UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Securities registered pursuant to Section 12(b) of the Act:
(Mark One) | |
R | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2012 | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to | |
Commission File Number | Exact Name of Registrant as specified in its charter | State or Other Jurisdiction of Incorporation or Organization | IRS Employer Identification Number | |||
1-9936 | EDISON INTERNATIONAL | California | 95-4137452 | |||
1-2313 | SOUTHERN CALIFORNIA EDISON COMPANY | California | 95-1240335 | |||
EDISON INTERNATIONAL | SOUTHERN CALIFORNIA EDISON COMPANY | |
2244 Walnut Grove Avenue (P.O. Box 976) Rosemead, California 91770 (Address of principal executive offices) | 2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California 91770 (Address of principal executive offices) | |
(626) 302-2222 (Registrant's telephone number, including area code) | (626) 302-1212 (Registrant's telephone number, including area code) | |
Title of each class | Name of each exchange on which registered | |
Edison International: Common Stock, no par value | NYSE LLC | |
Southern California Edison Company: Cumulative Preferred Stock | NYSE MKT LLC | |
4.08% Series, 4.24% Series, 4.32% Series, 4.78% Series | ||
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.
Edison International Yes þ No o Southern California Edison Company 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.
Edison International Yes ¨ No þ Southern California Edison Company Yes ¨ 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.
Edison International Yes þ No o Southern California Edison Company Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Edison International Yes þ No o Southern California Edison Company 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.
Edison International þ Southern California Edison Company þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
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): | ||||
Edison International | Large Accelerated Filer þ | Accelerated Filer ¨ | Non-accelerated Filer ¨ | Smaller Reporting Company ¨ |
Southern California Edison Company | Large Accelerated Filer ¨ | Accelerated Filer ¨ | Non-accelerated Filer þ | Smaller Reporting Company ¨ |
Edison International Yes ¨ No þ Southern California Edison Company Yes ¨ No þ
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2012, the last business day of the most recently completed second fiscal quarter:
Edison International Approximately $15 billion Southern California Edison Company Wholly owned by Edison International
Common Stock outstanding as of February 22, 2013: | ||
Edison International | 325,811,206 shares | |
Southern California Edison Company | 434,888,104 shares (wholly owned by Edison International) | |
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents listed below have been incorporated by reference into the parts of this report so indicated.
(1) Designated portions of the Proxy Statement relating to registrant's joint 2013 Annual Meeting of Shareholders Part I
TABLE OF CONTENTS
Coal Combustion Residuals | ||||
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Environmental Developments | ||||
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This is a combined Form 10-K separately filed by Edison International and Southern California Edison Company. Information contained herein relating to an individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.
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GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
2012 Form 10-K | Edison International's Annual Report on Form 10-K for the year-ended December 31, 2012 | |
2010 Tax Relief Act | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
APS | Arizona Public Service Company | |
ARO(s) | asset retirement obligation(s) | |
BACT | best available control technology | |
Bankruptcy Code | Chapter 11 of the United States Bankruptcy Code | |
Bankruptcy Court | United States Bankruptcy Court for the Northern District of Illinois, Eastern Division | |
Bcf | billion cubic feet | |
Big 4 | Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects | |
CAA | Clean Air Act | |
CAISO | California Independent System Operator | |
CARB | California Air Resources Board | |
CDWR | California Department of Water Resources | |
CEC | California Energy Commission | |
Competitive Businesses | competitive businesses related to the delivery and use of electricity | |
CPUC | California Public Utilities Commission | |
CRRs | congestion revenue rights | |
DOE | U.S. Department of Energy | |
EME | Edison Mission Energy | |
EMG | Edison Mission Group Inc. | |
EPS | earnings per share | |
ERRA | energy resource recovery account | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FIP(s) | federal implementation plan(s) | |
Four Corners | coal fueled electric generating facility located in Farmington, New Mexico in which SCE holds a 48% ownership interest | |
GAAP | generally accepted accounting principles | |
GHG | greenhouse gas | |
Global Settlement | A settlement between Edison International and the IRS that resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002 and related matters with state tax authorities. | |
GRC | general rate case | |
GWh | gigawatt-hours | |
IRS | Internal Revenue Service | |
ISO | Independent System Operator | |
kWh(s) | kilowatt-hour(s) | |
MD&A | Management's Discussion and Analysis of Financial Condition and Results of Operations in this report | |
MHI | Mitsubishi Heavy Industries, Inc. | |
Mohave | two coal fueled electric generating facilities that no longer operate located in Clark County, Nevada in which SCE holds a 56% ownership interest | |
Moody's | Moody's Investors Service | |
MW | megawatts | |
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MWh | megawatt-hours | |
NAAQS | national ambient air quality standards | |
NERC | North American Electric Reliability Corporation | |
Ninth Circuit | U.S. Court of Appeals for the Ninth Circuit | |
NRC | Nuclear Regulatory Commission | |
NSR | New Source Review | |
Palo Verde | large pressurized water nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest | |
PBOP(s) | postretirement benefits other than pension(s) | |
Petition Date | December 17, 2012 (date on which EME and certain wholly-owned subsidiaries filed for protection under Chapter 11 of the Bankruptcy Code) | |
PG&E | Pacific Gas & Electric Company | |
PSD | Prevention of Significant Deterioration | |
QF(s) | qualifying facility(ies) | |
ROE | return on equity | |
S&P | Standard & Poor's Ratings Services | |
San Onofre | large pressurized water nuclear electric generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest | |
SCE | Southern California Edison Company | |
SCR | selective catalytic reduction equipment | |
SDG&E | San Diego Gas & Electric | |
SEC | U.S. Securities and Exchange Commission | |
SED | Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or CPSD | |
Settlement Transaction | Certain transactions related to EME's Chapter 11 bankruptcy filing that the parties to the Support Agreement have by virtue of that agreement agreed to further document and support | |
Support Agreement | Transaction Support Agreement dated as of December 16, 2012 by and among Edison Mission Energy, Edison International and the Noteholders named therein | |
US EPA | U.S. Environmental Protection Agency | |
VIE(s) | variable interest entity(ies) | |
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FORWARD-LOOKING STATEMENTS
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 and SCE'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 and 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. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact Edison International and SCE, include, but are not limited to:
• | cost of capital and the ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms; |
• | ability of SCE to recover its costs in a timely manner from its customers through regulated rates; |
• | decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions; |
• | possible customer bypass or departure due to technological advancements or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable; |
• | risks inherent in the construction of transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable the acceptance of power delivery), and governmental approvals; |
• | risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts; |
• | risk that Unit 2 and/or Unit 3 at San Onofre may not recommence operations or may require extensive repairs or replacement of the steam generators; with the cost of the related outcome not being recoverable from SCE's supplier, insurance coverage or through regulatory processes; |
• | cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs to replace power and voltage support that would have been provided by San Onofre but for the current outage or in the event of other power plant outages or significant counterparty defaults under power-purchase agreements; |
• | environmental laws and regulations, at both the state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business; |
• | failure of the Bankruptcy Court to approve the Settlement Transaction related to the EME bankruptcy, which would impact the anticipated benefits to Edison International from the Settlement Transaction; |
• | changes in the fair value of investments and other assets; |
• | changes in interest rates and rates of inflation, including escalation rates, which may be adjusted by public utility regulators; |
• | governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by the California Independent System Operator, Regional Transmission Organizations, and adjoining regions; |
• | availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations; |
• | cost and availability of labor, equipment and materials; |
• | ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance or in the absence of insurance the ability to recover uninsured losses; |
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• | effects of legal proceedings, changes in or interpretations of tax laws, rates or policies; |
• | potential for penalties or disallowances caused by non-compliance with applicable laws and regulations; |
• | cost and availability of fuel for generating facilities and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts; |
• | cost and availability of emission credits or allowances for emission credits; |
• | transmission congestion in and to each market area and the resulting differences in prices between delivery points; |
• | ability to provide sufficient collateral in support of hedging activities and power and fuel purchased; |
• | risk that competing transmission systems will be built by merchant transmission providers in SCE's service area; and |
• | weather conditions and natural disasters. |
See "Risk Factors" in Part I, Item 1A of this report for additional information on risks and uncertainties that could cause results to differ from those currently expected or that otherwise could impact Edison International, SCE or their subsidiaries.
Additional information about risks and uncertainties, including more detail about the factors described in this report, is contained throughout this report. 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 and SCE's businesses. Forward-looking statements speak only as of the date they are made and neither Edison International nor SCE are obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International and SCE with the SEC.
Except when otherwise stated, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to "Edison International Parent and Other" mean Edison International Parent and its consolidated non-utility subsidiaries.
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PART I
ITEM 1. BUSINESS
INTRODUCTION
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 subsidiaries that are competitive businesses related to the delivery or use of electricity (the "Competitive Businesses"). As a holding company, Edison International's progress and outlook are dependent on developments at its operating subsidiaries.
The principal executive offices of Edison International and SCE are located at 2244 Walnut Grove Avenue, P.O. Box 976, Rosemead, California 91770, and the telephone numbers are (626) 302-2222 for Edison International and (626) 302-1212 for SCE.
This is a combined Annual Report on Form 10-K for Edison International and SCE. Edison International and SCE make available at www.edisoninvestor.com: Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statements and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, as soon as reasonably practicable after Edison International and SCE electronically file such material with, or furnishes it to, the SEC. Such reports are also available on the SEC's internet website at www.sec.gov. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.
Subsidiaries of Edison International
SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000 square-mile area of southern California. The SCE service territory contains a population of nearly 14 million people and SCE serves the population through approximately 5 million customer accounts. In 2012, SCE's total operating revenue of $11.9 billion was derived as follows: 41.4% commercial customers, 42.2% residential customers, 5.5% industrial customers, 0.5% resale sales, 5.2% public authorities, and 5.2% agricultural and other customers. Sources of energy to serve SCE's customers during 2012 were approximately: 75% purchased power and 25% SCE-owned generation.
Prior to December 17, 2012, Edison International had a competitive power generation segment (EMG), the majority of which consisted of its indirectly, wholly-owned subsidiary, EME. EME is a holding company with subsidiaries and affiliates engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. On December 17, 2012 (the "Petition Date"), EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (the "Bankruptcy Code") in the United States Bankruptcy Court for the Northern District of Illinois, Eastern Division (the "Bankruptcy Court"). The EME companies that filed for bankruptcy retained control of their assets and are authorized to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court. The factors that led EME and certain of its wholly owned subsidiaries to take this action are discussed in the MD&A and in Note 17 of Item 8. Notes to Consolidated Financial Statements. As a result of the bankruptcy filing and beginning on the Petition Date, Edison International determined that it no longer retains significant influence over EME and accordingly, EME's results of operations are no longer consolidated with those of Edison International. Additionally, EME's results of operations prior to December 17, 2012 and for prior periods, are reflected as discontinued operations in the consolidated financial statements and Edison International now accounts for its investment in EME using the cost method of accounting prospectively.
EME, Edison International and certain of EME's senior unsecured noteholders have entered into a Transaction Support Agreement dated December 16, 2012 (the “Support Agreement”) in which each party agrees, subject to certain conditions, to further document and support Bankruptcy Court approval of certain transactions (collectively, the “Settlement Transaction”), including Edison International's ceasing to have any continuing ownership interest in EME following effectiveness of a plan of reorganization. For further information regarding the Support Agreement and Settlement Transaction, see "Management Overview—EME Chapter 11 Bankruptcy Filing" in the MD&A.
Edison International continues to see merit in the ownership and operation of Competitive Businesses as a matter of corporate strategy and is exploring business ventures in a number of areas related to the provision of electric power and infrastructure, including distributed generation, electrification of transportation, water purification, and power management services to the commercial and industrial sector. Edison International has several subsidiaries that have been formed to hold assets, equity interests and businesses in emerging sectors of the electricity industry. To date, the holdings of these subsidiaries are not material for financial reporting purposes.
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Regulation of Edison International as a Holding Company
Edison International and its subsidiaries are subject to extensive regulation. As a public utility holding company, Edison International is subject to the Public Utility Holding Company Act. The Public Utility Holding Company Act primarily obligates Edison International and its utility subsidiaries to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.
Edison International is not a public utility and its capital structure is not regulated by the CPUC. The 1988 CPUC decision authorizing SCE to reorganize into a holding company structure, however, contains certain obligations on Edison International and its affiliates. These obligations include a requirement 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 deemed to be necessary to meet SCE's service obligations, shall receive first priority from the Boards of Directors of Edison International and SCE. The CPUC has also promulgated Affiliate Transaction Rules, which, among other requirements, prohibit holding companies from (1) being used as a conduit to provide non-public information to a utility's affiliate and (2) causing or abetting a utility's violation of the rules, including providing preferential treatment to affiliates.
Employees
At December 31, 2012, Edison International and its consolidated subsidiaries had an aggregate of 16,593 full-time employees, 16,515 of which are full-time employees at SCE.
Insurance
Edison International maintains a property and casualty insurance program for itself and its subsidiaries and excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations. These policies are subject to specific retentions, sub-limits and deductibles, which are comparable to those carried by other utility and electric generating companies of similar size. SCE also has separate insurance programs for nuclear property and liability, workers compensation and solar rooftop construction. For further information on nuclear and wildfire insurance, see "Item 8. Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
SOUTHERN CALIFORNIA EDISON COMPANY
Regulation
CPUC
The CPUC has the authority to regulate, among other things, retail rates, energy purchases on behalf of retail customers, rate of return, issuance of securities, disposition of utility assets and facilities, oversight of nuclear decommissioning funding and costs, and aspects of the transmission system planning, site identification and construction.
FERC
The FERC has the authority to regulate wholesale rates as well as other matters, including unbundled transmission service pricing, accounting practices, and licensing of hydroelectric projects. The FERC also has jurisdiction over a portion of the retail rates and associated rate design.
NERC
The FERC assigned administrative responsibility to the NERC to establish and enforce reliability standards and critical infrastructure protection standards, which protect the bulk power system against potential disruptions from cyber and physical security breaches. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with these standards is mandatory. The maximum penalty that may be levied for violating a NERC reliability or critical infrastructure protection standard is $1 million per violation, per day.
SCE has a formal cyber security program that is staffed and has a dedicated budget. The program covers SCE's information technology systems as well as supervisory control and data acquisition systems for the electric grid. Program staff is engaged with industry groups as well as public-private initiatives to reduce risk and to strengthen the security and reliability of SCE's systems and infrastructure. The program is also engaged in the protection of SCE's customer information.
Transmission and Substation Facilities Regulation
The construction, planning and project site identification of SCE's transmission lines and substation facilities require the approval of many governmental agencies and compliance with various laws. These agencies include utility regulatory commissions such as the CPUC and other state regulatory agencies depending on the project location; the CAISO, and other
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environmental, land management and resource agencies such as the Bureau of Land Management, the U.S. Forest Service, and the California Department of Fish and Game; and regional water quality control boards. 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 are also necessary for the project to proceed.
CEC
The construction, planning, and project site identification of SCE's power plants (excluding solar and hydro plants) of 50 MW or greater within California are subject to the jurisdiction of the CEC. The CEC is also responsible for forecasting future energy needs. These forecasts are used by the CPUC in determining the adequacy of SCE's electricity procurement plans.
Nuclear Power Plant Regulation
SCE is subject to the jurisdiction of the NRC with respect to the safety of its San Onofre and Palo Verde Nuclear Generating Stations. The NRC regulates commercial nuclear power plants through licensing, oversight and inspection, performance assessment, and enforcement of its requirements. For further information, see "Management Overview—San Onofre Outage, Inspection and Repair Issues" in the MD&A.
Operating License Renewal
In April 2011, the NRC extended the operating license for Palo Verde Operating Units 1, 2 and 3 for an additional 20 years, to 2045, 2046 and 2047, respectively. San Onofre's current operating licenses for Units 2 and 3 will expire in 2022. The NRC's review of a license renewal application typically takes three to five years. Prior to filing a license renewal application at the NRC, SCE would make an application to the CPUC to demonstrate the cost effectiveness of continuing operations at San Onofre and to seek authority to recover the cost of seeking a license renewal at the NRC and pursuing approvals from other state and federal agencies, such as the Department of the Navy and the California Coastal Commission. SCE has made no decision to seek license renewal or to file an application for cost recovery at the CPUC. If SCE were to choose not to pursue license renewal or if SCE' efforts to obtain license renewal were not successful, SCE will need to determine what generation and transmission alternatives would need to be made available to replace the capacity, energy, and grid reliability benefits that SCE's customers now receive from San Onofre by the time San Onofre ceases generating electricity. Should SCE decide to pursue a license renewal for San Onofre, SCE will likely need to simultaneously consider generation and transmission alternatives given the long lead times for the NRC to approve a license renewal and to site, permit and construct new generation and transmission facilities. The costs of these alternatives could be substantial. SCE completed several transmission upgrades to ensure grid reliability with San Onofre not operating during the summer of 2012 and is currently pursuing additional transmission upgrades should San Onofre not operate during the summer of 2013.
Overview of Ratemaking Process
CPUC
Revenue authorized by the CPUC through triennial GRC proceedings is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investments in generation and distribution assets and general plant (also referred to as “rate base”). The CPUC sets an annual revenue requirement for the base year which is made up of the operation and maintenance costs, taxes and a return consistent with the capital structure (discussed below). The return is established by multiplying an authorized rate of return, determined in separate cost of capital proceedings, by SCE's authorized CPUC rate base. In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecast basis. Following the base year, the revenue requirements for the remaining two years are set by a methodology established in the GRC proceeding, which generally, among other items, includes annual allowances for escalation in operation and maintenance costs, additional changes in capital-related investments and the recovery for expected nuclear refueling outages.
SCE's authorized revenue requirements for 2009, 2010, and 2011 were $4.8 billion, $5.0 billion, and $5.3 billion, respectively. In November 2012, the CPUC approved a decision authorizing a revenue requirement of approximately $5.7 billion for 2012 and a formula that would result in authorized revenue requirements of approximately $5.8 billion and $6.2 billion for 2013 and 2014, respectively. For further discussion of the 2012 GRC, see “Management Overview—2012 CPUC General Rate Case” in the MD&A.
CPUC rates decouple authorized revenue from the volume of electricity sales so that SCE earns revenue equal to amounts authorized. Differences between amounts collected and authorized levels are either collected from or refunded to customers, and, therefore, such differences do not impact operating revenue. Accordingly, SCE is neither benefited nor burdened by the volumetric risk related to retail electricity sales.
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The CPUC regulates SCE's capital structure and authorized rate of return. SCE's current authorized capital structure is 48% common equity, 43% long-term debt and 9% preferred equity. SCE's current authorized cost of capital, as authorized by the CPUC in December 2012 as part of the 2013 Cost of Capital Application, consists of: cost of long-term debt of 5.49%, cost of preferred equity of 5.79% and return on common equity of 10.45%. These costs were implemented in rates effective January 1, 2013. For further discussion of the 2013 Cost of Capital Application, see “Management Overview—2013 Cost of Capital Application” in the MD&A.
Balancing accounts (also referred to as cost-recovery mechanisms) are typically used to track and recover SCE's costs of fuel, purchased-power, and certain operation and maintenance expenses, including certain demand-side management program costs. SCE earns no return on these activities and although differences between forecasted and actual costs do not impact earnings, such differences do impact cash flows and can change rapidly.
SCE's balancing account for fuel and power procurement-related costs is referred to as the ERRA mechanism. SCE sets rates based on an annual forecast of the costs that it expects to incur during the subsequent year. In addition, the CPUC has established a "trigger" mechanism for the ERRA balancing account that allows for a rate adjustment if the balancing account over- or under-collection exceeds 5% of SCE's prior year's revenue that is classified as generation for retail rates. For 2013, the trigger amount is approximately $280 million.
The majority of procurement-related costs eligible for recovery through cost-recovery rates are effectively pre-approved by the CPUC through a procurement plan with predefined standards that establish the eligibility for cost recovery. If such costs are subsequently found to be non-compliant with this procurement plan, then this could negatively impact SCE's earnings and cash flows. In addition, the CPUC retrospectively reviews outages associated with utility-owned generation and SCE's power procurement contract administration activities through the annual ERRA review proceeding. If SCE is found to be unreasonable or imprudent with respect to its utility-owned generation outages and contract administration activities, then this could negatively impact SCE's earnings and cash flows.
FERC
Revenue authorized by the FERC is intended to provide SCE with recovery of its prudently-incurred transmission costs, including a return on its net investment in transmission assets. In August 2011, the FERC accepted, subject to refund and settlement procedures, SCE's request to implement a formula rate effective January 1, 2012 to determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP") revenue requirement that was previously recovered through a separate mechanism. Under operation of the formula rate, transmission revenue will be trued-up to actual cost of service annually. At December 31, 2012, revenue collected in excess of recognized revenue under the proposed formula rate was $106 million. Under the formula rate, the transmission revenue requirement and rates are updated each October 1, to reflect a forecast of costs for the upcoming rate period, as well as a true up of costs incurred by SCE in the prior calendar year. Settlement discussions regarding the formula rate are ongoing. In September 2012, SCE filed its first formula rate update with the FERC. For further discussion of SCE's FERC formula rates, see “Liquidity and Capital Resources—SCE—Regulatory Proceedings—FERC Formula Rates” in the MD&A.
Retail Rates Structure
To develop retail rates, the authorized revenue requirements are allocated among all customer classes (residential, commercial, industrial and agricultural) on a functional basis (i.e., generation, distribution, transmission, etc.). Specific rate components are designed to recover the authorized revenue allocated to each customer class.
Currently, SCE has a five tier residential rate structure. Each tier represents a certain electricity usage level and within each increasing usage level, the electricity is priced at a higher rate per kilowatt hour. The first tier is a baseline tier and has the lowest rate per kilowatt hour. "Baseline" refers to a specific amount of energy allocated for residential customers that is charged at a lower price than energy used in excess of that amount. Baseline quantities are determined by SCE for approval by the CPUC using average residential electricity consumption for nine geographical regions in southern and central California.
The intent of the baseline and the tiered structure is to provide a portion of reasonable energy needs (baseline usage) of residential customers at the lowest rate, and to encourage conservation of energy by increasing the rate charged as energy usage increases. Statutory restrictions on tier one and two rates have shifted some of the cost of residential rate increases to the higher tier/usage customers. As part of the second phase of SCE's 2012 GRC, SCE requested certain rate design modifications that are intended to provide a more equitable, cost-based rate design. A decision in the second phase is expected in the first half of 2013.
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Energy Efficiency Incentive Mechanism
In December 2012, the CPUC adopted an energy efficiency incentive mechanism for the 2010 – 2012 energy efficiency program performance period. The mechanism uses an incentive calculation that is based on actual energy efficiency expenditures. The December 2012 CPUC decision provided shareholder earnings for the 2010 program performance period and allows SCE the opportunity to claim future shareholder earnings in both 2013 and 2014 associated with SCE's 2011 and 2012 program performance periods using this incentive calculation. A proposed decision on the mechanism for the 2013 – 2014 program years is expected in the first quarter of 2013. For further discussion of SCE's energy efficiency incentive awards for 2010, 2011 and 2012, see “Liquidity and Capital Resources—SCE—Regulatory Proceedings—Energy Efficiency Incentive Mechanism” in the MD&A.
CDWR-Related Rates
As a result of the California energy crisis, in 2001 the CDWR entered into contracts to purchase power for sale at cost directly to SCE's retail customers and issued bonds to finance those power purchases. The CDWR's total statewide power and bond charge revenue requirements were allocated by the CPUC among the customers of the investor-owned utilities (SCE, PG&E and SDG&E). SCE billed and collected from its customers the costs of power purchased and sold by the CDWR. All CDWR power contracts that were allocated to SCE expired by the end of 2011. SCE will continue to bill and collect CDWR bond-related charges and direct access exit fees until 2022. The CDWR-related charges and a portion of direct access exit fees that are remitted directly to the CDWR are not recognized as operating revenue; but affect customer rates. See "Results of Operations—SCE—Supplemental Operating Revenue Information" in the MD&A for further discussion of the impact of CDWR charges on customer rates.
Purchased Power and Fuel Supply
SCE obtains power needed to serve its customers from its generating facilities and purchases from qualifying facilities, independent power producers, the CAISO, and other utilities.
Natural Gas Supply
SCE requires natural gas to meet contractual obligations for power tolling agreements (power contracts in which SCE has agreed to provide or pay for the natural gas burned to generate electricity). SCE also requires natural gas to fuel its Mountainview and peaker plants, which are generation units that are designed to operate in response to changes in demand for power. The physical natural gas purchased by SCE is subject to competitive bidding.
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. These arrangements are under review as a result of events at San Onofre. For more information, see "Management Overview—San Onofre Outage, Inspection and Repair Issues" in the MD&A.
Uranium concentrates | 2020 |
Conversion | 2020 |
Enrichment | 2020 |
Fabrication | 2015 |
For Palo Verde, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below.
Uranium concentrates | 2018 |
Conversion | 2018 |
Enrichment | 2020 |
Fabrication | 2016 |
Coal Supply
On January 1, 2010, SCE and the other Four Corners co-owners entered into a Four Corners Coal Supply Agreement with the BHP Navajo Coal Company, to supply coal to Four Corners Units 4 and 5 until July 6, 2016. In November 2010, SCE entered into an agreement to sell its interest in Four Corners to APS, subject to certain conditions including securing a long-term fuel
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supply agreement for the plant that extends beyond 2016. See "Item 8. Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for more information on the pending sale of SCE's interest in Four Corners. In December 2012, BHP Navajo Coal Company and the Navajo Nation announced that they are in negotiations to transfer ownership of the coal mining operation that supplies Four Corners. The Four Corners co-owners (other than SCE), BHP Navajo Coal Company and the Navajo Nation are currently negotiating a potential new Coal Supply Agreement for Four Corners to extend beyond 2016.
CAISO Wholesale Energy Market
In California and other states, wholesale energy markets exist through which competing electricity generators offer their electricity output to electricity retailers. Each state's wholesale electricity market is generally operated by its state ISO or a regional RTO. California's wholesale electricity market is operated by the CAISO. The CAISO schedules power in hourly increments with hourly prices through a real-time and day-ahead market that combines energy, ancillary services, unit commitment and congestion management. SCE participates in the day-ahead and real-time markets for the sale of its generation and purchases of its load requirements.
The CAISO uses a nodal locational pricing model, which sets wholesale electricity prices at system points ("nodes") that reflect local generation and delivery costs. Generally, SCE schedules its electricity generation to serve its load but when it has excess generation or the market price of power is more economic than its own generation, SCE may sell power from utility-owned generation assets and existing power procurement contracts into, or buy generation and/or ancillary services to meet its load requirements from, the day-ahead market. SCE will offer to buy its generation at nodes near the source of the generation, but will take delivery at nodes throughout SCE's service territory. Congestion may occur when available energy cannot be delivered due to transmission constraints, which results in transmission congestion charges and differences in prices at various nodes. The CAISO also offers congestion revenue rights or CRRs, a commodity that entitles the holder to receive (or pay) the value of transmission congestion between specific nodes, acting as an economic hedge against transmission congestion charges.
Competition
Because SCE is an electric utility company operating within a defined service territory pursuant to authority from the CPUC, SCE faces retail 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. While California law provides only limited opportunities for customers to choose to purchase power directly from an energy service provider other than SCE, a California statute was adopted in 2009 that permits a limited, phased-in expansion of customer choice (direct access) for nonresidential customers. SCE also faces some competition from cities and municipal districts that create municipal utilities or community choice aggregators. Competition between SCE and other electricity providers is conducted mainly on the basis of price. The effect of this competition on SCE generally is to reduce the number of customers purchasing power from SCE, but those departing customers typically continue to utilize and pay for SCE's transmission and distribution services.
SCE faces increased competition from distributed power generation alternatives, such as roof-top solar facilities, becoming available to its customers as a result of technological developments, federal and state subsidies, and declining costs of such alternatives. See "Item 1A. Risk Factors—Risks Relating to Southern California Edison Company—Regulatory Risks."
In the area of transmission infrastructure, SCE may experience increased competition from merchant transmission providers. The FERC has made changes to its transmission planning requirements with the goal of opening transmission development to competition from independent developers. In July 2011, the FERC adopted new rules that remove incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities. The rules direct regional entities, such as ISOs, to create new processes that would allow other providers to develop certain types of new transmission projects. The CAISO filed its processes, as required by the rule, with the FERC in October 2012. The FERC has not yet approved these processes. The majority of SCE's 2013 – 2014 transmission capital forecast relates to transmission projects that have been approved by the CAISO and barring a re-evaluation under the new rules, will not be subject to the new processes. SCE does not expect these projects to be re-evaluated. The impact of the new rules on future transmission projects will depend on the processes ultimately implemented by regional entities.
Properties
SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, which include sub-transmission facilities and are located primarily in California but also in Nevada and Arizona, deliver power from generating sources to the distribution network and consist of lines ranging from 33 kV to 500 kV and substations. SCE's distribution system, which takes power from substations to customers, includes over 59,000 circuit miles of overhead
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lines, 44,000 circuit miles of underground lines and over 700 distribution substations, all of which are located in California. SCE owns the generating facilities listed in the following table.
Generating Facility | Location (in CA, unless otherwise noted) | Fuel Type | Operator | SCE's Ownership Interest (%) | Net Physical Capacity (in MW) | SCE's Capacity pro rata share (in MW) | ||||||||||
San Onofre Nuclear Generating Station | South of San Clemente | Nuclear | SCE | 78.21 | % | 2,150 | 1,760 | |||||||||
Hydroelectric Plants (36) | Various | Hydroelectric | SCE | 100 | % | 1,176 | 1,176 | |||||||||
Pebbly Beach Generating Station | Catalina Island | Diesel | SCE | 100 | % | 9 | 9 | |||||||||
Mountainview | Redlands | Natural Gas | SCE | 100 | % | 1,050 | 1,050 | |||||||||
Peaker Plants (5) | Various | Gas fueled Combustion Turbine | SCE | 100 | % | 245 | 245 | |||||||||
Palo Verde Nuclear Generating Station | Phoenix, AZ | Nuclear | APS | 15.8 | % | 3,739 | 591 | |||||||||
Four Corners Units 4 and 5 | Farmington, NM | Coal-fired | APS | 48 | % | 1,540 | 739 | |||||||||
Solar PV Plants (24) | Various | Photovoltaic | SCE | 100 | % | 63 | 63 | |||||||||
Total | 9,972 | 5,633 | ||||||||||||||
In November 2010, SCE entered into an agreement to sell its interest in Four Corners to APS for approximately $294 million. The sale remains contingent upon APS obtaining a satisfactory long-term coal supply agreement for the plant. As of January 2013, the sale agreement may be terminated by either party. As of the date of this report, the agreement has not been terminated by either party. The purchase price is subject to certain adjustments under the sale agreement, which includes, among other adjustments, a reduction in the purchase price of $7.5 million for each month between October 1, 2012 and the closing date. See "Item 8. Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for more information.
San Onofre, Four Corners, certain of SCE's substations, and portions of its transmission, distribution and communication systems are located on lands owned by the federal, state or local governments under licenses, permits, easements or leases, or on public streets or highways pursuant to franchises. Certain of the documents evidencing such rights obligate SCE, under specified circumstances and at its expense, to relocate such 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 and related reservoirs are located in whole or in part on U.S.-owned lands and are subject to FERC licenses. Twenty of these plants have 29- to 40-year FERC licenses that expire at various times between 2021 and 2046. Eight plants are currently being relicensed and are operating under temporary annual permits with new FERC licenses expected within one to two years and three plants are not operating and undergoing decommissioning. FERC 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 objectives greater consideration in the licensing process. Substantially all of SCE's properties are subject to the lien of a trust indenture securing first and refunding mortgage bonds. See "Item 8. Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
Seasonality
Due to warm weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than the other quarters.
ENVIRONMENTAL REGULATION OF EDISON INTERNATIONAL AND SUBSIDIARIES
Legislative and regulatory activities by federal, state, and local authorities in the United States relating to energy and the environment impose numerous restrictions on the operation of existing facilities and affect the timing, cost, location, design, construction and operation of new facilities by Edison International's subsidiaries, as well as the cost of mitigating the
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environmental impacts of past operations. The environmental regulations and other developments discussed below have the largest impact on SCE's fossil-fuel fired power plants, and therefore the discussion in this section focuses mainly on regulations applicable to the states of California and New Mexico, where SCE's facilities are located.
Edison International and SCE continue to monitor legislative and regulatory developments and to evaluate possible strategies for compliance with environmental regulations. Additional information about environmental matters affecting Edison International and its subsidiaries, including projected environmental capital expenditures, is included in the MD&A under the heading "Liquidity and Capital Resources—SCE—Capital Investment Plan" and in "Item 8. Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Environmental Remediation" and "—Note 10. Environmental Developments."
Air Quality
The CAA, which regulates air pollutants from mobile and stationary sources, has a significant impact on the operation of fossil fuel plants, especially coal-fired plants. The CAA requires the US EPA to establish concentration levels in the ambient air for six criteria pollutants to protect public health and welfare. These concentration levels are known as NAAQS. The six criteria pollutants are carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2.
Federal environmental regulations of these criteria pollutants require states to adopt state implementation plans, known as SIPs, for certain pollutants, which detail how the state will attain the standards that are mandated by the relevant law or regulation. The SIPs must be equal to or more stringent than the federal requirements and must be submitted to the US EPA for approval. Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas), and must develop a SIP both to bring non-attainment areas into compliance with the NAAQS and to maintain good air quality in attainment areas. If the attainment status of areas changes, states may be required to develop new SIPs that address the changes. Much of southern California is in a non-attainment area for several criteria pollutants.
National Ambient Air Quality Standards
Ozone
In January 2010, the US EPA proposed a revision to the primary and secondary NAAQS for 8-hour ozone that it had finalized in 2008. The 8-hour ozone standard established in 2008 was 0.075 parts per million but the implementation process must be completed before the 0.075 parts-per-million standard can be enforced. The US EPA issued initial area designations of attainment, nonattainment, and unclassifiable areas across the nation in 2012. Areas in SCE's service territory were classified in various degrees of nonattainment, including Los Angeles (known as the South Coast Air Basin), which was designated as extreme nonattainment; Kern County (marginal nonattainment); Riverside County (severe nonattainment); Ventura County (serious nonattainment); and the San Joaquin Valley (extreme nonattainment). States will then be required to develop and submit state implementation plans outlining how compliance with the 2008 NAAQS will be achieved.
Particulate Matter
In December 2012, the US EPA lowered the primary annual NAAQS for fine particulate matter (known as PM2.5) from 15 to 12 micrograms per cubic meter (mg/m3). The EPA retained the existing 24-hour NAAQS for PM2.5 (35 mg/m3) and for coarse particulate matter (known as PM10) (150 mg/m3). These new limits take effect in 2020. States must recommend attainment designations to EPA by December 2013, with final designations expected in 2015 and implementation plans due in 2018.
Regional Haze
The regional haze rules under the CAA are designed to prevent impairment of visibility in certain federally designated areas. The goal of the rules 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 best available retrofit technology ("BART") or implement other control strategies to meet regional haze control requirements.
In relation to Four Corners, the US EPA issued its final FIP in August 2012. The FIP requires the installation of SCR pollution control equipment within designated time periods, or alternatively the shutdown of Units 1-3 and installation of SCRs on Units 4 and 5 within other designated times periods. In November 2010, SCE and APS entered into an agreement for the sale of SCE's interest in Four Corners Units 4 and 5 to APS, subject to regulatory approvals and other conditions. Due to the investment constraints of SB 1368, the California law on GHG emission performance standards discussed below in "—Greenhouse Gas Regulation—Regional Initiatives and State Legislation," SCE does not intend to be a Four Corners participant after the 2016 expiration of the current participant agreements and does not expect to participate in any investment
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in Four Corners SCRs. See "Item 8. Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for more information on the pending sale of SCE's interest in Four Corners.
New Source Review Requirements
The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made to air emissions sources at the facility. Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address NSR compliance issues at the nation's coal-fired power plants.
In April 2009, APS, as operating agent of Four Corners, received a US EPA request pursuant to Section 114 of the CAA for information about Four Corners, including information about Four Corners' capital projects from 1990 to the present. SCE understands that in other cases the US EPA has utilized responses to similar Section 114 letters to examine whether power plants have triggered NSR requirements under the CAA. In October 2011, four environmental organizations filed a lawsuit against the Four Corners owners alleging NSR violations. In January 2012, the organizations amended their complaint, also alleging related New Source Performance Standards violations, and served it on the Four Corners owners. The proceeding is currently stayed, to allow for settlement discussions until March 2013. See "Item 8. Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for information on the pending sale of SCE's interest in Four Corners and "—Note 9. Commitments and Contingencies—Four Corners New Source Review Litigation" for more information on the lawsuit.
Water Quality
Clean Water Act
Regulations under the federal Clean Water Act dictate permitting and mitigation requirements for many of SCE's construction projects, and govern critical parameters at generating facilities, such as the temperature of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities. In March 2011, the US EPA proposed standards under the federal Clean Water Act that would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). These standards are expected to be finalized by June 2013. SCE is evaluating the proposed standards and believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable without incurring material additional capital expenditures or operating costs. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and SCE is unable at this time to assess potential costs of compliance, which could be significant for San Onofre.
California-Prohibition on the Use of Ocean-Based Once-Through Cooling
California has a US EPA-approved program to issue individual or group permits for the regulation of Clean Water Act discharges. California also regulates certain discharges not regulated by the US EPA. Effective October 1, 2010, the California State Water Resources Control Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like SCE's San Onofre and many of the existing natural gas power plants along the California coast. The final policy required an independent engineering study to be completed prior to the fourth quarter of 2013 regarding the feasibility of compliance by California's two coastal nuclear power plants. The policy may result in significant capital expenditures at San Onofre and may affect its operations.
Coal Combustion Residuals
US EPA regulations currently classify coal ash and other coal combustion residuals as solid wastes that are exempt from hazardous waste requirements. This classification enables beneficial uses of coal combustion residuals, such as for cement production and fill materials. In June 2010, the US EPA published proposed regulations relating to coal combustion residuals that could result in their reclassification. Two different proposed approaches are under consideration, and SCE understands that US EPA issuance of a final rule is not expected before late 2013.
The first approach, under which the US EPA would list these residuals as special wastes subject to regulation as hazardous wastes, could require the owners of Four Corners to incur additional capital and operating costs. The second approach, under which the US EPA would regulate these residuals as nonhazardous wastes, would establish minimum technical standards for units that are used for the disposal of coal combustion residuals, but would allow procedural and enforcement mechanisms (such as permit requirements) to be exclusively a matter of state law.
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Greenhouse Gas Regulation
There have been a number of federal and state legislative and regulatory initiatives to reduce GHG emissions. Any climate change regulation or other legal obligation that would require substantial reductions in GHG emissions or that would impose additional costs or charges for the emission of GHGs could significantly increase the cost of generating electricity from fossil fuels, and especially from coal-fired plants, as well as the cost of purchased power.
Federal Legislative/Regulatory Developments
In June 2010, the US EPA issued the Prevention of Significant Deterioration ("PSD") and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule." This regulation generally subjects newly constructed sources of GHG emissions and newly modified existing major sources to the PSD air permitting program beginning in January 2011 (and later, to the Title V permitting program under the CAA); however the GHG tailoring rule significantly increases the emissions thresholds that apply before facilities are subjected to these programs. The emissions thresholds for CO2 equivalents in the final rule vary from 75,000 tons per year to 100,000 tons per year depending on the date and whether the sources are new or modified. In March 2012, the US EPA announced proposed carbon dioxide emission limits for new power plants.
Regulation of GHG emissions pursuant to the PSD program could affect efforts to modify SCE's facilities in the future, and could subject new capital projects to additional permitting or emissions control requirements that could delay such projects.
In December 2010, the US EPA announced that it had entered into a settlement with various states and environmental groups to resolve a long-standing dispute over regulation of GHGs from electrical generating units pursuant to the New Source Performance Standards in the CAA and would propose performance standards for emissions from new and modified power plants and emissions guidelines for existing power plants. The specific requirements will not be known until the regulations are finalized. Since January 2010, the US EPA's Final Mandatory GHG Reporting Rule has required all sources within specified categories, including electric generation facilities, to monitor emissions, and to submit annual reports to the US EPA by March 31 of each year. SCE's 2012 GHG emissions from utility-owned generation were approximately 6.9 million metric tons.
Regional Initiatives and State Legislation
Regional initiatives and state legislation may also require reductions of GHG emissions and it is not yet clear whether or to what extent any federal legislation would preempt them. If state and/or regional initiatives remain in effect after federal legislation is enacted, utilities and generators could be required to satisfy them in addition to the federal standards.
SCE's operations in California are subject to two laws governing GHG emissions. The first law, the California Global Warming Solutions Act of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce GHG emissions. AB 32 required the California Air Resources Board ("CARB") to develop regulations, which became effective in 2012, that would reduce California's GHG emissions to 1990 levels in yearly increments by 2020. In December 2011, the CARB regulation was officially published establishing a California cap-and-trade program. The first compliance period for the cap-and-trade program is for 2013 GHG emissions. The first auction, held on November 14, 2012 cleared at $10.09/metric ton, nine cents above the floor price.
CARB regulations implementing a cap-and-trade program and the cap-and-trade program itself, continue to be the subject of litigation. In March 2012, environmental groups filed a case against CARB challenging the cap-and-trade program's offset provisions. SCE intervened as part of a broad business coalition to support the offset provisions. In November 2012, the California Chamber of Commerce filed a suit alleging that the auction itself violated AB 32 and the California Constitution. Both suits are pending.
The second law, SB 1368, required the CPUC and the CEC to adopt GHG emission performance standards restricting the ability of California investor-owned and publicly owned utilities, respectively, to enter into long-term arrangements for the purchase of electricity. The standards that have been adopted prohibit these entities, including SCE, from entering into long-term financial commitments with generators that emit more than 1,100 pounds of CO2 per MWh, the performance of a combined-cycle gas turbine generator. SB 1368 may prohibit SCE from making emission control expenditures at Four Corners. See "Item 8. Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for information on the sale of SCE's interest in Four Corners.
In April 2011, California enacted a law to require California retail sellers of electricity to procure 33% of their customers' electricity requirements from renewable resources, as defined in the statute. On December 1, 2011, the CPUC approved a decision setting procurement quantity requirements for CPUC-regulated retail sellers that incrementally increase to 33% over several periods between January 2011 and December 31, 2020. The quantity would remain at 33% of retail sales for each
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year thereafter. SCE's delivery of eligible renewable resources to customers was 21% of its total energy portfolio for 2011 and its delivery of eligible renewable resources to customers is estimated to be approximately 20% of its total energy portfolio for 2012.
Litigation Developments
Litigation alleging that GHG is a public and private nuisance may affect SCE, whether or not it is named as a defendant. The law is unsettled on whether or not this litigation presents questions capable of judicial resolution or political questions that should be resolved by the legislative or executive branches. For further discussion see "Item 8. Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
ITEM 1A. RISK FACTORS
RISKS RELATING TO EDISON INTERNATIONAL
Edison International's liquidity depends on SCE's ability to pay dividends and tax allocation payments to Edison International.
Edison International is a holding company and, as such, it 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 SCE and its ability to make upstream distributions. Prior to paying dividends to Edison International, SCE has financial and regulatory obligations that must be satisfied, including, among others, debt service and preferred stock dividends. In addition, CPUC holding company rules require that SCE's dividend policy be established by SCE's Board of Directors on the same basis as if SCE were a stand-alone utility company, and that the capital requirements of SCE, as deemed to be necessary to meet SCE's service obligations, shall receive first priority from the Boards of Directors of both Edison International and SCE. SCE may also owe tax-allocation payments to Edison International under applicable tax-allocation agreements. Financial market and economic conditions may have an adverse effect on Edison International's liquidity. See "Risks Relating to Southern California Edison" below for further discussion.
The Bankruptcy Court may not approve the Settlement Transaction, or even if the Settlement Transaction is approved, it may not be consummated if certain conditions are not met. If the Settlement Transaction is not approved and consummated, Edison International may not be entitled to receive certain benefits contemplated by the Support Agreement.
On the Petition Date, EME and its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.
Under the Support Agreement to which EME, Edison International and certain of EME's senior unsecured noteholders are parties, each of them has agreed to support Bankruptcy Court approval of the Settlement Transaction, subject to conditions. If the Settlement Transaction is approved and consummated, EME will be required to perform its obligations under its tax allocation and intercompany services agreements with Edison International, to indemnify Edison International against liabilities arising from EME's conduct of its separate business, and Edison International, EME and the EME noteholders who have signed the Support Agreement will exchange releases of claims in accordance with the terms of the Support Agreement.
Under the Support Agreement, within 150 days following the Petition Date, EME will seek authority from the Bankruptcy Court to enter into the Settlement Transaction. The parties to the Support Agreement will seek approval by the Bankruptcy Court within 210 days following the Petition Date of the Settlement Transaction, which includes the benefits to Edison International described above. If the Bankruptcy Court does not grant approval within that period, the Support Agreement is subject to termination. There can be no assurance that the Bankruptcy Court will approve the Settlement Transaction, and even if it is approved, there can be no assurance that the conditions to the effectiveness of the Settlement Transaction will be satisfied. In addition, EME is entitled to terminate the Support Agreement and consider alternative transactions in accordance with its fiduciary duties. If the Settlement Transaction is not approved, absent a separate agreement, Edison International will not receive the benefits described above.
Edison International's future performance may be affected by southern California events.
While Edison International intends to continue to conduct both regulated and competitive businesses in the future, the bankruptcy of EME has resulted in its current business being concentrated almost entirely in the regulated sector and in southern California. As a result, Edison International's future performance may be affected by events concentrated in southern California and it does not have diversification of sources of revenue or regulatory oversight.
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RISKS RELATING TO SOUTHERN CALIFORNIA EDISON COMPANY
Regulatory Risks
SCE's financial results depend upon its ability to recover its costs in a timely manner from its customers through regulated rates.
SCE's ongoing financial results depend on its ability to recover from its customers in a timely manner its costs, including the costs of electricity purchased for its customers, through the rates it charges its customers as approved by the CPUC and FERC. SCE's financial results also depend on its ability to earn a reasonable return on capital, including long-term debt and equity. SCE's capital investment plan, increasing procurement of renewable power, increasing environmental regulations, moderating demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customer rates. Increases in self-generation also reduce the pool of customers from whom fixed costs are recovered, while costs potentially could increase due to system modifications that may be necessary to cope with the systemic effects of self-generation. Customers that self-generate their own power do not currently pay most transmission and distribution charges and non-bypassable charges, subject to limitations. The net result is to increase utility rates further for those customers who do not self-generate, which encourages more self-generation and further rate increases. If SCE is unable to obtain a sufficient rate increase or modify its rate design to recover material amounts of its costs (including an adequate return on capital) in rates in a timely manner, its financial condition and results of operations could be materially affected. For further information on SCE's rate requests, see "Management Overview—2012 General Rate Case" and "Liquidity and Capital Resources—SCE—FERC Formula Rates" in the MD&A.
SCE's energy procurement activities are subject to regulatory and market risks that could materially affect its financial condition and liquidity.
SCE obtains energy, capacity, environmental credits and ancillary services needed to serve its customers from its own generating plants, and through contracts with energy producers and sellers. California law and CPUC decisions allow SCE to recover through the rates it is allowed to charge its customers reasonable procurement costs incurred in compliance with an approved procurement plan. Nonetheless, SCE's cash flows remain subject to volatility primarily resulting from changes to commodity prices. In addition, SCE is subject to the risks of unfavorable or untimely CPUC decisions about the compliance with SCE's procurement plan and the reasonableness of certain procurement-related costs.
SCE may not be able to hedge its risk for commodities on economic terms or fully recover the costs of hedges through the rates it is allowed to charge its customers, which could materially affect SCE's liquidity and results of operations, see "Market Risk Exposures" in the MD&A.
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. Among other things, the CPUC regulates SCE's retail rates and capital structure, and the FERC regulates SCE's wholesale rates. The NRC regulates the safety of SCE's nuclear power plants. The construction, planning, and project site identification of SCE's power plants and transmission lines in California are also subject to the jurisdiction of the California Energy Commission (for thermal power plants 50 MW or greater) and the CPUC.
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 materially affected. The process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat would have a material effect on SCE's business.
This extensive governmental regulation creates significant risks and uncertainties for SCE's business. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to SCE, or its facilities or operations in a manner that may have a detrimental effect on SCE's business or result in significant additional costs. In addition, regulation adopted via the public initiative process may apply to SCE, or its facilities or operations in a manner that may have a detrimental effect on SCE's business or result in significant additional costs.
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Competitive Risks
SCE faces increased competition as a result of technological advancements.
The electricity industry is undergoing transformative change. Technological advancements such as energy storage and distributed generation may change the nature of energy generation and delivery. These changes may materially affect SCE's business model as a regulated utility and its ability to compete with new energy generation and delivery business models.
Operating Risks
SCE's financial condition and results of operations could be materially affected if it is unable to successfully manage the risks inherent in operating and maintaining its facilities.
SCE's infrastructure is aging and could pose a risk to system reliability. In order to mitigate this risk, SCE is engaged in a significant and ongoing infrastructure investment programs. This substantial investment program elevates the operational risks and the need for superior execution in its activities. SCE's financial condition and results of operations could be materially affected if it is unable to successfully manage these risks as well as the risks inherent in operating and maintaining its facilities, the operation of which can be hazardous. SCE's inherent operating risks include such matters as the risks of human performance, workforce capabilities, public opposition to infrastructure projects, delays, environmental mitigation costs, difficulty in estimating costs, system limitations and degradation, and interruptions in necessary supplies.
Weather-related incidents and other natural disasters could materially affect SCE's financial condition and results of operations.
Weather-related incidents and other natural disasters, including storms, wildfires and earthquakes, can disrupt the generation and transmission of electricity, and can seriously damage the infrastructure necessary to deliver power to SCE's customers. These events can lead to lost revenues and increased expenses, including higher maintenance and repair costs. They can also result in regulatory penalties and disallowances, particularly if SCE encounters difficulties in restoring power to its customers. These occurrences could materially affect SCE's business, financial condition and results of operations, and the inability to restore power to SCE's customers could also materially damage the business reputation of SCE and Edison International.
The generation, transmission and distribution of electricity are dangerous and involve inherent risks of damage to private property and injury to employees and the general public.
Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Injuries and property damage caused by such contact can subject SCE to liability that, despite the existence of insurance coverage, can be significant. In the wake of recent natural disasters such as windstorms, which can cause wildfires, pole failures and associated property damage and outages, the CPUC has increased its focus on public safety issues with an emphasis on heightened compliance with construction and operating standards and the potential for penalties being imposed on utilities. Such penalties and liabilities could be significant but are very difficult to predict. The range of possible penalties and liabilities includes amounts that could materially affect SCE's liquidity and results of operations.
SCE's systems and network infrastructure may be vulnerable to cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality.
Regulators, such as the NERC, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, have noted that the U.S. national electric grid and other energy infrastructures have potential vulnerabilities to cyber attacks and disruptions and that such cyber threats are becoming increasingly sophisticated and dynamic. SCE's operations require the continuous operation of critical information technology systems and network infrastructure. Although SCE actively monitors developments in this area and is involved in various industry groups and government initiatives, no security measures can completely shield such systems and infrastructure from vulnerabilities to cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality. If SCE's information technology systems security measures were to be breached or a critical system failure were to occur without timely recovery, SCE could be unable to fulfill critical business functions and/or sensitive confidential personal and other data could be compromised, which could materially affect SCE's financial condition and results of operations. See "Item 1. Business—Regulation—NERC" for further discussion.
There are inherent risks associated with operating nuclear power generating facilities, including, among other things, the potential harmful effects on the environment and human health resulting from the operation of nuclear power generating facilities and the storage, handling and disposal of radioactive materials.
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The scope of necessary repairs for the steam generators in Unit 2 and Unit 3 of San Onofre or the length of the Units' outages could prove more extensive than is currently estimated. The cost of such repairs or the substitute market power that must be purchased during the outage could exceed estimates and insurance coverage or may not be recoverable through regulatory processes or otherwise.
Units 2 and 3 at San Onofre have been off-line for extensive inspections, testing and analysis of their steam generators after unexpected wear and a leak were discovered in them in early 2012. SCE, the manufacturer of the steam generators and a team of outside experts have worked together to analyze the causes of the wear and possible remedial actions. The CPUC has begun an investigation proceeding that will consider the cost recovery for all of San Onofre costs, including the cost of the steam generator replacement project, substitute market power costs, operation and maintenance costs and the seismic study costs. SCE cannot assure that the scope of necessary repairs or the length of the outages will not exceed current estimates. There can also be no assurance that the cost of such repairs or the necessary substitute market power will not exceed current estimates and insurance coverage or that they will be recoverable through regulatory processes or otherwise. These amounts could be material and could materially affect SCE's financial condition and results of operations. For more information, see "Management Overview—San Onofre Outage, Inspection and Repair Issues" in the MD&A.
Continued NRC scrutiny of San Onofre may result in additional corrective actions that will increase operations and maintenance costs or require additional capital expenditures.
San Onofre is subject to extensive oversight and scrutiny of the NRC. This scrutiny may result in SCE being required to take additional corrective actions and incur increased operations and maintenance expenses or new capital expenditures. If SCE is unable to take effective corrective actions required by the NRC, the NRC has the authority to impose fines or shut down a unit, or both, depending upon the NRC's assessment of the severity of the situation, until compliance is achieved.
Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.
Federal law limits public liability claims from a nuclear incident to the amount of available financial protection which is currently approximately $12.6 billion. SCE and other owners of the San Onofre and Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance available of $375 million per site. If nuclear incident liability claims were to exceed $375 million, the remaining amount would be made up from contributions of approximately $12.2 billion made by all of the nuclear facility owners in the U.S., up to an aggregate total of $12.6 billion. There is no assurance that the CPUC would allow SCE to recover the required contribution made in the case of one or more nuclear incident claims that exceeded $375 million. If this public liability limit of $12.6 billion is insufficient, federal law contemplates that additional funds may be appropriated by Congress. There can be no assurance of SCE's ability to recover uninsured costs in the event the additional federal appropriations are insufficient. See "Item 8. Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Nuclear Insurance."
Spent fuel storage capacity could be insufficient to permit long-term operation of SCE's nuclear plants.
The U.S. 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 the 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 effect on SCE.
SCE's insurance coverage for wildfires arising from its ordinary operations may not be sufficient and Edison International may not be able to obtain sufficient insurance on SCE's behalf for such occurrences.
Edison International has experienced increased costs and difficulties in obtaining insurance coverage for wildfires that could arise from SCE's ordinary operations. In addition, the insurance Edison International has obtained on SCE's behalf for wildfire liabilities may not be sufficient. Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates. A loss which is not fully insured or cannot be recovered in customer rates could materially affect Edison International's and SCE's financial condition and results of operations. Furthermore, insurance for wildfire liabilities may not continue to be available at all or at rates or on terms similar to those presently available to Edison International.
Environmental Risks
SCE is subject to extensive environmental regulations that may involve significant and increasing costs and materially affect SCE.
SCE is subject to extensive and frequently changing environmental regulations and permitting requirements that involve significant and increasing costs and substantial uncertainty. SCE devotes significant resources to environmental monitoring, pollution control equipment, mitigation projects, and emission allowances to comply with existing and anticipated
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environmental regulatory requirements. However, the current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. The adoption of laws and regulations to implement greenhouse gas controls could materially affect operations of power plants, which could in turn impact electricity markets and SCE's purchased power costs. SCE may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or with respect to offsite waste disposal sites that have been used in its operations. Other environmental laws, particularly with respect to air emissions, disposal of ash, wastewater discharge and cooling water systems, are also generally becoming more stringent. The continued operation of SCE facilities may require substantial capital expenditures for environmental controls or cessation of operations. Current and future state laws and regulations in California also could increase the required amount of energy that must be procured from renewable resources. See "Item 1. Business—Environmental Regulation of Edison International and Subsidiaries" and "Item 8. Notes to Consolidated Financial Statements—Note 10. Environmental Developments" for further discussion of environmental regulations under which SCE operates.
Financing Risks
As a capital intensive company, SCE relies on access to the capital markets. If SCE were unable to access the capital markets or the cost of financing were to substantially increase, its liquidity and operations would be materially affected.
SCE regularly accesses the capital markets to finance its activities and is expected to do so by its regulators as part of its obligation to serve as a regulated utility. SCE's needs for capital for its ongoing infrastructure investment program are substantial. SCE's ability to arrange financing, as well as its ability to refinance debt and make scheduled payments of principal and interest, are dependent on numerous factors, including SCE's levels of indebtedness, maintenance of acceptable credit ratings, its financial performance, liquidity and cash flow, and other market conditions. SCE's failure to obtain additional capital from time to time would have a material effect on SCE's liquidity and operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
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 "Item 1. Business—Southern California Edison Company—Properties."
ITEM 3. LEGAL PROCEEDINGS
EME Chapter 11 Filing
On December 17, 2012, EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. For more information, see "Management Overview—EME Chapter 11 Bankruptcy Filing" in the MD&A and "Item 8. Notes to Consolidated Financial Statements—Note 17. Discontinued Operations."
EXECUTIVE OFFICERS OF EDISON INTERNATIONAL
Executive Officer | Age at December 31, 2012 | Company Position | ||
Theodore F. Craver, Jr. | 61 | Chairman of the Board, President and Chief Executive Officer | ||
Robert L. Adler | 65 | Executive Vice President and General Counsel | ||
Polly L. Gault | 59 | Executive Vice President, Public Affairs | ||
W. James Scilacci | 57 | Executive Vice President, Chief Financial Officer and Treasurer | ||
Janet T. Clayton | 58 | Senior Vice President, Corporate Communications | ||
Bertrand A. Valdman | 50 | Senior Vice President, Strategic Planning | ||
Mark C. Clarke | 56 | Vice President and Controller | ||
Ronald L. Litzinger | 53 | President, SCE | ||
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As set forth in Article IV of Edison International's and the relevant subsidiary's Bylaws, the elected officers of Edison International and its subsidiaries are chosen annually by, and serve at the pleasure of, Edison International and the relevant subsidiary'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 and its subsidiaries have been actively engaged in the business of Edison International and its subsidiaries for more than five years, except for Messrs. Adler and Valdman, and Ms. Clayton, 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:
Executive Officers | Company Position | Effective Dates | ||
Theodore F. Craver, Jr. | Chairman of the Board, President and Chief Executive Officer, Edison International President, Edison International Chairman of the Board, President and Chief Executive Officer, EMG1 Chairman of the Board, President and Chief Executive Officer, EME1 | August 2008 to present April 2008 to July 2008 November 2005 to March 2008 January 2005 to March 2008 | ||
Robert L. Adler | Executive Vice President and General Counsel, Edison International Executive Vice President, Edison International Partner, Munger, Tolles & Olson LLP2 | August 2008 to present July 2008 to August 2008 January 1978 to June 2008 | ||
Polly L. Gault | Executive Vice President, Public Affairs, Edison International Executive Vice President, Public Affairs, SCE | March 2007 to present March 2007 to September 2008 | ||
W. James Scilacci | Executive Vice President, Chief Financial Officer and Treasurer, Edison International Senior Vice President and Chief Financial Officer, EME1 Senior Vice President and Chief Financial Officer, EMG1 | August 2008 to present March 2005 to July 2008 November 2005 to July 2008 | ||
Janet T. Clayton | Senior Vice President, Corporate Communication, Edison International President, Think Cure3 | April 2011 to present Jan 2008 to April 2011 | ||
Bertrand A. Valdman | Senior Vice President, Strategic Planning, Edison International Executive Vice President, Chief Operating Officer Puget Sound Energy4 | March 2011 to present May 2007 to March 2011 | ||
Mark C. Clarke | Vice President and Controller, Edison International Vice President and Controller, SCE Vice President and Controller, EME1 | August 2009 to present December 2012 to present January 2003 to July 2009 | ||
Ronald L. Litzinger | President, SCE Chairman of the Board, President and Chief Executive Officer, EMG and EME1 Senior Vice President, Transmission and Distribution, SCE | January 2011 to present April 2008 to December 2010 May 2005 to March 2008 | ||
1 | EMG is the holding company for EME, an independent power producer and is a wholly-owned subsidiary of Edison International and an affiliate of SCE. EME and its wholly-owned subsidiaries filed for protection under Chapter 11 of the Bankruptcy Code on December 17, 2012. EME continues to be classified as an affiliate of SCE for certain purposes and is a wholly-owned subsidiary of Edison International, but as of December 17, 2012, it is deconsolidated from Edison International's financial results and accounted for as discontinued operations. |
2 | Munger, Tolles & Olson LLP is a California-based law firm. Mr. Adler also served as a Co-Managing Partner. |
3 | Think Cure is a community-based nonprofit organization that raises funds to accelerate collaborate research to cure cancer and is not a parent, affiliate or subsidiary of Edison International. |
4 | Puget Sound Energy is a regulated energy utility in Washington State and is not a parent, affiliate or subsidiary of Edison International. |
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EXECUTIVE OFFICERS OF SOUTHERN CALIFORNIA EDISON COMPANY
Executive Officer | Age at December 31, 2012 | Company Position | ||
Ronald L. Litzinger | 53 | President | ||
Stephen E. Pickett | 62 | Executive Vice President, External Relations | ||
Peter T. Dietrich | 48 | Senior Vice President and Chief Nuclear Officer | ||
Stuart R. Hemphill | 49 | Senior Vice President, Power Supply | ||
Linda G. Sullivan | 49 | Senior Vice President and Chief Financial Officer | ||
Russell C. Swartz | 61 | Senior Vice President and General Counsel | ||
Mark C. Clarke | 56 | Vice President and Controller | ||
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, its parent company Edison International, and/or one of SCE's subsidiaries or other affiliates for more than five years, except for Mr. Dietrich, 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:
Executive Officer | Company Position | Effective Dates | ||
Ronald L. Litzinger | President, SCE Chairman of the Board, President and Chief Executive Officer, EMG and EME1 Senior Vice President, Transmission and Distribution, SCE | January 2011 to present April 2008 to December 2010 May 2005 to March 2008 | ||
Stephen E. Pickett | Executive Vice President, External Relations, SCE Executive Vice President, External Relations and General Counsel, SCE Senior Vice President and General Counsel, SCE | February 2011 to present January 2011 to February 2011 January 2002 to December 2010 | ||
Peter T. Dietrich | Senior Vice President and Chief Nuclear Officer, SCE Senior Vice President, SCE Site Vice President, Entergy Nuclear Operations, Inc., James A. Fitzpatrick Nuclear Plant2 | December 2010 to present November 2010 to present April 2006 to November 2010 | ||
Stuart R. Hemphill | Senior Vice President, Power Supply, SCE Senior Vice President, Power Procurement, SCE Vice President, Renewable and Alternative Power, SCE Director of Renewable and Alternative Power, SCE | January 2011 to present July 2009 to December 2010 March 2008 to June 2009 April 2006 to March 2008 | ||
Linda G. Sullivan | Senior Vice President and Chief Financial Officer, SCE Senior Vice President, Chief Financial Officer and Acting Controller, SCE Vice President and Controller, Edison International Vice President and Controller, SCE | March 2010 to present July 2009 to March 2010 June 2005 to August 2009 June 2005 to June 2009 | ||
Russell C. Swartz | Senior Vice President and General Counsel, SCE Vice President and Associate General Counsel, SCE Associate General Counsel, SCE | February 2011 to present February 2010 to February 2011 March 2007 to February 2010 | ||
Mark C. Clarke | Vice President, and Controller, SCE Vice President and Controller, Edison International Vice President and Controller, EME1 | December 2012 to present August 2009 to present January 2003 to July 2009 | ||
1 | EMG is the holding company for EME, an independent power producer and is a wholly-owned subsidiary of Edison International and an affiliate of SCE. EME and its wholly-owned subsidiaries filed for protection under Chapter 11 of the Bankruptcy Code on December 17, 2012. EME continues to be classified as an affiliate of SCE for certain purposes and is a wholly-owned subsidiary of Edison International, but as of December 17, 2012, it is deconsolidated from Edison International's financial results and accounted for as discontinued operations. |
2 | Entergy Nuclear Operations, Inc. is a subsidiary of Entergy Corporation, an integrated energy company and is not a parent, affiliate or subsidiary of SCE. |
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
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 "Item 8. Edison International Notes to Consolidated Financial Statements—Note 19. Quarterly Financial Data." There are restrictions on the ability of Edison International's subsidiaries to transfer funds to Edison International that materially limit the ability of Edison International to pay cash dividends. Such restrictions are discussed in the MD&A under the heading "Liquidity and Capital Resources—Edison International Parent and Other," "—SCE—Dividend Restrictions," and in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 5. Debit and Credit Agreements." The number of common stockholders of record of Edison International was 41,000 on February 22, 2013. Additional information concerning the market for Edison International's Common Stock is set forth on the cover page of this report. The description of Edison International's equity compensation plans required by Item 201(d) of Regulation S-K is incorporated by reference to "Part III—Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" of this report.
Purchases of Equity Securities by Edison International and Affiliated Purchasers
The following table contains information about all purchases of Edison International Common Stock made by or on behalf of Edison International in the fourth quarter of 2012.
Period | (a) Total Number of Shares (or Units) Purchased1 | (b) Average Price Paid per Share (or Unit)1 | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs | ||||||||
October 1, 2012 to October 31, 2012 | 284,676 | $ | 46.75 | — | — | |||||||
November 1, 2012 to November 30, 2012 | 273,974 | 45.90 | — | — | ||||||||
December 1, 2012 to December 31, 2012 | 680,367 | 45.11 | — | — | ||||||||
Total | 1,239,017 | 45.66 | — | — | ||||||||
1 | The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's: (i) 401(k) Savings Plan; (ii) Dividend Reinvestment and Direct Stock Purchase Plan; and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions. |
Purchases of Equity Securities by Southern California Edison Company and Affiliated Purchasers
Certain information responding to Item 5 with respect to frequency and amount of cash dividends is included in "Item 8. Notes to the Consolidated Financial Statements—Note 19. Quarterly Financial Data." As a result of the formation of a holding company described in Item 1 above, 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.
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Comparison of Five-Year Cumulative Total Return
At December 31, | |||||||||||||||||||||||
2007 | 2008 | 2009 | 2010 | 2011 | 2012 | ||||||||||||||||||
Edison International | $ | 100 | $ | 62 | $ | 70 | $ | 80 | $ | 89 | $ | 100 | |||||||||||
S & P 500 Index | 100 | 63 | 80 | 92 | 94 | 109 | |||||||||||||||||
Philadelphia Utility Index | 100 | 73 | 80 | 85 | 101 | 100 | |||||||||||||||||
Note: Assumes $100 invested on December 31, 2007 in stock or index including reinvestment of dividends. Performance of the Philadelphia Utility Index is regularly reviewed by management and the Board of Directors in understanding Edison International's relative performance and is used in conjunction with elements of Edison International's compensation program.
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ITEM 6. SELECTED FINANCIAL DATA
Selected Financial Data: 2008 – 2012
(in millions, except per-share amounts) | 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||
Edison International and Subsidiaries | |||||||||||||||||||
Operating revenue | $ | 11,862 | $ | 10,588 | $ | 9,996 | $ | 9,991 | $ | 11,310 | |||||||||
Operating expenses | 9,577 | 8,527 | 8,177 | 8,982 | 9,599 | ||||||||||||||
Income from continuing operations | 1,594 | 1,100 | 1,144 | 751 | 848 | ||||||||||||||
Income (loss) from discontinued operations, net of tax | (1,686 | ) | (1,078 | ) | 164 | 197 | 500 | ||||||||||||
Net income (loss) | (92 | ) | 22 | 1,308 | 948 | 1,348 | |||||||||||||
Net income (loss) attributable to common shareholders | (183 | ) | (37 | ) | 1,256 | 849 | 1,215 | ||||||||||||
Weighted-average shares of common stock outstanding (in millions) | 326 | 326 | 326 | 326 | 326 | ||||||||||||||
Basic earnings (loss) per share: | |||||||||||||||||||
Continuing operations | $ | 4.61 | $ | 3.20 | $ | 3.34 | $ | 1.98 | $ | 2.16 | |||||||||
Discontinued operations | (5.17 | ) | (3.31 | ) | 0.50 | 0.61 | 1.53 | ||||||||||||
Total | $ | (0.56 | ) | $ | (0.11 | ) | $ | 3.84 | $ | 2.59 | $ | 3.69 | |||||||
Diluted earnings (loss) per share: | |||||||||||||||||||
Continuing operations | $ | 4.55 | $ | 3.17 | $ | 3.32 | $ | 1.98 | $ | 2.16 | |||||||||
Discontinued operations | (5.11 | ) | (3.28 | ) | 0.50 | 0.60 | 1.52 | ||||||||||||
Total | $ | (0.56 | ) | $ | (0.11 | ) | $ | 3.82 | $ | 2.58 | $ | 3.68 | |||||||
Dividends declared per share | 1.3125 | 1.285 | 1.265 | 1.245 | 1.225 | ||||||||||||||
Total assets | $ | 44,394 | $ | 48,039 | $ | 45,530 | $ | 41,444 | $ | 44,615 | |||||||||
Long-term debt excluding current portion | 9,231 | 8,834 | 8,029 | 6,509 | 6,312 | ||||||||||||||
Capital lease obligations excluding current portion | 210 | 216 | 221 | 227 | 13 | ||||||||||||||
Preferred and preference stock of utility | 1,759 | 1,029 | 907 | 907 | 907 | ||||||||||||||
Common shareholders' equity | 9,432 | 10,055 | 10,583 | 9,841 | 9,517 | ||||||||||||||
Southern California Edison Company | |||||||||||||||||||
Operating revenue | $ | 11,851 | $ | 10,577 | $ | 9,983 | $ | 9,965 | $ | 11,248 | |||||||||
Operating expenses | 9,572 | 8,454 | 8,119 | 8,047 | 9,595 | ||||||||||||||
Net income | 1,660 | 1,144 | 1,092 | 1,371 | 904 | ||||||||||||||
Net income available for common stock | 1,569 | 1,085 | 1,040 | 1,226 | 683 | ||||||||||||||
Total assets | $ | 44,034 | $ | 40,315 | $ | 35,906 | $ | 32,474 | $ | 32,568 | |||||||||
Long-term debt excluding current portion | 8,828 | 8,431 | 7,627 | 6,490 | 6,212 | ||||||||||||||
Capital lease obligations excluding current portion | 210 | 216 | 221 | 227 | 13 | ||||||||||||||
Preferred and preference stock | 1,795 | 1,045 | 920 | 920 | 920 | ||||||||||||||
Common shareholder's equity | 9,948 | 8,913 | 8,287 | 7,446 | 6,513 | ||||||||||||||
Capital structure: | |||||||||||||||||||
Common shareholder's equity | 48.4 | % | 48.5 | % | 49.2 | % | 50.1 | % | 47.7 | % | |||||||||
Preferred and preference stock | 8.7 | % | 5.7 | % | 5.5 | % | 6.2 | % | 6.8 | % | |||||||||
Long-term debt | 42.9 | % | 45.8 | % | 45.3 | % | 43.7 | % | 45.5 | % | |||||||||
The selected financial data was derived from Edison International's and SCE's audited financial statements and is qualified in its entirety by the more detailed information and financial statements, including notes to these financial statements, included in this annual report.
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Edison International and Subsidiaries
EME Chapter 11 Filing and Discontinued Operations
On December 17, 2012, EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On December 16, 2012, Edison International, EME and certain of EME's senior unsecured noteholders entered into the Support Agreement, which contemplates among other things, Edison International ceasing to have any continuing ownership interest in EME following effectiveness of a plan of reorganization.
Edison International considers EME to be an abandoned asset under generally accepted accounting principles, and, as a result, the operations of EME prior to December 17, 2012 and for all prior years, are reflected as discontinued operations in the consolidated financial statements. See "Management Overview—EME Chapter 11 Bankruptcy Filing" in the MD&A and "Item 8. Notes to Consolidated Financial Statements—Note 17. Discontinued Operations" for further information.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MANAGEMENT OVERVIEW
Highlights of Operating Results
Edison International is the parent holding company of SCE. SCE is an investor-owned public utility primarily engaged in the business of supplying electricity. Edison International is also the parent company of subsidiaries that are engaged in competitive businesses related to the delivery or use of electricity. Such competitive business activities are currently not material to report as a separate business segment. References to Edison International refer to the consolidated group of Edison International and its subsidiaries. References to Edison International Parent and Other refer to Edison International Parent and its nonutility subsidiaries, including EME. Unless otherwise described all of the information contained in this annual report relates to both filers.
(in millions) | 2012 | 2011 | 2012 vs 2011 Change | 2010 | |||||||||||
Net Income (Loss) attributable to Edison International | |||||||||||||||
SCE | $ | 1,569 | $ | 1,085 | $ | 484 | $ | 1,040 | |||||||
Edison International Parent and Other | |||||||||||||||
Continuing operations | (66 | ) | (44 | ) | (22 | ) | 52 | ||||||||
Discontinued operations | (1,686 | ) | (1,078 | ) | (608 | ) | 164 | ||||||||
Edison International | (183 | ) | (37 | ) | (146 | ) | 1,256 | ||||||||
Less: Non-Core Items | |||||||||||||||
SCE: | |||||||||||||||
2012 General Rate Case – repair deductions (2009 – 2011) | 231 | — | 231 | — | |||||||||||
Global Settlement | — | — | — | 95 | |||||||||||
Tax impact of health care legislation | — | — | — | (39 | ) | ||||||||||
Edison International Parent and Other: | |||||||||||||||
Consolidated state deferred tax impacts related to EME | (37 | ) | (19 | ) | (18 | ) | 21 | ||||||||
Gain on sale of Beaver Valley lease interest | 31 | — | 31 | — | |||||||||||
Write-down of net investment in aircraft leases | — | (16 | ) | 16 | — | ||||||||||
Global Settlement | — | — | — | 43 | |||||||||||
EME discontinued operations | (1,686 | ) | (1,078 | ) | (608 | ) | 164 | ||||||||
Total Non-Core Items | (1,461 | ) | (1,113 | ) | (348 | ) | 284 | ||||||||
Core Earnings (Losses) | |||||||||||||||
SCE | 1,338 | 1,085 | 253 | 984 | |||||||||||
Edison International Parent and Other | (60 | ) | (9 | ) | (51 | ) | (12 | ) | |||||||
Edison International | $ | 1,278 | $ | 1,076 | $ | 202 | $ | 972 | |||||||
Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including lease terminations, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings. On December 17, 2012, EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of Illinois, Eastern Division. Edison International considers EME to be an abandoned asset under generally accepted accounting principles, and, as a result, the operations of EME prior to December 17, 2012 and for all prior years, are reflected as discontinued operations.
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SCE's 2012 core earnings increased $253 million for the year primarily due to rate base growth and lower income taxes which reflect the implementation of the 2012 CPUC General Rate Case ("GRC") decision. SCE also incurred incremental inspection and repair costs related to the outages at San Onofre of $66 million, net of SCE's share of amounts received from Mitsubishi Heavy Industries, Inc. ("MHI"), and $112 million in severance costs. Severance costs are related to employee reductions at San Onofre, as planned in the 2012 GRC, and approved employee reductions for 2013 as SCE works to optimize its cost structure and to minimize impacts on customer rates. These costs were partially offset by other operations and maintenance cost reductions.
Edison International Parent and Other 2012 core losses increased $51 million as a result of income tax benefits in 2011. Core losses in 2012 also reflect higher income taxes, a write-down of an investment and higher operating expenses and interest costs.
Consolidated non-core items for 2012 and 2011 for Edison International included:
• | An after-tax earnings charge of $1.3 billion during the fourth quarter of 2012 due to the full impairment of the investment in EME as a result of the deconsolidation of EME, recognition of losses previously deferred in accumulated other comprehensive income, a provision for losses from the EME bankruptcy and tax impacts related to the expected future tax deconsolidation and separation of EME from Edison International. See "Item 8. Notes to Consolidated Financial Statements—Note 17. Discontinued Operations" for further information. |
• | An after-tax earnings benefit of $231 million recorded in 2012 resulting from the regulatory treatment of 2009 – 2011 income tax repair deductions for income tax purposes as adopted in the 2012 GRC decision. See "Results of Operations—SCE—Income Taxes" for further discussion. |
• | An after-tax earnings charge of $37 million recorded in 2012 and $19 million recorded in 2011 resulting from Edison International's update to its estimated long-term California apportionment rate applicable to deferred income taxes as a result of changes related to EME. |
• | An after-tax earnings benefit of $31 million ($65 million pre-tax gain) recorded in 2012 attributable to Edison Capital's sale of its lease interest in Unit No. 2 of the Beaver Valley Nuclear Power Plant to a third party for $108 million. |
• | An after-tax earnings charge of $16 million recorded in 2011 attributable to the write-down of a net investment in aircraft leases with American Airlines. |
See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations, including a comparison of 2011 results to 2010.
2012 CPUC General Rate Case
In November 2012, the CPUC approved a final decision in SCE's 2012 GRC, authorizing a base rate revenue requirement of approximately $5.7 billion. The decision results in an increase of approximately $470 million, excluding revenue related to nuclear refueling outages, over currently authorized revenue. The decision approves San Onofre costs subject to refund and reasonableness review and includes a requirement to track those costs in a memorandum account. See “—San Onofre Outage, Inspection and Repair Issues” below for further information. In addition, SCE's proposed ratemaking treatment of repair deductions for income taxes was reflected in the revenue requirement adopted in the decision. See "Item 8. Notes to Consolidated Financial Statements—Note 7. Income Taxes" for further discussion.
The decision allows a ratemaking methodology that escalates capital additions by 3.05% for 2013 and 2.93% for 2014. The decision also allows operations and maintenance expense to be escalated for 2013 and 2014 through the use of various annual escalation factors for labor, non-labor and medical expenses. The methodology adopted in the decision and the 2013 escalation factors results in a 2013 revenue requirement of approximately $5.8 billion. SCE estimates that the 2014 revenue requirement would be approximately $6.2 billion using the decision methodology, estimated escalation factors and the reduction in the cost of capital discussed below.
San Onofre Outage, Inspection and Repair Issues
Two replacement steam generators were installed at San Onofre in each of Units 2 and 3 in 2010 and 2011, respectively. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators and the Unit was safely taken off-line. At the time, Unit 2 was off-line for a planned outage when areas of unexpected tube to support structure wear were found. Both Units have remained off-line for extensive inspections, testing and analysis of their steam generators. Each Unit will be restarted only when and if SCE determines that it is safe to do so
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and when start-up has been approved by the NRC pursuant to the terms of a Confirmatory Action Letter (“CAL”) issued by the NRC in March 2012.
Tube Leak and Repairs
The Unit 3 steam generator water leak was caused by unexpected excessive wear resulting from tube-to-tube contact in the area of the leak. Unit 2's steam generators were re-inspected using a more sensitive inspection method than had previously been employed, and similar wear from tube-to-tube contact was found on two tubes in one of the steam generators at wear levels below the detection capability of initial inspections. In contrast, Unit 3 experienced extensive tube to tube wear in a number of tubes. Both Unit 2 and Unit 3 also had tube-to-support structure wear.
As a result of these findings, SCE has plugged and removed from service all tubes showing excessive wear in each of the steam generators. In addition, SCE preventively plugged all tubes in contact with retainer bars or in the area of the tube bundles where tube-to-tube contact occurred. Each steam generator has over 9,700 heat transfer tubes and is designed to include sufficient tubes to accommodate removal of some tubes from service for a variety of reasons, and the tubes that have been removed from service are within this margin.
A team of outside experts was assembled to assist SCE and MHI, the manufacturer of the steam generators, to analyze the causes of the tube-to-tube wear and potential remedial actions. As a result of their work, SCE understands that the tube-to-tube contact arises from excessive vibration of the tubes in certain areas of the steam generators. The excessive vibration that caused the tube-to-tube wear in Unit 3 resulted from a phenomenon called fluid elastic instability. This phenomenon arises from a combination of thermal hydraulic conditions (steam velocity and moisture content of the steam), and ineffectiveness of the tube supports in the areas where the vibration occurs. Unit 2 is susceptible to the same thermal hydraulic conditions as Unit 3, but the Unit 2 tube supports largely remained effective for the entire time that it operated as compared to Unit 3.
SCE's Unit 2 restart plans and its response to the CAL are based on work done by engineering groups of three independent firms with expertise in steam generator design and manufacturing. Restart plans were submitted only for Unit 2 because it did not experience the extensive tube-to-tube wear that Unit 3 did. Using different methodologies, each independent outside engineering group agreed that it would be safe to restart Unit 2 and operate at a reduced power level (70%) for approximately five months, followed by a mid-cycle scheduled outage and inspection. In addition to these requirements, the restart plan covers repairs, corrective actions and operating parameters and also includes additional monitoring, detection and response activities. Inasmuch as Unit 3 had much more tube-to-tube wear than Unit 2, it remains unclear whether Unit 3 will be able to restart without additional repairs and corrective actions. The ability to restart Unit 3 may also be affected by the operating experience of Unit 2. Each Unit will only be restarted when any necessary repairs and appropriate mitigation plans for that Unit are completed in accordance with the CAL, and the NRC and SCE are satisfied that it is safe to do so.
SCE has also been engaged in the analysis of what repairs, if any, could be undertaken to restore the steam generators on both Units to their originally specified capabilities safely, and has been advised by MHI that a possible course of action would be replacement of significant portions of the steam generators, a process that could take more than five years.
NRC Processes
The CAL requires NRC permission to restart Unit 2 and Unit 3 and outlines actions SCE must complete before permission to restart either Unit may be sought. In October 2012, SCE submitted to the NRC a response to the CAL and restart plans for Unit 2. The timing of restart of the Units will be affected by the nature of and schedule for regulatory processes required by the NRC. There is no set or predetermined time period for approval of Unit 2's proposed restart, and, accordingly, there can be no assurance about the length of time the NRC may take to review SCE's request to restart or whether any such request will be granted in whole or in part. It is also possible that one or more amendments to the NRC operating license for San Onofre might be required (whether or not as a prerequisite to return a Unit to safe operation).
The NRC has been engaged in conducting a series of inspections, evaluations, reviews and public meetings about the causes of the steam generator malfunction and damage and to verify that SCE has performed the actions described in the CAL response and as otherwise required by its obligations as a nuclear operator. This process has included inspections and review by an NRC-appointed Augmented Inspection Team. SCE has been advised that the NRC's Office of Investigations has initiated an investigation into the accuracy and completeness of information SCE has provided to the NRC regarding the San Onofre steam generators. Should the NRC find a deficiency in SCE's performance or provision of information, SCE could be subject to additional NRC actions, including the imposition of penalties, and the findings could be taken into consideration in the CPUC regulatory proceedings described below.
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CPUC Review
Under California Public Utilities Code Section 455.5, SCE is required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months (not including preplanned outages). SCE provided such notice to the CPUC on November 1, 2012 for Unit 3 and December 6, 2012 for Unit 2. The CPUC is required within 45 days of SCE's notice for a particular Unit to initiate an investigation to determine whether to remove from customer rates some or the entire revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5, any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation.
In October 2012, in advance of SCE's required notification under Section 455.5, the CPUC issued an Order Instituting Investigation that consolidates all San Onofre issues in related regulatory proceedings and considers appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, substitute market power costs, capital expenditures, operations and maintenance costs, and seismic study costs. The Order requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent included in rates, collected subject to refund. The Order also states that the CPUC will determine whether to order the immediate removal, effective as of the date of the order, of all costs related to San Onofre from SCE's rates, with placement of those costs in a deferred debit account pending the return of one or both Units to useful service, or other possible action. It is currently expected that the investigation will be conducted in phases that will extend at least into 2014.
In parallel with the Order Instituting Investigation, the 2012 GRC final decision requires SCE to track San Onofre-related costs in a memorandum account subject to refund, beginning January 1, 2012. SCE filed an application in January 2013 seeking a reasonableness determination regarding these costs. That application has been consolidated with the Order Instituting Investigation proceeding.
Contractual Matters
The steam generators were designed and supplied by MHI and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions both in the contract and under law. SCE has notified MHI that it believes one or more of such exceptions now apply and that MHI's liability is not limited to $138 million, and MHI has advised SCE that it disagrees. The disagreement may ultimately become subject to dispute resolution procedures set forth in the purchase agreement, including international arbitration. SCE, on behalf of itself and the other San Onofre co-owners, has submitted three invoices to MHI totaling $106 million for steam generator repair costs incurred through October 31, 2012. MHI paid the first invoice of $45 million, while reserving its right to challenge any of the charges in the invoice. In January 2013, MHI advised SCE that it rejected a portion of the first invoice and required further documentation regarding the remainder of the invoice. SCE has recorded its share of the invoice paid as a reduction of repair and inspection costs.
San Onofre carries both property damage and outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. The property damage policy (including excess coverage) provides insurance for certain costs and expenses resulting from “Accidental Property Damage” with a $2.5 million deductible and a $2.75 billion limit of liability. After a twelve week deductible period, the outage policy provides insurance for an outage caused by “Accidental Property Damage” of up to $3.5 million per week for each Unit (or $2.8 million per Unit per week if both Units are out because of the same "Accident"), with a $490 million limit for each Unit ($392 million each if both Units are out because of the same "Accident"). The NEIL policies have a number of exclusions and limitations that may reduce or eliminate coverage.
In October 2012, SCE filed separate proofs of loss for Unit 2 and Unit 3 under the outage policy. Pursuant to these proofs of loss SCE is seeking the weekly indemnity amounts provided under the policy for each Unit. Because the outage is ongoing, SCE will supplement these proofs of loss in the future. No amounts have been recognized in SCE's financial statements, pending NEIL's response. To the extent any costs are recovered under the outage policy, SCE expects to refund those amounts to ratepayers through the ERRA balancing account. For further information, see "Item 8. Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
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Financial Summary
A summary of financial items related to SONGS is as follows:
• | The 2012 costs tracked in the memorandum account under the CPUC's Order Instituting Investigation include $613 million of SCE's 2012 authorized revenue requirement associated with operating and maintenance expenses, and depreciation and return on SCE's investment in Unit 2, Unit 3 and common plant. This amount is subject to refund depending on the outcome of the investigation. |
• | At December 31, 2012, SCE's rate base and net investment associated with San Onofre are set forth in the following table: |
(in millions) | Unit 2 | Unit 3 | Common Plant | Total | |||||||||||
Net Investment | |||||||||||||||
Net plant in service | $ | 638 | $ | 461 | $ | 233 | $ | 1,332 | |||||||
Materials and supplies | — | — | 101 | 101 | |||||||||||
Construction work in progress | 24 | 105 | 94 | 223 | |||||||||||
Nuclear fuel1 | 153 | 213 | 101 | 467 | |||||||||||
Net investment | $ | 815 | $ | 779 | $ | 529 | $ | 2,123 | |||||||
Tax basis | $ | 343 | $ | 360 | $ | 206 | $ | 909 | |||||||
Rate base | |||||||||||||||
Net plant in service | $ | 638 | $ | 461 | $ | 233 | $ | 1,332 | |||||||
Materials and supplies | — | — | 101 | 101 | |||||||||||
Accumulated deferred income taxes | (118 | ) | (75 | ) | (58 | ) | (251 | ) | |||||||
Amounts in rate base | $ | 520 | $ | 386 | $ | 276 | $ | 1,182 | |||||||
1 | In addition, SCE has contracted to purchase nuclear fuel. See "Liquidity and Capital Resources—Contractual Obligations and Contingencies" below. |
• | In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million based on SCE's estimate after adjustment for inflation using the Handy-Whitman Index) for SCE's 78.21% share of the costs to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $601 million through December 31, 2012 on the steam generator replacement project. These expenditures are included in the table above and remain subject to CPUC reasonableness review and approval. |
• | As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre are being purchased in the market by SCE (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market power costs through December 31, 2012 were approximately $300 million, net of avoided nuclear fuel costs, and are typically recoverable through the ERRA balancing account subject to CPUC reasonableness review, which will now take place as part of the CPUC's Order Instituting Investigation proceeding. Future market power costs cannot be estimated at this time due to uncertainties associated with when and at what output levels the Units will or may be returned to service; however, such amounts may be material. |
• | Through December 2012, SCE's share of incremental inspection and repair costs totaled $102 million for both Units (not including payments made by MHI as described below), and repairs to restart Unit 2 at the reduced power levels described above were completed. The costs for Unit 2 may increase following NRC review under the CAL. Total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain. SCE recorded its share of payments made to date by MHI ($36 million) as a reduction of incremental inspection and repair costs. |
SCE believes that the actions taken and costs incurred in connection with the San Onofre replacement steam generators and outages have been prudent. Accordingly, SCE considers its operating, capital, and market power costs, recoverable through base rates and the ERRA balancing account, as offset by third party recoveries where applicable. SCE cannot provide assurance that either or both Units of San Onofre will be returned to service, that the CPUC will not disallow costs incurred or order refunds to customers of amounts collected in rates, or that SCE will be successful in recovering amounts from third parties. A delay in the restart of San Onofre Unit 2 beyond this summer may impact plans for future operations of both Units.
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Disallowances of costs and/or refund of amounts received from customers could be material and adversely affect SCE's financial condition, results of operations and cash flows.
2013 Cost of Capital Application
In June 2012, the CPUC issued an order in the 2013 Cost of Capital proceeding consolidating SCE's 2013 application with the three other California investor-owned utilities' applications and splitting the proceeding into two phases. The first phase addressed the 2013 ratemaking capital structure and cost of capital for the utilities. The second phase considers whether the current cost of capital adjustment mechanism should be continued or modified.
In December 2012, the CPUC issued a final decision in the ratemaking capital structure and cost of capital phase of SCE's 2013 cost of capital proceeding granting SCE's requested ratemaking capital structure of 43% long-term debt, 9% preferred equity and 48% common equity. The decision adopted a return on common equity of 10.45% and adopted long-term debt and preferred stock costs of 5.49% and 5.79%, respectively. SCE has implemented the impacts of the decision in rates, effective January 1, 2013.
In February 2013, a proposed decision was issued in the second phase of the proceeding that provides for SCE's adjustment mechanism to continue for 2014 and 2015. The proposed decision also provides for the mechanism to automatically readjust SCE’s capital costs if certain thresholds are reached on an annual basis. A final decision for the second phase is expected in March 2013.
Capital Program
Total capital expenditures (including accruals) were $3.9 billion in both 2012 and 2011. Due to the delay in the GRC decision, the level of capital expenditures in 2012 was lower than anticipated. SCE's capital program for 2013 – 2014 is focused primarily in the following areas:
• | Maintaining reliability and expanding the capability of SCE's transmission and distribution system. |
• | Upgrading and constructing new transmission lines and substations for system reliability and increased access to renewable energy, including the Tehachapi, Devers-Colorado River, Eldorado-Ivanpah, and Red Bluff transmission and substation projects. |
• | Maintaining performance of SCE's natural gas, nuclear and hydro-electric generating plants. |
SCE forecasts capital expenditures in the range of $7.3 billion to $8.2 billion for 2013 – 2014. Actual capital spending will be affected by: changes in regulatory, environmental and engineering design requirements; permitting and project delays; cost and availability of labor, equipment and materials; and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plan." SCE continues to experience cost pressures on its Tehachapi and Devers-Colorado River Transmission Projects, primarily related to environmental monitoring and mitigation costs, scope changes and schedule delays. The Tehachapi Transmission Project has experienced further permitting and schedule delays. The Project may be further impacted by CPUC proceedings to reexamine construction options, including possibly undergrounding lines, for a portion of the Project and by issues related to aviation marking and lighting and community opposition to portions of the line, as further discussed in "SCE: Liquidity and Capital Resources—Capital Investment Plan."
EME Chapter 11 Bankruptcy Filing
During 2012, EME continued to experience operating losses due to low realized energy and capacity prices, high fuel costs and low generation at the Midwest Generation plants. Forward market prices indicate that these trends are expected to continue for a number of years. A continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its Midwest Generation plants to comply with governmental regulations, ultimately caused EME and certain of its wholly-owned subsidiaries to file voluntary petitions on the Petition Date for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On December 16, 2012, Edison International, EME and certain of EME's senior unsecured noteholders entered into Support Agreement, that, subject to further documentation, Bankruptcy Court approval and certain other conditions, provides that:
• | Edison International will cease to own EME when EME emerges from bankruptcy pursuant to a plan of reorganization. |
• | The tax allocation agreements with respect to EME will be extended through the earlier of the effective date of a plan of reorganization or December 31, 2014, and EME will remain bound to perform its obligations under such agreements. |
• | Edison International and EME will continue to provide ongoing shared services to each other in the ordinary course, consistent with the same terms and conditions on which those services have been provided in the past. |
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• | Upon effectiveness of EME's plan of reorganization, Edison International will assume certain of EME's employee retirement related liabilities. |
• | Edison International, EME and the noteholders who have signed the Support Agreement will exchange releases of claims, and EME and Edison International will cross-indemnify one another against liabilities arising from the conduct of their separate businesses. |
Under the Support Agreement, within 150 days following the Petition Date, EME will seek authority from the Bankruptcy Court to enter into the Settlement Transaction, which must be obtained within 210 days following the Petition Date or the Support Agreement is subject to termination. There can be no assurance that the Bankruptcy Court will approve the Settlement Transaction, and even if it is approved, there can be no assurance that the conditions to the effectiveness of the Settlement Transaction will be satisfied. In addition, EME is entitled to terminate the Support Agreement and consider alternative transactions in accordance with its fiduciary duties.
In anticipation of EME's Chapter 11 filing, Edison International's representatives, who previously served on the EME Board of Directors, resigned. EME and those subsidiaries in Chapter 11 proceedings retain control of their assets and are authorized to operate their businesses as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Edison International no longer retains significant influence over the ongoing operations of EME.
Edison International anticipates that the Bankruptcy Court will approve a plan of reorganization in which Edison International ceases to have any ownership interest as provided in the Support Agreement. As a result of the bankruptcy filing, Edison International no longer consolidates the earnings and losses of EME or its subsidiaries effective December 17, 2012 and has reflected its ownership interest in EME utilizing the cost method of accounting prospectively, under which Edison International's investment in EME is reflected as a single amount on the Consolidated Balance Sheet of Edison International at December 31, 2012. Furthermore, Edison International has recorded a full impairment of the investment in EME as a result of the deconsolidation of EME, recognition of losses previously deferred in accumulated other comprehensive income, a provision for losses from the EME bankruptcy and estimated tax impacts related to the expected future tax deconsolidation and separation of EME from Edison International. The aggregate impact of these matters resulted in an after tax charge of $1.3 billion during the fourth quarter of 2012. In addition, for the reasons described above, Edison International considers EME to be an abandoned asset under generally accepted accounting principles, and, as a result, the operations of EME prior to December 17, 2012 and for all prior years, are reflected as discontinued operations in the consolidated financial statements. See "Item 8. Notes to Consolidated Financial Statements—Note 17. Discontinued Operations" for additional information related to these bankruptcy proceedings.
RESULTS OF OPERATIONS
SCE
SCE's results of operations are derived mainly through two sources:
• | Utility earning activities – representing revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of authorized operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in utility earnings activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any. |
• | Utility cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery of specific project or program costs, subject to reasonableness review or compliance with upfront standards. Utility cost-recovery activities include rates which provide recovery, subject to reasonableness review of, among other things, fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses and nuclear decommissioning expenses. |
The following tables summarize SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities. Beginning in 2012, SCE classified revenues and costs related to programs that provide for recovery of actual costs plus a return on capital as utility earning activities. Previously, SCE classified the recovery of actual costs incurred under these programs as utility cost-recovery activities. In addition, the 2012 GRC decision eliminated the balancing account treatment for Palo Verde operation and maintenance costs effective January 1, 2012. The tables presented below reflect a reclassification of the revenues and costs for 2011 and 2010 consistent with the presentation in 2012. The reclassification of revenues and costs had no impact on earnings.
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The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earnings activities and utility cost-recovery activities:
2012 | 2011 | 2010 | |||||||||||||||||||||||||
(in millions) | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | ||||||||||||||||||
Operating revenue | $ | 6,682 | $ | 5,169 | $ | 11,851 | $ | 6,257 | $ | 4,320 | $ | 10,577 | $ | 5,837 | $ | 4,146 | $ | 9,983 | |||||||||
Fuel and purchased power | — | 4,139 | 4,139 | — | 3,356 | 3,356 | — | 3,293 | 3,293 | ||||||||||||||||||
Operations and maintenance | 2,518 | 1,026 | 3,544 | 2,423 | 964 | 3,387 | 2,439 | 852 | 3,291 | ||||||||||||||||||
Depreciation decommissioning and amortization | 1,562 | — | 1,562 | 1,426 | — | 1,426 | 1,273 | — | 1,273 | ||||||||||||||||||
Property taxes and other | 296 | (1 | ) | 295 | 285 | — | 285 | 263 | — | 263 | |||||||||||||||||
Disallowances and other | 32 | — | 32 | — | — | — | — | (1 | ) | (1 | ) | ||||||||||||||||
Total operating expenses | 4,408 | 5,164 | 9,572 | 4,134 | 4,320 | 8,454 | 3,975 | 4,144 | 8,119 | ||||||||||||||||||
Operating income | 2,274 | 5 | 2,279 | 2,123 | — | 2,123 | 1,862 | 2 | 1,864 | ||||||||||||||||||
Net interest expense and other | (400 | ) | (5 | ) | (405 | ) | (378 | ) | — | (378 | ) | (330 | ) | (2 | ) | (332 | ) | ||||||||||
Income before income taxes | 1,874 | — | 1,874 | 1,745 | — | 1,745 | 1,532 | — | 1,532 | ||||||||||||||||||
Income tax expense | 214 | 214 | 601 | 601 | 440 | 440 | |||||||||||||||||||||
Net income | 1,660 | — | 1,660 | 1,144 | — | 1,144 | 1,092 | — | 1,092 | ||||||||||||||||||
Dividends on preferred and preference stock | 91 | — | 91 | 59 | — | 59 | 52 | — | 52 | ||||||||||||||||||
Net income available for common stock | $ | 1,569 | $ | — | $ | 1,569 | $ | 1,085 | $ | — | $ | 1,085 | $ | 1,040 | $ | — | $ | 1,040 | |||||||||
Core Earnings1 | $ | 1,338 | $ | 1,085 | $ | 984 | |||||||||||||||||||||
Non-Core Earnings | |||||||||||||||||||||||||||
2012 General Rate Case – repair deductions (2009 – 2011) | 231 | — | — | ||||||||||||||||||||||||
Global Settlement | — | — | 95 | ||||||||||||||||||||||||
Tax impact of health care legislation | — | — | (39 | ) | |||||||||||||||||||||||
Total SCE GAAP Earnings | $ | 1,569 | $ | 1,085 | $ | 1,040 | |||||||||||||||||||||
1 | See use of non-GAAP financial measures in "Management Overview—Highlights of Operating Results." |
Utility Earning Activities
2012 vs 2011
Utility earning activities were primarily affected by the following:
• | Higher operating revenue was primarily due to the following: |
• | $375 million increase in revenue related to the implementation of the 2012 GRC decision. The decision authorized a revenue requirement increase of approximately $470 million over the 2011 authorized revenue, excluding nuclear refueling outages ($95 million of which is reflected in utility cost-recovery activities primarily related to employee benefits); and |
• | $60 million increase in revenue related to authorized CPUC projects not included in SCE's GRC authorized revenue, including the EdisonSmartConnect® project and the Solar Photovoltaic project. |
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• | Higher operation and maintenance expense due to the following: |
• | $112 million in accrued severance costs from current and approved reductions in staffing; |
• | $66 million in incremental inspection and repair costs related to the outages at San Onofre, net of SCE's share of payments received from MHI; and |
• | $85 million of lower costs related to information technology, transmission and distribution expenses, San Onofre and benefits realized from EdisonSmartConnect®. |
• | Higher depreciation, decommissioning and amortization expense of $136 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs. |
• | $32 million charge due to the 2012 GRC decision disallowing capitalized costs incurred as part of SCE's implementation of SAP's Enterprise Resource Planning system. |
• | Higher net interest expense and other of $22 million was primarily due to higher outstanding balances on long-term debt due to new issuances. For further details of other income and expenses, see "Item 8. Notes to Consolidated Financial Statements—Note 16. Other Income and Expenses." |
• | Lower income taxes primarily due to an earnings benefit resulting from the regulatory treatment adopted in the 2012 GRC for tax repair deductions for income tax purposes. See "—Income Taxes" below for more information. |
• | Higher preferred and preference stock dividends of $32 million related to new issuances in 2012. |
2011 vs 2010
Utility earning activities were primarily affected by the following:
• | Higher operating revenue primarily due to the following: |
• | $135 million increase primarily due to a $215 million (4.35%) increase in 2011 authorized revenue approved in the 2009 CPUC GRC decision. The 2011 increase was partially offset by reductions of $80 million mainly resulting from revenue recognized in 2010 associated with the recovery of San Onofre Unit 3 scheduled outage costs with no comparable amount in 2011; |
• | $125 million in revenue related to authorized CPUC projects not included in SCE's GRC process, primarily related to the San Onofre steam generator replacement project, the EdisonSmartConnect® project and the Solar Photovoltaic project; |
• | $95 million increase in FERC-related revenue primarily resulting from the inclusion of capital expenditures related to the Tehachapi Transmission Project in rate base; |
• | $25 million increase in capital-related revenue requirements related to the San Onofre steam generator replacement project and a $20 million increase for the EdisonSmartConnect® project; and |
• | $20 million increase related to recovery of legal costs incurred between 2004 and 2009 in support of SCE's efforts to obtain generator refunds related to claims arising out of the energy crisis in California in 2000 – 2001. |
• | Higher depreciation, decommissioning and amortization expense of $153 million primarily related to increased transmission and distribution investments. |
• | Higher net interest expense and other of $48 million primarily due to higher outstanding balances on long-term debt. For details of other income and expenses, see "Item 8. Notes to Consolidated Financial Statements—Note 16. Other Income and Expenses." |
• | Higher income taxes primarily due to an increase in income as well as benefits recorded in 2010 related to the Global Settlement. See "—Income Taxes" below for more information. |
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Utility Cost-Recovery Activities
2012 vs. 2011
Utility cost-recovery activities were primarily affected by the following:
• | Higher fuel and purchased power expense of $783 million was primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below) and $300 million of market costs net of lower nuclear fuel costs related to the San Onofre outages in 2012 (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information). |
• | Higher operation and maintenance expense of $62 million was primarily due to an increase in pension and postretirement benefit contributions. |
2011 vs. 2010
Utility cost-recovery activities were primarily affected by the following:
• | Higher purchased power expense of $59 million primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but impacted customer bills (see "—Supplemental Operating Revenue Information" below), and higher costs associated with renewable contracts. The increase was partially offset by increased purchased power in 2010 during the outages at San Onofre and Four Corners. |
• | Higher operation and maintenance expense of $112 million primarily due to an increase in spending for various public purpose programs. |
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $11.1 billion for 2012 and $10.0 billion for both 2011 and 2010. The 2012 revenue reflects:
• | A sales volume increase of $1.4 billion, primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011, partially offset by |
• | A rate decrease of $344 million, resulting from rate adjustments in June 2011 and August 2012, primarily reflecting lower natural gas prices and refunds to customers of over-collected fuel and power procurement-related costs. |
The 2011 revenue reflects:
• | A rate decrease of $408 million resulting from a rate adjustment beginning on June 1, 2011, primarily reflecting the refund of over collected fuel and power procurement-related costs, offset by |
• | A sales volume increase of $393 million primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011. |
The 2010 revenue reflects:
• | A rate increase of $777 million mainly due to the implementation of the CPUC 2009 GRC decision and approved FERC transmission rate changes, partially offset by |
• | A sales volume decrease of $255 million primarily due to milder weather experienced during 2010 compared to the same period in 2009 and continuing recessionary effects. |
As a result of the CPUC-authorized decoupling mechanism, SCE earnings are not affected by changes in retail electricity sales (see "Item 1. Business—Overview of Ratemaking Process").
SCE remits to CDWR and does not recognize as revenue the amounts that SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, as well as CDWR bond-related costs and a portion of direct access exit fees. The amounts collected and remitted to CDWR were $44 million, $1.1 billion and $1.2 billion for years ended December 31, 2012, 2011 and 2010, respectively. All CDWR power contracts allocated to SCE by the CPUC expired by the end of 2011.
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Income Taxes
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.
Years ended December 31, | ||||||||||||
(in millions) | 2012 | 2011 | 2010 | |||||||||
Income from continuing operations before income taxes | $ | 1,874 | $ | 1,745 | $ | 1,532 | ||||||
Provision for income tax at federal statutory rate of 35% | 656 | 611 | 536 | |||||||||
Increase (decrease) in income tax from: | ||||||||||||
Items presented with related state income tax, net: | ||||||||||||
2012 General Rate Case – repair deductions1 | (231 | ) | * | — | — | |||||||
Global Settlement related2 | — | — | (95 | ) | * | |||||||
Change in tax accounting method for asset removal costs3 | — | — | (40 | ) | * | |||||||
State tax, net of federal benefit | 54 | 80 | 59 | |||||||||
Health care legislation4 | — | — | 39 | * | ||||||||
Property-related5 | (223 | ) | (46 | ) | (92 | ) | ||||||
Accumulated deferred income tax adjustments | (41 | ) | (30 | ) | — | |||||||
Tax reserve | 36 | (3 | ) | 45 | ||||||||
Other | (37 | ) | (11 | ) | (12 | ) | ||||||
Total income tax expense from continuing operations | $ | 214 | $ | 601 | $ | 440 | ||||||
Effective tax rate | 11.4 | % | 34.4 | % | 28.7 | % | ||||||
* | These items are reflected as non-core benefits or charges. See use of Non-GAAP financial measures in "Management Overview—Highlights of Operating Results." |
1 | As discussed below, SCE recorded a $231 million earnings benefit in the fourth quarter of 2012, resulting from the flow-through regulatory treatment for certain repair costs for 2009 – 2011 as adopted in the 2012 GRC. |
2 | Edison International and the IRS finalized the terms of a Global Settlement on May 5, 2009. The Global Settlement resolved all of SCE's federal income tax disputes and affirmative claims through tax year 2002. During 2010, SCE recognized a $95 million earnings benefit from the acceptance by the California Franchise Tax Board of the tax positions finalized in 2009 and receipt of the final interest determination from the Franchise Tax Board. |
3 | During 2010, the IRS approved SCE's request to change its tax accounting method for asset removal costs primarily related to its infrastructure replacement program. As a result, SCE recognized a $40 million earnings benefit (of which $28 million relates to asset removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions were recorded on a flow-through basis as required by the CPUC. |
4 | During 2010, SCE recorded a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies. |
5 | Incremental repair benefit recorded in 2012. See discussion of repair deductions below. |
2012 GRC Earnings Benefit from Repair Deductions
Edison International made a voluntary election in 2009 to change its tax accounting method for certain repair costs incurred on SCE's transmission, distribution and generation assets. Regulatory treatment for the incremental deductions taken after the 2009 election to change SCE's tax accounting method for certain repair costs was included as part of SCE's 2012 GRC. The 2012 GRC decision retained flow-through treatment of repair deductions for regulatory purposes, which resulted in SCE recognizing an earnings benefit of $231 million from these incremental deductions taken in 2009, 2010 and 2011. The earnings benefit results from recognition of a regulatory asset for recovery of deferred income taxes in future periods due to the flow-through treatment of repair deduction for income tax purposes. The 2012 earnings benefits from incremental repair deductions following the same regulatory treatment was $115 million (classified as property related in the above table) and the earnings benefit for 2013 is estimated to be approximately $50 million.
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For a discussion of the status of Edison International's income tax audits, see "Item 8. Notes to Consolidated Financial Statements—Note 7. Income Taxes."
Edison International Parent and Other
Results of operations for Edison International Parent and Other includes amounts from other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations. As a result of EME's bankruptcy, EME and its subsidiaries were deconsolidated and reported as discontinued operations for all periods presented. For additional information, see "Management Overview—EME Chapter 11 Bankruptcy Filing." Since the continuing operations of the competitive power generation segment was no longer significant enough to be reported separately, this segment has been combined into Edison International Parent and Other for all periods presented.
Income from Continuing Operations
Edison International Parent and Other loss from continuing operations is comprised of the following:
Years ended December 31, | |||||||||||
(in millions) | 2012 | 2011 | 2010 | ||||||||
Income (loss) from continuing operations | |||||||||||
Edison International Parent | $ | (85 | ) | $ | (33 | ) | $ | (8 | ) | ||
EMG | 19 | (11 | ) | 60 | |||||||
Edison International Parent and Other | (66 | ) | (44 | ) | 52 | ||||||
Less: Non-Core Items: | |||||||||||
Edison International Parent: | |||||||||||
Consolidated state deferred tax impact related to EME | (37 | ) | (19 | ) | 21 | ||||||
Global Settlement | — | — | 7 | ||||||||
EMG: | |||||||||||
Gain on sale of Beaver Valley lease interest | 31 | — | — | ||||||||
Write-down of net investment in aircraft leases | — | (16 | ) | — | |||||||
Global Settlement | — | — | 36 | ||||||||
Total Non-Core Items | (6 | ) | (35 | ) | 64 | ||||||
Core Earnings (Losses) | |||||||||||
Edison International Parent | (48 | ) | (14 | ) | (36 | ) | |||||
EMG | (12 | ) | 5 | 24 | |||||||
Edison International Parent and Other | $ | (60 | ) | $ | (9 | ) | $ | (12 | ) | ||
See "Management Overview—Highlights of Operating Results" for use of non-GAAP financial measures and for a description of the above non-core items.
The Edison International Parent core loss in 2012 increased from 2011 as a result of income tax benefits in 2011 including a cumulative deferred tax adjustment related to employee benefits and a reduction in consolidated amounts for uncertain tax positions. In addition, the core loss in 2012 included higher operating expenses and interest costs.
The EMG core loss in 2012 was primarily due to increases in deferred income taxes as a result of higher state apportionment rates and a write down of an investment. The results in 2011 were lower than 2010 due to income tax benefits recorded in 2010 from changes in estimated interest costs related to uncertain tax positions.
Income (Loss) from Discontinued Operations
Income (loss) from discontinued operations, net of tax, was $(1.7 billion), $(1.1 billion) and $164 million for the years ended December 31, 2012, 2011 and 2010, respectively. The 2012 loss reflects an earnings charge of $1.3 billion due to the full impairment of the investment in EME during the fourth quarter of 2012 as a result of the deconsolidation of EME, recognition of losses previously deferred in accumulated other comprehensive income, a provision for losses from the EME bankruptcy and estimated tax impacts related to the expected future tax deconsolidation and separation of EME from Edison International. The 2012 loss also reflects a $53 million earnings charge associated with the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. The 2011 loss reflects an earnings charge of
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$1.05 billion recorded in the fourth quarter of 2011 resulting primarily from the impairment of the Homer City, Fisk, Crawford and Waukegan power plants and wind related charges. In addition to the charges recorded in 2012 and 2011 the increase in loss also reflects lower average realized energy and capacity prices and lower generation at the Midwest Generation plants and decreased earnings from natural gas-fired projects. For additional information, see "Item 8. Notes to Consolidated Financial Statements—Note 17. Discontinued Operations."
LIQUIDITY AND CAPITAL RESOURCES
SCE
SCE's ability to operate its business, fund capital expenditures, and implement its business strategy is dependent upon its cash flow and access to the capital markets. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, interest and dividend payments to Edison International, and the outcome of tax and regulatory matters.
SCE expects to fund its 2013 obligations, capital expenditures and dividends through operating cash flows, tax benefits (including bonus depreciation) and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities to fund requirements.
In January 2013, SCE issued 160,004 shares of 5.10% Series G preference stock (cumulative, $2,500 liquidation value) to SCE Trust II, a special purpose entity formed to issue trust securities as discussed in "Item 8. Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities." The proceeds from the sale of these shares will be used to redeem all outstanding shares of Series B and C preference stock.
Available Liquidity
During 2012, SCE replaced its existing credit facilities scheduled to mature in early 2013 with a new $2.75 billion five-year revolving credit facility that matures May 2017. The following table summarizes the status of the SCE credit facility at December 31, 2012:
(in millions) | |||
Commitment | $ | 2,750 | |
Outstanding borrowings supported by credit facilities | (175 | ) | |
Outstanding letters of credit | (162 | ) | |
Amount available | $ | 2,413 | |
Debt Covenant
The debt covenant in SCE's credit facility limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At December 31, 2012, SCE's debt to total capitalization ratio was 0.44 to 1.
Capital Investment Plan
SCE's forecasted capital expenditures for 2013 – 2014 include a capital forecast in the range of $7.3 billion to $8.2 billion based on the average variability experienced in 2012, 2011 and 2010 of 10% between annual forecast capital expenditures and actual spending. The completion of projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, weather and other unforeseen conditions.
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SCE's 2012 capital expenditures and the 2013 – 2014 capital expenditures forecast are set forth in the table below:
(in millions) | 2012 Actual | 2013 | 2014 | 2013 – 2014 Total | |||||||||
Transmission | $ | 1,390 | $ | 1,396 | $ | 802 | $ | 2,198 | |||||
Distribution | 1,995 | 2,329 | 2,617 | 4,946 | |||||||||
Generation | 526 | 485 | 532 | 1,017 | |||||||||
Total Estimated Capital Expenditures1 | $ | 3,911 | $ | 4,210 | $ | 3,951 | $ | 8,161 | |||||
Total Estimated Capital Expenditures for 2013 – 2014 (using 10% variability discussed above) | $ | 3,789 | $ | 3,555 | $ | 7,344 | |||||||
1 | Included in SCE's capital expenditures plan are projected environmental capital expenditures of $599 million and $634 million in 2013 and 2014, respectively. The projected environmental capital expenditures are to comply with laws, regulations, and other nondiscretionary requirements. |
Transmission Projects
A summary of SCE's large transmission and substation projects during the next two years is presented below:
Project Name | Description | Project Lifecycle Phase | Scheduled in Service Date | Direct Expenditures1(in millions) | % of Spend Complete | 2013 – 2014 Forecast (in millions) | |||||
Tehachapi 1-11 | Transmission lines and substation | In construction | 2009 – 2015 | $ | 2,500 | 78 | % | $ | 455 | ||
Devers-Colorado River | Transmission line and upgraded substation | ||||||||||