve demand for gas at Mountainview and the four peaker plants, which commenced operations in August 2007. All of the physical gas purchased by SCE in 2007 was purchased under North American Energy Standards Board agreements (master gas agreements) that define the terms and conditions of transactions with a particular supplier prior to any financial commitment.

 

In 2006, SCE secured a one-year natural gas storage capacity contract with Southern California Gas Company for the 2006/2007 storage season. Storage capacity was secured to provide operation flexibility and to mitigate potential costs associated with the dispatch of SCE’s tolling agreements. SCE executed a natural gas capacity storage contract with Southern California Gas Company for the 2007/2008 storage season.

 

Nuclear Fuel Supply

 

For San Onofre Units 2 and 3, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below:

 

 

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

 

 

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.

 

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 in the United States. This regulation, including in the areas of air and water pollution, waste management, hazardous chemical use, noise abatement, land use, aesthetics, nuclear control and climate change, continues to result in the imposition of numerous restrictions on SCE’s operation of existing facilities, on the timing, cost, location, design, construction, and operation by SCE of new facilities, and on the cost of mitigating the effect of past operations on the environment. 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 regulation of climate change to determine their impact on its operations. Programs to reduce emissions of CO₂ 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. Any such cost increases are generally 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. SCE seeks to modify the decision to exempt financial contributions required by contracts in existence as of January 25, 2007, with facilities that would not otherwise meet the standard.

 

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

 

Clean Air Interstate Rule

 

The US EPA’s CAIR currently does not apply to SCE’s facilities. While the US EPA has not adopted a rule comparable to CAIR for the western United States where SCE has facilities, SCE cannot predict what action the US EPA will take in the future with regard to the western United States, and what impact those actions would have on its facilities.

 

Regional Haze

 

The US EPA has adopted alternate rules for the area where Four Corners is located. The rules allow nine western states and Indian tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule. The US EPA issued a Revised Annex Rule on October 13, 2006, to address a previous challenge and court remand of that rule.

 

Ambient Air Quality Standards

 

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 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.

 

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 the laws and regulations identified herein. 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

 

Cooling Water Intake Structures

 

The US EPA Phase II rule did not have a material impact on SCE’s operations at San Onofre. Until the US EPA adopts new rules, SCE cannot determine their impact.

 

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 — Cooling Water Intake Structures.”

 

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

 

EME was formed in 1986 with two domestic operating power plants. As of December 31, 2007, EME’s continuing operations consisted of owned or leased interests in 28 operating projects with an aggregate net physical capacity of 10,623 MW, of which EME’s capacity pro rata share was 9,453 MW. At December 31, 2007, eight projects totaling 447 MW of generating capacity were under construction. EME’s operating projects primarily consist of coal-fired generating facilities, natural gas-fired facilities and wind farms, unless otherwise specifically noted.

 

Historically, 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 ancillary services, has undergone significant deregulation over the last three decades, which has led to increased competition. Most recently, through the EPAct 2005, Congress recognized that a significant market for electric power produced by independent power producers, such as EME, has developed in the United States and indicating that competitive wholesale electricity markets have become accepted as a fundamental aspect of the electricity industry.

 

As part of the 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 expanded access to transmission service. ISOs and RTOs may also operate real-time and day-ahead energy and ancillary service markets, which are governed by FERC-approved tariffs and market rules. The development of such organized markets into which independent power producers are able to sell has reduced their dependence on bilateral contracts with electric utilities. See further discussion of regulations under “ — Regulation of EME — United States Federal Energy Regulation.”

 

In various regional markets, electricity market administrators have acknowledged that the markets for generating capacity do not provide sufficient revenues 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. PJM originally covered Pennsylvania, New Jersey, and Maryland, and now extends from North Carolina to Illinois. PJM operates a wholesale spot energy market and determines the market-clearing price for each hour based on bids submitted by participating generators which indicate the minimum prices a bidder is willing to accept to be dispatched at various incremental generation levels. PJM conducts both day-ahead and real-time energy markets. PJM’s energy markets are based on locational marginal pricing, which establishes hourly prices at specific locations throughout PJM. Locational marginal pricing is determined by considering a number of factors, including generator bids, load requirements, transmission congestion and transmission losses. PJM requires all load-serving entities to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM also determines the amount of

capacity available from each specific generator and operates capacity markets. PJM’s capacity markets have a single market-clearing price. Load-serving entities and generators, such as EME’s subsidiaries Midwest Generation, with respect to the Illinois Plants, and EME Homer City, with respect to the Homer City facilities, may participate in PJM’s capacity markets or transact capacity sales on a bilateral basis.

 

The Homer City facilities have direct, high voltage interconnections to both PJM and the 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.

 

Prior to May 1, 2004, sales of power produced by Midwest Generation required using transmission that had to be obtained from Commonwealth Edison. As mentioned previously, the Illinois plants are generally dispatched into the PJM market. Sales may also be made from PJM into the MISO, where there is a single rate for transmission.

 

On April 1, 2005, the MISO commenced operation, linking portions of Illinois, Wisconsin, Indiana, Michigan, and Ohio, as well as other states in the region. In the MISO, there is a bilateral market and day-ahead and real-time markets based on locational marginal pricing similar to that of PJM. While EME does not own generating facilities within the MISO, its opening has further facilitated transparency of prices and provided additional market liquidity to support risk management and trading strategies.

 

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

 

EME is subject to intense competition from energy marketers, utilities, industrial companies, 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 location of their generation facilities.

 

For a number of years, natural gas had been the fuel of choice for new power generation facilities for economic, operational and environmental reasons. While natural gas-fired facilities continue to be an important part of the nation’s generation portfolio, some regulated utilities are constructing units powered by renewable resources, often with subsidies or under legislative mandate. New environmental regulations, particularly those that limit emissions of CO₂ and other GHG by electric generators, could put coal-fired power plants at a disadvantage compared with plants utilizing other fuels.

 

Where EME sells power from power plants from which the output is not committed to be sold under long-term contracts, commonly referred to as merchant plants, EME is subject to market fluctuations in prices based on a number of factors, including the amount of capacity available to meet demand, the price and availability of fuel and the presence of transmission constraints.

 

EME’s operating projects are located within the United States, except for the Doga project in Turkey. As of December 31, 2007, 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 expects to continue to do so over the next several years. Historically, wind projects have received federal subsidies in the form of production tax credits. In August 2005, production tax credits were made available for new wind projects placed in service by December 31, 2007 under EPAct 2005. In December 2006, the deadline for production tax credits was extended to apply to new wind projects placed in service by December 31, 2008.

 

In seeking to find and invest in new wind projects, EME has teamed with third-party development companies through joint development agreements that provide for funding of development costs through loans (referred to as development loans) and joint decision-making on key contractual agreements (e.g., power purchase contracts, site agreements and permits). Joint development agreements and development loans may be for a specific project or a group of identified and future projects and generally grant EME the exclusive right to acquire related projects. 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 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.

 

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.

 

Thermal Projects

 

EME expects to make investments in thermal projects during the next several years. As part of its development efforts, EME is in the process of obtaining permits for two sites in Southern California for peaker plants. Development efforts include feasibility studies, site development and acquisition, permitting, and contractual arrangements, including fuel supply and interconnection. Generally, it is expected that thermal projects in which EME invests will sell electricity under long-term power purchase contracts. EME may

participate in bids to utilities in response to requests for proposals to build new generation and may acquire existing generation in selected markets.

 

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

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

 

EME’s merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively monitored by EME’s risk management committee to ensure compliance with EME’s risk management policies. Policies are in place which define risk tolerances, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by the risk management committee. EME uses “value earnings at risk” to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions of its Illinois Plants, its 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 earnings 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 limits and counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated.

 

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

 

Beginning in January 2007, EME 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 19% of EME’s consolidated operating revenues for the year ended December 31, 2007. In the past three fiscal years, EME also derived a significant source of its operating revenues from electric power sold into the PJM market from the Homer City facilities and the Illinois Plants. Sales into PJM accounted for approximately 51%, 58% and 69% of EME’s consolidated operating revenues for the years ended December 31, 2007, 2006 and 2005, respectively.

 

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 Homer City property insurance program currently covers losses up to $1.25 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 permits it to maintain its current insurance coverage through June 1, 2008.

 

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. Federal laws and regulations govern, among other things, transactions by and with purchasers of power, including utility companies, the operation of a power plant and the ownership of a power plant. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Energy-producing projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning, land use and operation of a project. Federal, state and local environmental requirements generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with these permits and approvals. In addition, EME is subject to the market rules, procedures, and protocols of the markets in which it participates.

 

EME is subject to a varied and complex body of laws and regulations that are in a state of flux. Intricate and changing environmental and other regulatory requirements could necessitate substantial expenditures and could

create a significant risk of expensive delays or significant loss of value in a project if it were to become unable to function as planned due to changing requirements or local opposition.

 

United States Federal Energy Regulation

 

The FERC has ratemaking jurisdiction and other authority with respect to interstate wholesale sales and transmission of electric energy (other than transmission that is “bundled” with retail sales) under the 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. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing additional exemptions from PUHCA 1935 for exempt wholesale generators (EWGs) and foreign utility companies.

 

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 and other non-qualifying facility independent power projects are subject to the FPA and to the FERC’s ratemaking jurisdiction thereunder, but the FERC typically grants EWGs the authority to charge market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown.

 

As of December 31, 2007, 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.

 

In addition, the FPA grants the FERC jurisdiction over the sale or transfer of jurisdictional 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. In granting authority to make sales at market-based rates, the FERC typically also grants blanket approval for certain obligations, such as those related to the issuance of securities. However, 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 determines that the relevant market meets certain conditions for competitive, nondiscriminatory access), and that the utilities sell back up power to the qualifying facility on a nondiscriminatory basis. The FERC’s regulations also permitted qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility’s avoided costs.

 

EPAct 2005 made several important amendments to PURPA, including:

 

 

 

The FERC has initiated several proceedings to promulgate rules and regulations to implement the mandates of EPAct 2005 with respect to PURPA. On October 20, 2006, FERC issued a final rule establishing a rebuttable presumption that any utility located in MISO, PJM, ISO New England, NYISO or Electric Reliability Council of Texas (ERCOT) will be relieved from the must-purchase requirement with respect to qualifying facilities larger than 20 MW. With respect to other markets, and with respect to all qualifying facilities 20 MW or smaller, the utility bears the burden of showing that it qualifies for relief from the must-purchase requirement. Any electric utility seeking relief from the must-purchase requirement, regardless of location, must apply to the FERC for relief.

 

Several of EME’s projects, including the Big 4 Projects, the Westside Projects, American Bituminous, and March Point, are qualifying cogeneration facilities. 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 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. Moreover, EME’s business and financial condition could be adversely affected if regulations or legislation were modified or enacted that changed the standards applicable to EME’s facilities for maintaining qualifying facility status or that eliminated or reduced the benefits and exemptions currently enjoyed by EME’s qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to, among other things, fines and penalties, or claims by a utility customer for the refund of payments previously made.

 

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

 

Natural Gas Act

 

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

 

Transmission of Wholesale Power

 

Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others. This transmission

service over the lines of intervening transmission owners is also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the FERC when the entity providing the transmission service is a jurisdictional public utility under the 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.

 

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

 

On February 16, 2007, the FERC issued Order No. 890 with the stated intent of promoting competition in wholesale power markets and strengthening the electric power grids. Order No. 890 is designed to strengthen the Open Access Rules embodied in Order No. 888, increase transparency in the rules applicable to planning and use of the transmission system, make undue discrimination in transmission easier to detect, and facilitate the FERC’s enforcement efforts in remedying such discrimination. Public utility transmission providers, including RTOs and ISOs, were required to make changes in their tariffs to comply with Order No. 890.
Order No. 890 became effective on May 14, 2007.

 

Illinois Power Procurement

 

Prior Auction Rules

 

In February 2005, Commonwealth Edison and the Ameren Illinois utilities filed tariffs at the Illinois Commerce Commission proposing the adoption of what is known as a New Jersey style full requirement auction process for the procurement of power for the utilities’ bundled customers beginning January 1, 2007. The Illinois Commerce Commission unanimously approved the competitive auction process on January 24, 2006.

 

In September 2006, the first Illinois power procurement auction was held according to the rules approved by the Illinois Commerce Commission. Through the auction, EMMT entered into two load requirements service contracts. Under the terms of these agreements, Midwest Generation is delivering, through EMMT, electricity, capacity and specified ancillary, transmission and load following services necessary to serve a portion of Commonwealth Edison’s residential and small commercial customer load.

 

Illinois Auction Challenges

 

Legal actions, including a complaint at the FERC by the Illinois Attorney General and two class action lawsuits, were instituted against successful participants in the 2006 Illinois power procurement auction, including EMMT. On July 24, 2007, Midwest Generation and EMMT, along with other power generation companies and utilities, entered into a settlement with the Illinois Attorney General. Enacting legislation for the settlement was signed on August 28, 2007. As part of the settlement, all auction-related complaints filed by the Illinois Attorney General at the FERC, the Illinois Commerce Commission and in the Illinois courts were dismissed and on December 24, 2007, the class action lawsuits were dismissed. For further discussion, see “EMG: Other Developments — Settlement with Illinois Attorney General” in the MD&A.

Power Procurement in the Future

 

The legislation that was signed into law on August 28, 2007, is referred to as the Illinois Power Agency Act. In addition to enacting the settlement and associated rate relief provisions, the Illinois Power Agency Act establishes a new process for Commonwealth Edison and the Ameren Illinois utilities to procure power for their bundled-rate customers. Beginning July 1, 2008, the two utilities will procure power for bundled-rate customers by means of those full requirements contracts that resulted from the September 2006 auction 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.

 

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 the load-serving entities through a locational reliability charge. Also 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, which is then allocated among the load-serving entities through a locational reliability charge. Also 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, which is then allocated among the 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. EME is still evaluating the impact that marginal loss pricing in PJM will have on its results of operations, but continues to believe that it may reduce locational marginal prices for some of its units relative to the locational marginal prices for the benchmark locations of Western Hub and Northern Illinois Hub.

 

The construction and operation of power plants by EME are subject to environmental regulation by federal, state and local authorities.

 

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 CO₂ or that would impose additional costs or charges for the emission of CO₂ 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. Programs to reduce emissions of CO₂ and other GHG emissions could significantly increase the cost of generating electricity from fossil fuels, especially coal.

 

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 emissions performance standard contemplated by SB 1368, 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, related 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, NOx and SO₂ emissions at the Illinois Plants. The agreement has been embodied in rule language, called the CPS, and Midwest Generation’s obligations under the agreement were conditioned upon the formal adoption of the CPS as a rule. On January 5, 2007, the Illinois EPA and Midwest Generation jointly filed the CPS in the pending state rulemaking related to the Illinois SIP for the CAIR. The CPS became final upon publication in the Illinois Register, which took place on September 7, 2007. Midwest Generation believes that the CPS will provide greater predictability with respect to the timing and amount of emissions reductions that will be required of the Illinois Plants for these pollutants through 2018. See “Other Developments — Environmental Matters — Air Quality Standards — Clean Air Interstate Rule — Illinois” in the MD&A for a description of the agreement with the Illinois EPA.

 

On May 30, 2006, the Illinois EPA submitted a proposed regulation to the Illinois Pollution Control Board to implement the Illinois SIP required for compliance with the CAIR. The Illinois CAIR rule became final upon publication in the Illinois Register, which took place on September 7, 2007. Because the CPS involves mercury emissions, the US EPA has moved the CPS from the Illinois CAIR SIP to the Illinois CAMR SIP, which was pending final action by the US EPA prior to the February 8, 2008 U.S. Court of Appeals decision vacating the federal CAMR. See “Business of Edison International — Environmental Matters Affecting Edison International — Air Quality Regulation — Mercury Regulation.” The US EPA approved the Illinois CAIR SIP (without the CPS included) effective as of December 17, 2007.

 

Pennsylvania

 

For information on compliance with CAIR in Pennsylvania by EME Homer City, see “Other Developments — Environmental Matters — Air Quality Standards — Clean Air Interstate Rule — Pennsylvania” in the MD&A.

 

Mercury Regulation

 

Illinois

 

The final state rule for the reduction of mercury emissions in Illinois was adopted and became effective on December 21, 2006. However, Midwest Generation’s CPS, supersedes this rule for the Illinois plants. The CPS requires installation of activated carbon injection technology for the removal of mercury on all Midwest Generation units by July 2009 (except for three units to be shut down by the end of 2010), prohibits participation in the federal cap-and-trade program, and requires a 90% removal of mercury by unit by the end of 2015.

 

Any impact of the D.C. Circuit Court decision on EME cannot yet be determined. For additional discussion of the D.C. Circuit Court decision, see “Business of Edison International — Environmental Matters Affecting Edison International — Air Quality Regulation — Mercury Regulation.”

Pennsylvania

 

For information on compliance with mercury regulations in Pennsylvania by EME Homer City, see “Other Developments — Environmental Matters — Air Quality Standards — Mercury Regulation — Pennsylvania” in the MD&A.

 

Ambient Air Quality Standards

 

Almost all of EME’s facilities are located in counties that have been identified as being in non-attainment with air quality standards. EME anticipates that any further emissions reduction obligations required under the final rule on fine particulates would not be imposed until 2015 at the earliest, and intends to consider such rules as part of its overall plan for environmental compliance.

 

Illinois

 

Beginning with the 2003 ozone season (May 1 through September 30), EME has been required to comply with an average NO_X emission rate of 0.25 lb NO_X/mm British Thermal Units of heat input. This limitation is commonly referred to as the East St. Louis SIP. This regulation is a State of Illinois requirement. Each of the Illinois plants complied with this standard in 2004. Beginning with the 2004 ozone season, the Illinois Plants became subject to the federally mandated “NO_X SIP Call” regulation that provided ozone-season NO_X emission allowances to a 19-state region east of the Mississippi. This program provides for NO_X allowance trading similar to the SO₂ (acid rain) trading program already in effect.

 

During 2004, the Illinois plants stayed within their NO_X allocations by augmenting their allocation with early reduction credits generated within the fleet. In 2005, the Illinois plants used banked allowances, along with some purchased allowances, to stay within their NO_X allocations. In 2006 and 2007, the Illinois plants used purchased allowances to stay within their NO_X allocations. Midwest Generation plans to continue to purchase allowances as it implements the agreement it reached with the Illinois EPA.

 

Pennsylvania

 

In June 2007, the PADEP requested a redesignation of Clearfield/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, EME 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 is due to the US EPA by April 5, 2008. Although the final form of the SIP is not yet known, at this time EME does not anticipate that it will be required to install additional pollution controls at the Homer City facilities to meet the expected SIP requirements for fine particulates.

 

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 $3 million at December 31, 2007, 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.

 

Ambient Air Quality Standards

 

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, EME 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 is due to the US EPA by April 5, 2008. Although the final form of the SIP is not yet known, at this time, EME does not anticipate that it will be required to install additional pollution controls at the Homer City facilities to meet the expected SIP requirements for fine particulates.

 

Water Quality Regulation

 

Clean Water Act - Cooling Water Intake Structures

 

EME has begun to collect 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, and those activities are continuing. Although the US EPA rule to be generated in the new rulemaking process could have a material impact on EME’s operations, its compliance criteria have not yet been finalized, and EME cannot reasonably determine the financial impact at this time.

 

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 which those stations use water for station cooling. See “Other Developments — Environmental Matters — Water Quality Regulation — State Water Quality Standards — Illinois” in the MD&A.

 

At December 31, 2007, EME and its subsidiaries employed 1,793 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, Edison Mission Group Inc. The projects were then contributed to EME. During the first half of 2006, Edison Capital made a dividend of its remaining wind projects to Edison Mission Group Inc., and the projects were subsequently contributed to EME.

 

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

 

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.

 

Leveraged Leases

 

As of December 31, 2007, Edison Capital is the lessor with an investment balance of $2.6 billion in the following leveraged leases:

 

 

 

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, 2007, in the aggregate at approximately $1.8 billion against $2.6 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 year-end 2007, Edison Capital had an investment balance of $22 million in the Latin America fund, $16 million in the Asia fund, and $22 million in the emerging Europe fund. As of December 31, 2007, 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, 2007, Edison Capital had a net investment of $16 million in approximately 319 affordable housing projects with approximately 26,000 units rented to qualifying low-income tenants in 36 states. These investments are usually in the form of majority interests in limited partnerships or limited liability companies. With a few exceptions, the projects are managed by third parties. For 105 projects, Edison Capital has guaranteed a minimum return to the syndicated investor. Edison Capital continues to consolidate the investment funds subject to the guaranteed minimum return. Edison Capital retained a minority interest in, and continues to monitor, all of the syndicated investments. Edison Capital is entitled to low-income housing tax credits, depreciation and interest deductions, and a small percentage of cash generated from the projects. Edison Capital’s tax credits from these projects could be recaptured by the Internal Revenue Service if, among other things, the project fails to comply with the requirements of the tax credit program, costs are excluded from the eligible basis used to compute the amount of tax credits, or the project changes ownership through foreclosure. In most cases, Edison Capital is indemnified by the project manager (or parties related to it) against some losses, but there is no assurance of collecting against such indemnities. As of year-end 2007, 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.

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

 

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

 

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

 

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

 

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 could be materially adversely affected.

 

SCE’s revenues and earnings are substantially affected by regulatory proceedings known as general rate cases and cost of capital proceedings. General rate cases are expected to occur every three years. During those cases, the CPUC determines SCE’s rate base (the value of assets on which SCE earns a rate of return for investors), depreciation rates, operation and maintenance costs, and administrative and general costs that SCE may recover from its customers through its rates. Cost of capital proceedings are currently conducted annually. During those cases, the CPUC authorizes SCE’s capital structure and the return on common equity applicable to the rate base determined in the general rate case proceedings. More information about these proceedings is set forth in the MD&A under the heading “SCE: Regulatory Matters.”

 

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

 

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

 

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

 

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

 

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

 

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

 

 

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

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

 

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

 

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

 

 

 

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

 

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

 

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

 

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. See “EMG: Market Risk Exposures — Commodity Price Risk” in the MD&A.

 

EME may not be able to hedge market risks effectively.

 

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

 

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

 

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

 

 

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

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

 

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

 

EME is subject to extensive energy industry regulation.

 

EME’s operations are subject to extensive regulation by governmental agencies. EME’s projects are subject to federal laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the development and construction of generation facilities, the ownership and operations of generation facilities, and access to transmission. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Generation facilities are also subject to federal, state and local laws and regulations that govern, among other things, the geographical location, zoning, land use and operation of a project.

 

The FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, where it determines that potential market power might exist and that the public interest requires mitigation. In addition, many of EME’s facilities are subject to rules, restrictions and terms of participation imposed and administered by various RTOs and ISOs. For example, ISOs and RTOs may impose bidding and scheduling rules, both to curb the potential exercise of market power and to facilitate market functions. Such actions may materially affect EME’s results of operations.

 

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

 

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

 

EME’s operations are subject to extensive environmental 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’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) integrated gasification combined cycle, 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 plans to make substantial additional commitments in the future. In addition, EME expends significant amounts for preliminary engineering, permitting, legal and other expenses before it can determine whether it will win a competitive bid, or whether a project is feasible or economically attractive.

 

Historically, wind projects have received federal subsidies in the form of production tax credits. In August 2005, production tax credits were made available for new wind projects placed in service by December 31, 2007, under EPAct 2005. In December 2006, the deadline for production tax credits was extended to apply to new wind projects placed in service by December 31, 2008. 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, 2008, 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. 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. Furthermore, EME may not be able to obtain financing for new projects that are developed and may not be able to obtain sufficient equity capital or additional borrowings to enable it to fund equity commitments for future projects. Recent disruptions in the credit markets have impacted the availability of credit, cost of borrowing, and terms and conditions of new borrowings. It is uncertain whether these market conditions will affect EME’s ability to obtain financing for new projects or the terms and conditions of future financings. If a project under development is abandoned, EME would expense all capitalized development costs incurred in connection with that project, and could incur additional losses associated with any related contingent liabilities. If EME is not successful in developing new projects, it may be required to sell turbines that were purchased and such sales may result in substantial losses. See “EMG: Liquidity — Purchase Obligations” in the MD&A.

 

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 another turbine manufacturer has suspended operations at one site in order to address potential rotor blade and gearbox 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 project construction could subject projects to damages under their power purchase agreements. The turbine suppliers have provided warranties for workmanship, schedule guarantees and performance guarantees during the first five years after a turbine has been commissioned. However, EME cannot predict at this time the amount of damages that will be received 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. For further discussion, see “EMG: Liquidity — Capital Expenditures — Wind Turbine Performance Issues.”

 

Competition could adversely affect EME’s business.

 

The independent power industry is characterized by numerous capable competitors, some of whom may have more extensive operating experience in the acquisition and development of power projects, larger staffs, and greater financial resources than EME. Several participants in the wholesale markets, including many regulated utilities, have a lower cost of capital than most merchant generators and often are able to recover fixed costs

through rate base mechanisms, allowing them to build, buy and upgrade generation assets without relying exclusively on market clearing prices to recover their investments. This could affect EME’s ability to compete effectively in the markets in which those entities operate.

 

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

 

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

 

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

 

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

 

 

Recent disruptions in the credit markets have impacted the availability of credit, cost of borrowing, and terms and conditions of new borrowings. EME cannot provide assurance that its projected sources of capital will be available when needed or that its actual cash requirements will not be greater than expected.

 

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

 

As of December 31, 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, 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 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.

 

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.

 

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

 

EME engages in hedging activities in order to mitigate its exposure to market risk with respect to electricity sales from its generation facilities, fuel utilized by those facilities and emissions allowances. EME generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract

volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. EME also uses derivative contracts with respect to its limited proprietary trading activities, through which EME attempts to achieve incremental returns by transacting where it has specific market expertise. These derivative contracts are recorded on its balance sheet at fair value pursuant to SFAS No. 133. Some of these derivative contracts do not qualify under SFAS No. 133 for hedge accounting, and changes in their fair value are therefore recognized currently in earnings as unrealized gains or losses. As a result, EME’s financial results, including gross margin, operating income and balance sheet ratios, will at times be volatile and subject to fluctuations in value primarily due to changes in electricity and fuel prices. See “EMG: Market Risk Exposures — Accounting for Energy Contracts” in the MD&A.

 

None.

 

 

As a holding company, Edison International does not directly own any significant properties other than the stock of its subsidiaries. The principal properties of SCE are described above under “Business of Southern California Edison Company — Properties of SCE.” Properties of EME and Edison Capital are discussed above under “Business of Edison Mission Group Inc. — Business of Edison Mission Energy” and “ — Business of Edison Capital,” respectively.

 

 

 

Information about the CPUC investigation regarding SCE’s performance-based ratemaking (PBR) rewards for customer satisfaction, injury and illness reporting and system reliability portions of PBR appears in the MD&A under the heading “SCE: Regulatory Matters — Investigations Regarding Performance Incentive Rewards — CPUC Investigation.”

 

 

During the first half of 2006, the South Coast Air Quality Management District (SCAQMD) issued three NOVs alleging that Unit 15, SCE’s primary diesel generation unit on Catalina Island, had exceeded the NO_x emission limit dictated by its air permit. Prior to the NOVs, SCE had filed an application with the SCAQMD seeking a permit revision that would allow a three-hour averaging of the NO_x limit during normal (non-startup) operations and clarification regarding a startup exemption. In July 2006, the SCAQMD denied SCE’s application to revise the Unit 15 air permit, and informed SCE that several conditions would have to be satisfied prior to re-application. SCE is currently in the process of developing and supplying the information and analyses required by those conditions.

 

On October 2, 2006 and July 19, 2007, SCE received two additional NOVs pertaining to two other Catalina Island diesel generation units, Unit 7 and Unit 10, alleging that these units have exceeded their annual NO_x limit in 2004 (Unit 10), 2005 (Unit 7), and 2006 (Unit 10). Going forward, SCE expects that the new Continuous Emissions Monitoring System, installed in late 2006, which monitors the emissions from these units, along with the employment of best practices, will enable these units to meet their annual NO_x limits in 2007.

 

Settlement negotiations with the SCAQMD regarding the penalties are ongoing and the SCAQMD has not yet proposed any specific fines to be imposed on SCE.

 

 

Information about the FERC notice regarding an investigatory proceeding with respect to EMMT appears in the MD&A under the heading “EMG: Other Developments — FERC Notice Regarding Investigatory Proceeding against EMMT.”

 

 

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.”

 

No matters were submitted to a vote of shareholders of Edison International during the fourth quarter of 2007.

 

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

 

 

 

Edison International

 

 

 

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. Bouknight, 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:

 

 

Edison International

 

 

 

Southern California Edison Company

 

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:

 

Southern California Edison Company

 

 

The Nonutility Companies

 

 

 

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:

 

The Nonutility Companies

 

 

 

Edison International Common Stock is traded on the New York Stock Exchange under the symbol “EIX.”

 

Market information responding to Item 5 is included in the Annual Report under the heading “Quarterly Financial Data (Unaudited)” on page 163 and is incorporated herein by this reference. There are restrictions on the ability of Edison International’s subsidiaries to transfer funds to Edison International that currently materially limit the ability of Edison International to pay cash dividends. Such restrictions are discussed in the MD&A under the heading “Edison International (Parent): Liquidity” and Note 3 of Notes to Consolidated Financial Statements. The number of common stock shareholders of record of Edison International was 54,187 on February 22, 2008. Additional information concerning the market for Edison International’s Common Stock is set forth on the cover page hereof.

 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

The following table contains information about all purchases made by or on behalf of Edison International or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) of shares or other units of any class of Edison International’s equity securities that is registered pursuant to Section 12 of the Exchange Act.

 

 

 

 

Information responding to Item 6 is included in the Annual Report under “Selected Financial Data: 2003 — 2007” on page 175, and is incorporated herein by this reference.

 

 

Information responding to Item 7 is included in the Annual Report on pages 6 through 101 and is incorporated herein by this reference.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

Information responding to Item 7A is included in the MD&A under the headings “SCE: Market Risk Exposures” on pages 31 through 33, “EMG: Market Risk Exposures” on pages 42 through 56.

 

 

Certain information responding to Item 8 is set forth after Item 15 in Part III. Other information responding to Item 8 is included in the Annual Report on pages 103 through 109 and is incorporated herein by this reference.

 

 

None.

 

 

Disclosure Controls and Procedures

 

Edison International’s management, under the supervision and with the participation of the company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of Edison International’s disclosure controls and procedures (as that term is defined in Rule 13a-15(e) or 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, Edison International’s disclosure controls and procedures are effective.

 

Management’s Report on Internal Control Over Financial Reporting

 

Edison International’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as that term is defined in Rule 13a-15(f) under the Exchange Act) for Edison International. Under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, Edison International’s management conducted an evaluation of the effectiveness of Edison International’s internal control over financial reporting based on the framework set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under the COSO framework, Edison International’s management concluded that Edison International’s internal control over financial reporting was effective as of December 31, 2007. Edison International’s internal controls over financial reporting as of December 31, 2007 have been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report on the financial statements in Edison International’s Annual Report, which is incorporated herein by this reference.

 

Changes in Internal Controls

 

There were changes as described below in EME’s internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably likely to materially affect EME’s and Edison International’s internal control over financial reporting.

 

During 2007, EME implemented a series of SAP ERP modules, including the general ledger, chart of accounts, new consolidation, reporting and accounts payable. In addition, procurement and materials management and fuel management systems were implemented at the Illinois Plants and the Homer City facilities. The introduction of these ERP modules and the related workflow capabilities resulted in changes to EME’s financial reporting controls and procedures, with such changes identified during the implementation of the ERP modules. EME has modified the design and documentation of internal control processes and procedures relating to the new system to supplement and complement existing internal controls over financial reporting. The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in EME’s internal control over financial reporting.

 

None.

 

PART III

 

 

Information concerning executive officers of Edison International is set forth in Part I in accordance with General Instruction G(3), pursuant to Instruction 3 to Item 401(b) of Regulation S-K. Other information responding to Item 10 will appear in Edison International’s definitive Proxy Statement to be filed with the SEC in connection with Edison International’s Annual Shareholders’ Meeting to be held on April 24, 2008, under the headings “Election of Directors, Nominees for Election,” and “Board Committees and Subcommittees,” and is incorporated herein by this reference.

 

The Edison International Ethics and Compliance Code is applicable to all Directors, officers and employees of Edison International and its majority-owned subsidiaries. The Code is available on Edison International’s Internet website at www.edisonethics.com and is available in print without charge upon request from the Edison International Corporate Secretary. Any amendments or waivers of Code provisions for the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, will be posted on Edison International’s Internet website at www.edisonethics.com.

 

 

Information responding to Item 11 will appear in the Proxy Statement under the headings “Compensation Discussion and Analysis,” “Compensation Committees’ Report,” “Compensation Committees’ Interlocks and Insider Participation,” “Summary Compensation Table — Fiscal 2007,” “Grants of Plan-Based Awards in Fiscal 2007,” “Outstanding Equity Awards at Fiscal 2007 Year-End,” “Option Exercises and Stock Vested in Fiscal 2007,” “Pension Benefits,” “Non-qualified Deferred Compensation,” “Potential Payments Upon Termination or Change in Control,” and “Director Compensation” and is incorporated herein by this reference.

 

 

Information responding to Item 12 will appear in the Proxy Statement under the headings “Stock Ownership of Directors and Executive Officers,” and “Stock Ownership of Certain Shareholders,” and is incorporated herein by this reference.

Equity Compensation Plans

 

The following table provides information as of December 31, 2007, for compensation plans under which equity securities may be issued:

 

 

 

 

 

Information responding to Item 13 will appear in the Proxy Statement under the headings “Certain Relationships and Related Transactions,” and “Questions and Answers on Corporate Governance — Q: How do the Edison International and SCE Boards determine which Directors are considered independent? and — Q: Which Directors have the Edison International and SCE Boards determined are independent?” and is incorporated herein by this reference.

 

 

Information responding to Item 14 will appear in the Proxy Statement under the heading “Independent Registered Public Accounting Firm Fees,” and is incorporated herein by this reference.

 

The following items contained in the Annual Report are found on pages 6 through 174, and are incorporated herein by this reference to Exhibit 13 to this Annual Report on Form 10-K.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Management’s Responsibility for Financial Reporting

 

Management’s Report on Internal Control Over Financial Reporting

 

Report of Independent Registered Public Accounting Firm

 

Consolidated Statements of Income — Years Ended December 31, 2007, 2006 and 2005

 

Consolidated Statements of Comprehensive Income — Years Ended December 31, 2007, 2006 and 2005

 

Consolidated Balance Sheets — December 31, 2007 and 2006

 

Consolidated Statements of Cash Flows — Years Ended December 31, 2007, 2006 and 2005

 

Consolidated Statements of Changes in Common Shareholders’ Equity — Years Ended December 31, 2007, 2006 and 2005

 

Notes to Consolidated Financial Statements

 

 

The following documents may be found in this report at the indicated page numbers:

 

 

See “Exhibit Index” beginning on page 63 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 February 27, 2008 appearing in the 2007 Annual Report to Shareholders of Edison International (which report and consolidated financial statements and assessment 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

 

February 27, 2008

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

 

 

CONDENSED BALANCE SHEETS

 

EDISON INTERNATIONAL

 

 

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

 

CONDENSED STATEMENTS OF INCOME

 

For the Years Ended December 31, 2007, 2006 and 2005

 

EDISON INTERNATIONAL

 

 

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT

 

CONDENSED STATEMENTS OF CASH FLOWS

 

For the Years Ended December 31, 2007, 2006 and 2005

 

EDISON INTERNATIONAL

 

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

 

For the Year Ended December 31, 2007

 

 

EDISON INTERNATIONAL

 

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

 

For the Year Ended December 31, 2006

 

 

EDISON INTERNATIONAL

 

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

 

For the Year Ended December 31, 2005