SOUTHERN CALIFORNIA EDISON Co - Annual Report: 2007 (Form 10-K)

 

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

FORM 10-K

 

Commission File Number 1-2313

SOUTHERN CALIFORNIA EDISON COMPANY

(Exact name of registrant as specified in its charter)

 

 

 

(626) 302-1212

(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 x  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 x

 

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 x  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.  x

 

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 “accelerated filer,” “large accelerated filer,” and “smaller reporting company” in Rule 12b-12 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 x

 

As of February 22, 2008, there were 434,888,104 shares of Common Stock outstanding, all of which are held by the registrant’s parent holding company. The aggregate market value of registrant’s voting and non-voting common equity held by non-affiliates was zero. As of February 22, 2008, there were 434,888,104 shares of Common Stock outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

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

 

 

 

TABLE OF CONTENTS

 

 

 

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 SCE’s current expectations and projections about future events based on SCE’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 SCE 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 SCE 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 SCE’s business. Forward-looking statements speak only as of the date they are made and SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE with the SEC.

 

Glossary

 

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

 

 

Glossary (Continued)

 

 

 

Glossary (Continued)

 

 

 

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. Edison International owns all of the common stock of SCE. Except when otherwise stated, references to SCE mean SCE together with its subsidiaries on a consolidated basis.

 

Information about SCE is available on the internet website maintained by Edison International at
http://www.edisoninvestor.com. SCE makes available, free of charge on that 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 Securities Exchange Act of 1934, as soon as reasonably practicable after SCE 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.

 

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.

 

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. SCE believes that it has taken all steps to be compliant with current NERC reliability standards. SCE 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.

 

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 “Regulatory Matters” and in this section under the subheading “— Competition.”

 

SCE is subject to the jurisdiction of the Nuclear Regulatory Commission with respect to its nuclear power plants. The United States Nuclear Regulatory Commission 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 CARB, and local air pollution control districts with respect to the emission of pollutants into the atmosphere; the regulatory requirements of the California State Water Resources Control Board and regional boards with respect to the discharge of pollutants into waters of the state; and the requirements of the California Department of Toxic Substances Control with respect to handling and disposal of hazardous materials and wastes. SCE is also subject to regulation by the US EPA, which administers 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 location and other 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 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, the California Department of Fish and Game; Regional Water Quality Controls 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 Americans 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 approval 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. 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.

 

In addition, the CPUC has issued affiliate transaction rules governing the relationships between SCE and its affiliates, including its nonutility subsidiaries. SCE has filed compliance plans which set forth SCE’s implementation of the CPUC’s affiliate transaction rules. The rules and compliance plans are intended to maintain separateness between utility and nonutility activities and ensure that utility assets are not used to subsidize the activities of nonutility affiliates.

 

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 888 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 operational 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.

 

The principal environmental laws and regulations affecting SCE’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 GHGs 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 hexaflouride (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 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.

 

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.

 

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 “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.

 

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.

 

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.”

 

Response to Climate Change Initiatives

 

SCE has devoted substantial effort to develop expertise and infrastructure in areas such as energy efficiency 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 similar federal and state and regulations implementing such statutes apply to plants owned by SCE as well as to plants from which SCE 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 Act 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 NO_x 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.

 

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.

 

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 NO_x 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. Edison International and SCE are assessing the impact of this decision on the regulations in California, 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.

 

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.

 

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 included both the filing of suits against a number of power plant owners, and the issuance of administrative NOVs to a number of power plant owners alleging NSR violations. 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, SCE anticipates that no such further emission reduction obligations will be imposed under the new rule until 2015.

 

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

 

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 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

 

Regulations under the federal Clean Water Act require permits for the discharge of pollutants into United States waters and permits for the discharge of storm water flows from certain facilities. The Clean Water Act also regulates the thermal component (heat) of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities. California has a US EPA approved program to issue individual or group (general) permits for the regulation of Clean Water Act discharges. California also regulates certain discharges not regulated by the US EPA.

 

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. 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.

 

All of SCE’s revenue for the last three fiscal years is attributed to SCE’s country of domicile, the United States. All of SCE’s assets are located in the United States.

 

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

 

SCE is subject to extensive environmental regulation and permitting requirements that involve significant and increasing costs. SCE devotes 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 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 SCE conducts business. 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 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 CEC (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 CARB, 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.

 

None.

 

The principal properties of SCE are described above in Part I under the heading “Properties.”

 

Catalina South Coast Air Quality Management District Potential Environmental Proceeding

 

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 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.”

 

Information about the Navajo Nation litigation appears in the MD&A under the heading “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 (General Instruction) G(3), the following information is included as an additional item in Part I:

 

 

None of SCE’s executive officers is related to each other by blood or marriage. 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 have been actively engaged in the business of SCE, Edison International and/or the nonutility company affiliates of SCE for more than five years, except for Mr. House, 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:

 

 

Certain information responding to Item 5 with respect to frequency and amount of cash dividends is included in the Annual Report, under Quarterly Financial Data on page 103 and is incorporated herein by this reference. As a result of the formation of a holding company described above in Item 1, all of the issued and outstanding common stock of SCE is owned by Edison International and there is no market for such stock.

 

Item 201(d) of Regulation S-K, “Securities Authorized For Issuance Under Equity Compensation Plans,” is not applicable because SCE has no compensation plans under which equity securities of SCE are authorized for issuance.

 

Information responding to Item 6 is included in the Annual Report under “Selected Financial Data: 2003 — 2007” on page 104, and is incorporated herein by reference.

 

Information responding to Item 7 is included in the Annual Report on pages 4 through 48 and is incorporated herein by this reference.

 

Information responding to Item 7A is included in the MD&A under the headings “SCE: Market Risk Exposures” on pages 31 through 34.

 

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 51 through 55 and is incorporated herein by this reference.

 

None.

 

Disclosure Controls and Procedures

 

SCE’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 SCE’s disclosure controls and procedures (as that term is defined in Rules 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, SCE’s disclosure and procedures are effective.

 

Management’s Report on Internal Control Over Financial Reporting

 

SCE’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 SCE. Under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, SCE’s management conducted an evaluation of the effectiveness of SCE’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, SCE’s management concluded that SCE’s internal control over financial reporting was effective as of December 31, 2007.

 

Change in Internal Control Over Financial Reporting

 

There were no changes in SCE’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the fiscal quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, SCE’s internal control over financial reporting.

 

SCE has not designed, established, or maintained internal control over financial reporting for four variable interest entities, referred to as “VIEs,” that SCE was required to consolidate under an accounting interpretation issued by the Financial Accounting Standards Board. SCE’s evaluation of internal control over financial reporting does not include these VIEs.

 

This Annual Report on Form 10-K does not include an attestation report of SCE’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SCE’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit SCE to provide only management’s report in this Annual Report on Form 10-K.

 

None.

 

Information concerning executive officers of SCE 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 SCE’s definitive Proxy Statement to be filed with the SEC in connection with SCE’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, including SCE. 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 SCE Corporate Secretary. Any amendments or waivers of Code provisions for SCE’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.

 

Item 201(d) of Regulation S-K, “Securities Authorized For Issuance Under Equity Compensation Plans,” is not applicable because SCE has no compensation plans under which equity securities of SCE are authorized for issuance.

 

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 — Is SCE subject to the same stock exchange listing standards regarding corporate governance matters as Edison International?, — 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.

 

(a)(1) Financial Statements

 

The following items contained in the Annual Report are found on pages 4 through 103, 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

 

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

 

(a)(2) Report of Independent Registered Public Accounting Firm and Schedules Supplementing

 

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

 

 

Schedules I and III through V, inclusive, are omitted as not required or not applicable.

 

(a)(3) Exhibits

 

See Exhibit Index beginning on page 32 of this report.

 

SCE will furnish a copy of any exhibit listed in the accompanying Exhibit Index upon written request and upon payment to SCE 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.

 

To the Board of Directors

of Southern California Edison Company

 

Our audits of the consolidated financial statements referred to in our report dated February 27, 2008, appearing in the 2007 Annual Report of Southern California Edison Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedules listed in Item 15(a)(2) of this Form 10-K. In our opinion, these financial statement schedules present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

 

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

February 27, 2008

Southern California Edison Company

 

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

 

For the Year Ended December 31, 2007

 

 

(a) Accounts written off, net.

Southern California Edison Company

 

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

 

For the Year Ended December 31, 2006

 

 

(a) Accounts written off, net.

Southern California Edison Company

 

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

 

For the Year Ended December 31, 2005

 

 

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

SOUTHERN CALIFORNIA EDISON COMPANY

 

LINDA G. SULLIVAN

Vice President and Controller

Date: February 27, 2008

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

 

 

Date: February 27, 2008