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, 2013 | |
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, 2013, the last business day of the most recently completed second fiscal quarter:
Edison International Approximately $15.7 billion Southern California Edison Company Wholly owned by Edison International
Common Stock outstanding as of February 21, 2014: | ||
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 registrants' joint 2014 Annual Meeting of Shareholders Part III
TABLE OF CONTENTS
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ii
Nuclear Decommissioning – Asset Retirement Obligation | ||||
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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.
2013 Form 10-K | Edison International's Annual Report on Form 10-K for the year-ended December 31, 2013 | |
2010 Tax Relief Act | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
Amended Plan of Reorganization | EME Chapter 11 Bankruptcy Plan of Reorganization as amended to incorporate the terms of the Settlement Agreement, dated February 19, 2014 | |
APS | Arizona Public Service Company, operator of Four Corners | |
ARO(s) | asset retirement obligation(s) | |
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 | |
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 generation, 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., a wholly owned subsidiary of Edison International and the parent company of EME and Edison Capital | |
EPS | earnings per share | |
ERRA | energy resource recovery account | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
Four Corners | coal fueled electric generating facility located in Farmington, New Mexico in which SCE held a 48% ownership interest | |
GAAP | generally accepted accounting principles | |
GHG | greenhouse gas | |
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. | |
Moody's | Moody's Investors Service | |
MW | megawatts | |
MWh | megawatt-hours | |
NAAQS | national ambient air quality standards | |
NEIL | Nuclear Electric Insurance Limited | |
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 | |
OII | Order Instituting Investigation | |
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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 common equity | |
S&P | Standard & Poor's Ratings Services | |
San Onofre | retired nuclear 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 Agreement | Settlement Agreement by and among Edison Mission Energy, Edison International and the Consenting Noteholders identified therein, dated February 18, 2014 | |
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:
• | ability of SCE to recover its costs in a timely manner from its customers through regulated rates, including regulatory assets related to San Onofre and under-collection of fuel and purchased power costs; |
• | decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities and delays in regulatory actions; |
• | ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms; |
• | 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 power generating facilities including: public safety issues, failure, availability, efficiency, and output of equipment and availability and cost of spare parts; |
• | risks associated with the retirement and decommissioning of nuclear generating facilities; |
• | physical security of SCE's critical assets and personnel and the cyber security of SCE's critical information technology systems for grid control, and business and customer data; |
• | cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs to replace power and voltage support that was previously provided by San Onofre or in the event of 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; |
• | risk that the costs incurred in connection with San Onofre may not be recoverable from SCE's supplier or insurance coverage; |
• | approval of the Amended Plan of Reorganization, including the Settlement Agreement, in connection with the EME bankruptcy and proceedings related to it; |
• | 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; |
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• | 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; |
• | 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; |
• | extent of technological change in the generation, storage, transmission, distribution and use of electricity; |
• | cost and availability of emission credits or allowances for emission credits; |
• | 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
CORPORATE STRUCTURE, INDUSTRY AND OTHER INFORMATION
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 primarily related to the generation, 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 and delivering electricity to an approximately 50,000 square-mile area of southern California. The SCE service area contains a population of nearly 14 million people and SCE serves the population through approximately 5 million customer accounts. In 2013, SCE's total operating revenue of $12.6 billion was derived as follows: 41.6% commercial customers, 40.2% residential customers, 7% agricultural and other customers, 5.5% industrial customers, 5.1% public authorities, and 0.6% resale sales. Sources of energy to serve SCE's customers during 2013 were approximately: 79% purchased power and 21% SCE-owned generation.
Prior to December 17, 2012, Edison International had a competitive power generation segment, 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. As a result of the bankruptcy filing and beginning on the Petition Date, Edison International determined that it no longer retained significant influence over EME and accordingly, EME's results of operations have not been 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. For further information regarding the EME bankruptcy, see "Management Overview—EME Chapter 11 Bankruptcy Filing" in the MD&A and "Item 8. Notes to Consolidated Financial Statements—Note 16. Discontinued Operations."
Edison Capital holds energy and infrastructure investments in the form of leveraged leases and partnership interests in affordable housing projects in the United States.
Edison International also has several subsidiaries that have been formed to hold equity interests and engage in businesses in emerging sectors of the electricity industry. To date, the holdings of these subsidiaries are not material for financial reporting purposes. In August 2013, Edison International acquired SoCore Energy, LLC, a distributed solar developer focused on commercial rooftop installations.
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Electric Power Industry Trends
Multiple factors are converging to put the electric power industry on the cusp of significant change. These factors include:
• | leveling of demand due to decelerating population growth, demand side management of energy and an increase in distributed- or self-generation; |
• | prioritization by public policymakers of initiatives to reduce carbon emissions and advance competition; |
• | increased need for infrastructure replacement and development to accommodate new technologies; and |
• | technological and financing innovation that facilitates conservation and self-generation and changes in electricity generation, transmission and distribution. |
Edison International has been addressing these changes by focusing SCE on investing in and strengthening its electric grid and driving operational and service excellence to improve system safety, reliability and service while controlling costs and rates. Simultaneously, Edison International is investing in Competitive Businesses to meet the electricity needs of commercial and industrial customers both inside and beyond SCE's service area. 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.
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, imposed 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, 2013, Edison International and its consolidated subsidiaries had an aggregate of 13,677 full-time employees, 13,599 of which were full-time employees at SCE.
Approximately 4,000 of SCE's full-time employees are covered by collective bargaining agreements with one labor union; the International Brotherhood of Electrical Workers, Local 47, AFL-CIO ("IBEW"). The IBEW collective bargaining agreements expire on December 31, 2014.
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 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 12. Commitments and Contingencies."
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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, SCE capital structure, 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, rate of return, 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, including supervisory control and data acquisition systems for the electric grid. 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 covers SCE's information technology systems as well as customer data. 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 FERC, the CPUC and other state regulatory agencies depending on the project location; the CAISO, and other 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
The NRC has jurisdiction with respect to the safety of the 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. In June 2013, SCE decided to permanently retire and decommission San Onofre. For further information, see "Management Overview—Permanent Retirement of San Onofre " in the MD&A.
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”) on a forecast basis. The CPUC sets an annual revenue requirement for the base year which is made up of the operation and maintenance costs, depreciation, taxes and a return consistent with the authorized cost of capital (discussed below). The return is established by multiplying an authorized rate of return, determined in separate cost of capital
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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 and additional changes in capital-related investments.
SCE's 2012 GRC authorized revenue requirements for 2012, 2013, and 2014 of $5.7 billion, $5.8 billion, and $6.2 billion, respectively. In November 2013, SCE filed its 2015 GRC application that requested a 2015 base rate revenue requirement of $6.4 billion. For further discussion of the 2015 GRC, see “Management Overview—2015 General Rate Case” in the MD&A.
CPUC rates decouple authorized revenue from the volume of electricity sales so that SCE receives 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.
The CPUC regulates SCE's cost of capital, including its capital structure and authorized rates of return. SCE's authorized capital structure is 43% long-term debt, 9% preferred equity and 48% common equity. SCE's authorized cost of capital, effective January 1, 2013, 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%. In 2013, the CPUC authorized SCE's cost of capital adjustment mechanism to continue for 2014 and 2015. The mechanism provides for an automatic adjustment to SCE's authorized cost of capital if the utility bond index changes beyond certain thresholds on an annual basis. The index changes did not exceed the threshold in September 2013 so the return on common equity will remain at 10.45% for 2014. SCE will reevaluate the cost of capital for 2015 in September 2014 and the capital adjustment mechanism will set SCE's 2015 cost of capital.
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 energy efficiency and 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 balancing account. 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 2014, the trigger amount is approximately $289 million. At December 31, 2013, SCE's undercollection in the ERRA balancing account was approximately $1 billion, due to delays in regulatory decisions and the deferral of San Onofre costs to the OII proceeding. For further information on the status of the ERRA undercollection, see "Management Overview—ERRA Balancing Account" in the MD&A.
The majority of procurement-related costs eligible for recovery through cost-recovery rates are pre-approved by the CPUC through specific decisions and 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 (also referred to as "rate base"). In November 2013, the FERC approved SCE's settlement 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 updated to actual cost of service annually. The transmission revenue requirement and rates are updated each December, to reflect a forecast of costs for the upcoming rate period, as well as a true up of the transmission revenue to actual costs incurred by SCE in the prior calendar year on its formula rate. The FERC weighted average ROE, including project and other incentives, is 10.45% and will remain in effect until at least June 30, 2015, when the moratorium, provided for in the settlement, on modifications to the formula rate tariff ends. For further information on the current FERC formula rates, related transmission revenue requirements and rate changes, see “Liquidity and Capital Resources—SCE—Regulatory Proceedings—FERC Formula Rates” in the MD&A.
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Retail Rates Structure
To develop retail rates, the authorized revenue requirements are allocated among all customer classes (residential, commercial, industrial, agricultural and street lighting) 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.
SCE has a four-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 allowances 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 allowance 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. Although, for more than a decade, statutory restrictions on increasing Tier 1 and 2 rates resulted in shifting much of the cost of residential rate increases to the higher tier/usage customers, the California legislature passed a law ("AB 327") in October 2013 that lifts the restrictions on Tier 1 and 2 rates. The law also returns to the CPUC the authority to authorize an increase in residential customer charges (beginning in January 2015 at the earliest, which can aid in recovering more of SCE’s fixed costs of serving residential customers. In connection with an open rulemaking proceeding at the CPUC, SCE has proposed to reduce the rate ratio between the four tiers so that more revenues are collected from Tier 1 and 2 customers, which will relieve the pressure on upper-tier rates, and a decision is expected on this proposal by summer 2014. SCE also expects to include a proposal for an increased customer charge in a subsequent phase of the rulemaking.
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. In September 2013, the CPUC adopted a new energy efficiency incentive mechanism called the Energy Savings and Performance Incentive Mechanism ("ESPI"). The ESPI will apply starting with the 2013 – 2014 energy efficiency program cycle and continue for subsequent cycles, until further notice. The ESPI is comprised of performance/savings rewards and management fees based on actual energy efficiency expenditures and does not contain any provisions for penalties. The proposed ESPI schedule for earning claims anticipates payments of the incentive rewards occurring between one and two years after the relevant program year. For further discussion of SCE's energy efficiency incentive awards, see "Liquidity and Capital Resources—SCE—Regulatory Proceedings—Energy Efficiency Incentive Mechanism" in the MD&A.
Purchased Power and Fuel Supply
SCE obtains power needed to serve its customers primarily from purchases from qualifying facilities, independent power producers, the CAISO, and other utilities as well as from its generating facilities.
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
SCE had various nuclear fuel supply commitments for San Onofre Units 2 and 3. As a result of the decision to permanently retire San Onofre Units 2 and 3, SCE has submitted fuel contract delivery cancellation notices for these contractual arrangements. For more information, see "Management Overview—Permanent Retirement of San Onofre" in the MD&A and "Item 8. Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Other Contingencies."
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For Palo Verde, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below.
Uranium concentrates | 2016 |
Conversion | 2016 |
Enrichment | 2020 |
Fabrication | 2016 |
CAISO Wholesale Energy Market
In California and other states, there are wholesale energy markets through which competing electricity generators offer their electricity output to market participants, including 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 for 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 area. 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
SCE faces retail competition in the sale of electricity to the extent that federal and California laws permit other entities to provide electricity and related services to customers within SCE's service area. While California law provides only limited opportunities for customers in SCE's service area 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 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.
SCE also 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.
Distributed power generation’s competitiveness has been fostered by legislation passed in 1995, when distributed power generation systems were first introduced to the marketplace. The legislation was meant to encourage private investment in renewable energy resources by both residential and non-residential customers and required SCE to offer a net energy metering ("NEM") billing option to customers who install eligible distributed power generation systems to supply all or part of their energy needs. SCE is required to offer the NEM option until the total generating capacity used by NEM customers exceeds 10% of SCE’s aggregate customer peak demand (the "NEM Cap").
NEM customers are interconnected to SCE’s grid and credited for the net difference between the electricity SCE supplied to them through the grid and the electricity the customer exported to SCE over a twelve month period. SCE is required to credit the NEM customer for the power they sell back to SCE at the full retail rate. Through the credit they receive, NEM customers effectively avoid paying costs for the grid, which include all of the fixed costs of the poles, wires, meters, advanced technologies, and other infrastructure that makes the grid safe, reliable, and able to accommodate solar panels or other distributed generation systems. In addition, NEM customers are exempted from standby and departing load charges and interconnection-related costs.
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AB 327 directs the CPUC to address this subsidization through: rate reform, which includes the imposition of fixed charges on both NEM and non-NEM customers; the development of a new standard billing contract for customers who install distributed generation systems after July 2017 or the attainment of the NEM Cap; and a transition period over which customers who received NEM billing prior to new standard billing contract period will transition to the new contract. The new standard billing contract will be based on the actual costs and benefits of distributed power generation.
The effect of these types of competition on SCE generally is to reduce the number of customers purchasing power from SCE in the case of alternative electricity provider and to level the demand for power from SCE in the case of customers who self-generate. However customers who use alternative electricity providers, typically continue to utilize and pay for SCE's transmission and distribution services. 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 all of 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. 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 53,000 line miles of overhead lines, 37,000 line miles of underground lines and approximately 800 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) | ||||||||||
Hydroelectric Plants (36) | Various | Hydroelectric | SCE | 100 | % | 1,176 | 1,176 | |||||||||
Pebbly Beach Generating Station | Catalina Island | Diesel | SCE | 100 | % | 9 | 9 | |||||||||
Mountainview Units 3 and 4 | 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 | |||||||||
Solar PV Plants (25) | Various | Photovoltaic | SCE | 100 | % | 91 | 91 | |||||||||
Total | 6,310 | 3,162 | ||||||||||||||
In June 2013, SCE decided to permanently retire the remaining Units at San Onofre. For more information, see "Management Overview—Permanent Retirement of San Onofre " in the MD&A.
On December 30, 2013, SCE completed the sale of its interest in Four Corners to APS. See "Item 8. Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for more information.
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San Onofre and 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. In particular, the easement granted by the U.S. Navy for San Onofre gives the Navy the right to set site-restoration requirements, which could exceed the NRC requirements and require SCE to restore the site to its original condition.
The majority of SCE's hydroelectric plants and related reservoirs are located in whole or in part on U.S.-owned lands and are subject to FERC licenses. Slightly over half of these plants have FERC licenses that expire at various times between 2021 and 2046. SCE continuously monitors and maintains these licenses. 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 environmental impacts of past operations. The environmental regulations and other developments discussed below may impact SCE's fossil-fuel fired power plants and fossil-fuel power plants owned by others that SCE purchases power from, and accordingly, the discussion in this section focuses mainly on regulations applicable to California. For more information on environmental risks, see "Item 1A. Risk Factors—Risks Relating to Southern California Edison Company—Environmental Risks."
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 12. Commitments and Contingencies—Environmental Remediation."
Air Quality
The CAA, which regulates air pollutants from mobile and stationary sources, has a significant impact on the operation of fossil fuel 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
In 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 area were classified in
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various degrees of nonattainment, including the greater Los Angeles area (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). California is in the process of developing air quality management plans and updating its state implementation plan to outline how compliance with the 2008 NAAQS will be achieved. The implementation plans may call for more stringent restrictions on air emissions, which could further increase the difficulty of siting new natural gas fired generation in Southern California.
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. Federal standards intended to protect aquatic organisms by reducing capture in the screens attached to cooling water intake structures (impingement) at generating facilities and the water volume brought into the facilities (entrainment) are expected to be finalized in the first quarter of 2014. Due to the decision to permanently retire San Onofre Units 2 and 3, SCE will seek relief from the federal standards in order to avoid material capital expenditures at San Onofre.
California Restriction 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. In 2010, the California State Water Resources Control Board ("SWRCB") issued a final policy, which established significant restrictions on the use of ocean water by existing once-through cooled 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. SCE received a suspension of the requirement to perform the study pending the submittal of additional information to the SWRCB regarding the continued use of ocean water at San Onofre during decommissioning. In November 2013, SCE submitted this additional information to the SWRCB and is awaiting a decision on its request to be exempted from the requirements of the policy. If the SWRCB grants the exemption, further compliance-related capital expenditures at San Onofre will likely not be required.
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, as well as the cost of purchased power.
Federal Legislative/Regulatory Developments
In 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 September 2013, the US EPA announced proposed carbon dioxide emissions limits for new power plants. President Obama has directed the US EPA to develop greenhouse gas emissions performance standards for existing plants by June 2015. 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.
Since 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 2013 GHG emissions from utility-owned generation were approximately 6.7 million metric tons.
Regional Initiatives and State Legislation
Regional initiatives and state legislation 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.
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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 by 2020. In December 2011, the CARB regulation was officially published establishing a California cap-and-trade program. In the California cap-and-trade program, all covered GHG emitters, including SCE, are subject to a “cap” on their emissions designed to encourage entities to reduce emissions from their operations. Covered entities must remit a compliance instrument for each ton of carbon dioxide equivalent gas emitted and can do so buying state-issued emission allowances at auction or purchasing them in the secondary allowance market. GHG emitters can also meet up to 8% of their AB 32 cap-and-trade obligations by participating in verified offset programs, such as reforestation, that have recognized effects on reducing atmospheric GHGs. The first compliance period for the cap-and-trade program covers 2013-2014 GHG emissions. The most recent auction, held on November 19, 2013, cleared at $11.48/metric ton, $0.77 above the floor price of $10.71.
CARB regulations implementing a cap-and-trade program and the cap-and-trade program itself, continue to be the subject of litigation. In 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 provisions on offset programs. The Superior Court upheld the offset provisions but the case is on appeal. The California Chamber of Commerce and a private company filed suits alleging that the auction itself violated AB 32 and the California Constitution. The Superior Court consolidated the two suits and ruled in CARB's favor in November 2013. Plaintiffs have announced their intent to appeal.
The second law, SB 1368, required the CPUC and the CEC to adopt GHG emission performance standards that apply to California investor-owned and publicly owned utilities' 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, which is the performance of a combined-cycle gas turbine generator.
In 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. The CPUC set procurement quantity requirements applicable to SCE that incrementally increase to 33% over several periods between January 2011 and December 2020. The requirement remains at 33% of retail sales for each year thereafter. In October 2013, AB 327 was enacted to permit the CPUC to require the procurement of eligible renewable energy resources in excess of 33%; but the CPUC has not yet changed this requirement. SCE's delivery of eligible renewable resources to customers was 20% of its total energy portfolio for 2012 and is estimated to be approximately 22% of its total energy portfolio for 2013.
Litigation Developments
Litigation alleging that GHGs have caused damages for which plaintiffs seek recovery may affect SCE, whether or not it is named as a defendant. The legal developments in this area have focused on whether lawsuits seeking recovery for such alleged damages present questions capable of judicial resolution or political questions that should be resolved by the legislative or executive branches.
In 2011, the U.S. Supreme Court dismissed public nuisance claims against five power companies related to GHG emissions. In the dismissal, the Supreme Court ruled that the CAA, and the US EPA actions it authorizes, displace federal common law nuisance claims that might arise from the emission of GHGs. The Supreme Court also affirmed that at least some of the plaintiffs had standing to bring the case, but did not determine whether the CAA also preempts state law claims that might arise from the same circumstances.
Other suits alleging causes of action that include negligence, public and private nuisance, trespass, and violation of the public trust have been dismissed on threshold grounds, including justiciability and standing, by several courts. However, various groups of plaintiffs continue to explore and assert legal theories under which they seek to obtain recovery for past alleged harm, or have courts issue rulings that will control levels of current and future GHG emissions. Thus, the defendants in the dismissed actions, including SCE and other Edison International subsidiaries, together with other industrial companies associated with GHG emissions, may be required to defend such actions in both state and federal courts for the foreseeable future.
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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 Company" below for further discussion.
The Settlement Agreement between Edison International, EME and certain of EME’s unsecured creditors may not be approved by the Bankruptcy Court or otherwise not be consummated, which could result in claims by EME against Edison International that may result in losses to Edison International.
In December 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. EME submitted its Plan of Reorganization in December 2013, which included the sale of substantially all of EME’s assets to NRG Energy, Inc. Under the December Plan, EME would have retained certain assets and liabilities, including any claims against Edison International when it emerges from bankruptcy. EME had indicated that it was preparing a complaint containing claims similar to those alleged by the Official Committee of Unsecured Creditors in a motion filed in the Bankruptcy Court in August 2013 against Edison International, SCE, certain other subsidiaries of Edison International, and present and former directors of Edison International, SCE and EME (the "EME Claims"). In February 2014, Edison International, EME and certain of EME’s creditors holding a majority of its outstanding senior unsecured notes (“Consenting Noteholders”) entered into a Settlement Agreement pursuant to which EME amended its previously filed Plan of Reorganization to incorporate the terms of the Settlement Agreement. Under the Amended Plan of Reorganization, all existing EME claims against Edison International would be extinguished. The Amended Plan of Reorganization, including the Settlement Agreement, is subject to Bankruptcy Court approval, which is expected to occur in March 2014, but is not certain. If the Amended Plan is not approved, this could result in EME or its creditors filing the EME Claims against Edison International, SCE, certain other subsidiaries of Edison International, and present and former directors of Edison International, SCE and EME. If such a complaint were to be filed, Edison International would vigorously contest such allegations. An unfavorable outcome of such claims by EME could result in losses to and adversely impact Edison International. For further information on EME's bankruptcy filing, see "Management Overview—EME Chapter 11 Bankruptcy Filing."
Edison International's activities are concentrated in one industry and in one region.
Edison International does not have diversified sources of revenue or regulatory oversight. SCE comprises substantially all of Edison International’s business, and Edison International’s business is expected to remain concentrated in the electricity industry. Furthermore, Edison International's current business is concentrated almost entirely in southern California. As a result, Edison International's future performance may be affected by events and economic performance concentrated in southern California or by regional regulation or legislation.
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RISKS RELATING TO SOUTHERN CALIFORNIA EDISON COMPANY
Regulatory Risks
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 regulated the operations of San Onofre and regulates the decommissioning of San Onofre. 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, regulations 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.
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, leveling demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customer rates. 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—2015 General Rate Case," "Item 1. Business—SCE—Overview of Ratemaking Process—Retail Rates Structure" and "Liquidity and Capital Resources—SCE—Regulatory Proceedings—FERC Formula Rates" in the MD&A.
SCE may not fully recover its investment in San Onofre from regulatory proceedings, SCE's supplier, insurance, or otherwise; could be subject to NRC actions, including the imposition of penalties; or could be ordered by the CPUC to make refunds to customers of prior revenues.
In June 2013, SCE decided to permanently retire and decommission Units 2 and 3 at San Onofre. The CPUC is conducting an investigation proceeding that will consider the cost recovery for all San Onofre costs, including the cost of the steam generator replacement project, other sunk capital costs, substitute market power costs, nuclear fuel, operation and maintenance costs and seismic study costs. SCE cannot assure that the remaining cost of the steam generators, repair costs or the necessary substitute market power will be recoverable from its supplier, insurance, regulatory processes or otherwise or that the CPUC will not order refund of revenues previously collected. These amounts could be material and could materially affect SCE's financial condition and results of operations.
San Onofre remains subject to NRC oversight and SCE is aware of an NRC investigation into information SCE provided to the NRC regarding the steam generator failure; which could subject SCE to additional actions, including imposition of penalties. For more information, see "Management Overview—Permanent Retirement of San Onofre" 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
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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. For more information, see "Management Overview—ERRA Balancing Account" in the MD&A.
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.
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 obtain financing, as well as its ability to refinance debt and make scheduled payments of principal, interest and preferred stock dividends, 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.
Competitive and Market Risks
The electricity industry is undergoing extensive changes, including increased competition, technological advancements, and political and regulatory developments.
The entire electricity industry is undergoing extensive change, including technological advancements such as self-generation, energy storage and distributed generation that may change the nature of energy generation and delivery.
Demand for electricity from utilities has been leveling, while growth in self-generation has been accelerating. At the same time, a growing amount of investment is needed to replace aging infrastructure, and without corresponding growth in demand or corresponding savings elsewhere, these investments are reflected in rate increases that have the effect of further leveling demand and encouraging self-generation. Self-generation itself may exacerbate these trends by reducing the pool of customers, subject to certain regulatory limits, from whom fixed costs are recovered, while potentially increasing costs of system modifications that may be needed to integrate the systemic effects of self-generation. Rate designs that disproportionately impose costs on some classes of customers also accelerate these trends. For example, customers in California that self-generate their own power do not currently pay most transmission and distribution charges and non-bypassable charges, subject to limitations. Other customer classes have had artificial caps placed upon their proportionate sharing in overall costs. The net result is to increase utility rates further for those customers who do not self-generate or are not subject to such caps, which encourages more self-generation and further rate increases. For more information, see "Item 1. Business—SCE—Overview of Ratemaking Process—Retail Rates Structure."
In addition, the FERC has adopted changes that have opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and operation of transmission facilities. For more information, see "Item 1. Business—SCE—Competition."
Another emerging trend in the electricity industry is the increasing public discussion regarding the possibility of future changes in the electric utility business model as a result of the technological advancements and competitive pressures discussed above as well as political and regulatory developments. In October 2013, the CPUC held an open hearing to receive views from various sources on whether the current California utility business model should be revised. It is possible that material revisions to the traditional utility business model could materially affect SCE's business model and its financial condition and results of operations.
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 program. 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
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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 electrical current or equipment, including through downed power lines or if equipment malfunctions. Injuries and property damage caused by such events can subject SCE to liability that, despite the existence of insurance coverage, can be significant. 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 physical and 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 and other attacks and disruptions and that such 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 and materially damage the business reputation of Edison International and SCE. See "Item 1. Business—Regulation—NERC" for further discussion.
There are inherent risks associated with owning and decommissioning nuclear power generating facilities, including, among other things, potential harmful effects on the environment and human health and the danger of storage, handling and disposal of radioactive materials.
The cost of decommissioning Unit 2 and Unit 3 of San Onofre could prove more extensive than is currently estimated. These costs could exceed estimates or may not be recoverable through regulatory processes or otherwise. For more information, see "Risks Relating to Southern California Edison Company—Regulatory Risks" above.
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 $13.6 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 $13.6 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 $13.6 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
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the additional federal appropriations are insufficient. For more information on nuclear insurance risk, see "Item 8. Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Nuclear Insurance."
SCE's insurance coverage for wildfires arising from its ordinary operations may not be sufficient.
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 that has been obtained 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. For more information on wildfire insurance risk, see "Item 8. Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Wildfire Insurance."
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 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" for further discussion of environmental regulations under which SCE operates.
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 16. Discontinued Operations."
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EXECUTIVE OFFICERS OF EDISON INTERNATIONAL
Executive Officer | Age at December 31, 2013 | Company Position | ||
Theodore F. Craver, Jr. | 62 | Chairman of the Board, President and Chief Executive Officer | ||
Robert L. Adler | 66 | Executive Vice President and General Counsel | ||
W. James Scilacci | 58 | Executive Vice President, Chief Financial Officer and Treasurer | ||
Janet T. Clayton | 59 | Senior Vice President, Corporate Communications | ||
Bertrand A. Valdman | 51 | Senior Vice President, Strategic Planning | ||
Gaddi H. Vasquez | 58 | Senior Vice President, Government Affairs | ||
Mark C. Clarke | 57 | Vice President and Controller | ||
Ronald L. Litzinger | 54 | President, SCE | ||
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. Valdman and Vasquez, 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 | August 2008 to present | ||
Robert L. Adler | Executive Vice President and General Counsel, Edison International | August 2008 to present | ||
W. James Scilacci | Executive Vice President, Chief Financial Officer and Treasurer, Edison International | August 2008 to present | ||
Janet T. Clayton | Senior Vice President, Corporate Communications, Edison International President, Think Cure1 | 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 Energy2 | March 2011 to present May 2007 to March 2011 | ||
Gaddi H. Vasquez | Senior Vice President, Government Affairs, Edison International and SCE Senior Vice President, Public Affairs, SCE Executive Director, Annenberg Foundation Trust at Sunnylands3 US Ambassador and Permanent Representative to United Nations Agencies in Rome, Italy | May 2013 to present July 2009 to May 2013 February 2009 to July 2009 October 2006 to January 2009 | ||
Mark C. Clarke | Vice President and Controller, Edison International Vice President and Controller, SCE Vice President and Controller, EME4 | 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 EME4 | January 2011 to present April 2008 to December 2010 | ||
1 | Think Cure is a community-based nonprofit organization that raises funds to accelerate collaborative research to cure cancer and is not a parent, affiliate or subsidiary of Edison International. |
2 | Puget Sound Energy is a regulated energy utility in Washington State and is not a parent, affiliate or subsidiary of Edison International. |
3 | Annenberg Foundation Trust at Sunnylands is an independent nonprofit 501(c)(3) entity that provides a location where national and international leaders may meet in order to facilitate international agreement and supports education programs on the U.S. Constitution. It is not a parent, affiliate or subsidiary of Edison International. |
4 | 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. |
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EXECUTIVE OFFICERS OF SOUTHERN CALIFORNIA EDISON COMPANY
Executive Officer | Age at December 31, 2013 | Company Position | ||
Ronald L. Litzinger | 54 | President | ||
Janet T. Clayton | 59 | Senior Vice President, Corporate Communications | ||
Peter T. Dietrich | 49 | Senior Vice President | ||
Erwin G. Furukawa | 57 | Senior Vice President, Customer Service | ||
Stuart R. Hemphill | 50 | Senior Vice President, Power Supply | ||
David L. Mead | 61 | Senior Vice President, Transmission and Distribution | ||
Leslie E. Starck | 58 | Senior Vice President, Regulatory Affairs | ||
Linda G. Sullivan | 50 | Senior Vice President and Chief Financial Officer | ||
Russell C. Swartz | 62 | Senior Vice President and General Counsel | ||
Gaddi H. Vasquez | 58 | Senior Vice President, Government Affairs | ||
Mark C. Clarke | 57 | Vice President and Controller | ||
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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 Messrs. Dietrich, Vasquez 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 Officer | Company Position | Effective Dates | ||
Ronald L. Litzinger | President, SCE Chairman of the Board, President and Chief Executive Officer, EMG and EME1 | January 2011 to present April 2008 to December 2010 | ||
Janet T. Clayton | Senior Vice President, Corporate Communications, Edison International President, Think Cure2 | April 2011 to present Jan 2008 to April 2011 | ||
Peter T. Dietrich | Senior Vice President, SCE Chief Nuclear Officer, SCE Site Vice President, Entergy Nuclear Operations, Inc., James A. Fitzpatrick Nuclear Plant3 | November 2010 to present December 2010 to December 2013 April 2006 to November 2010 | ||
Erwin G. Furukawa | Senior Vice President, Customer Service, SCE Vice President, Customer Programs and Services, SCE | April 2011 to present April 2007 to April 2011 | ||
Stuart R. Hemphill | Senior Vice President, Power Supply, SCE Senior Vice President, Power Procurement, SCE Vice President, Renewable and Alternative Power, SCE | January 2011 to present July 2009 to December 2010 March 2008 to June 2009 | ||
David L. Mead | Senior Vice President, Transmission and Distribution, SCE Vice President, Engineering and Technical Services, SCE | April 2011 to present May 2008 to April 2011 | ||
Leslie E. Starck | Senior Vice President, Regulatory Policy & Affairs, SCE Vice President, Local Public Affairs, SCE | July 2011 to present November 2007 to June 2011 | ||
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 | ||
Gaddi H. Vasquez | Senior Vice President, Government Affairs, Edison International and SCE Senior Vice President, Public Affairs, SCE Executive Director, Annenberg Foundation Trust at Sunnylands4 US Ambassador and Permanent Representative to United Nations Agencies in Rome, Italy | May 2013 to present July 2009 to May 2013 February 2009 to July 2009 October 2006 to January 2009 | ||
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 | See footnote 4 under Executive Officers of Edison International above. |
2 | See footnote 1 under Executive Officers of Edison International above. |
3 | Entergy Nuclear Operations, Inc. is a subsidiary of Entergy Corporation, an integrated energy company and is not a parent, affiliate or subsidiary of SCE. |
4 | See footnote 3 under Executive Officers of Edison International above. |
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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. Debt and Credit Agreements." The number of common stockholders of record of Edison International was 41,000 on February 21, 2014. 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 2013.
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, 2013 to October 31, 2013 | 153,894 | $ | 48.22 | — | — | |||||||
November 1, 2013 to November 30, 2013 | 478,303 | 47.72 | — | — | ||||||||
December 1, 2013 to December 31, 2013 | 227,571 | 46.14 | — | — | ||||||||
Total | 859,768 | 47.39 | — | — | ||||||||
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, | |||||||||||||||||||||||
2008 | 2009 | 2010 | 2011 | 2012 | 2013 | ||||||||||||||||||
Edison International | $ | 100 | $ | 113 | $ | 129 | $ | 144 | $ | 161 | $ | 170 | |||||||||||
S & P 500 Index | 100 | 126 | 145 | 149 | 172 | 228 | |||||||||||||||||
Philadelphia Utility Index | 100 | 110 | 116 | 139 | 138 | 153 | |||||||||||||||||
Note: Assumes $100 invested on December 31, 2008 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: 2009 – 2013
(in millions, except per-share amounts) | 2013 | 2012 | 2011 | 2010 | 2009 | ||||||||||||||
Edison International | |||||||||||||||||||
Operating revenue | $ | 12,581 | $ | 11,862 | $ | 10,588 | $ | 9,996 | $ | 9,991 | |||||||||
Operating expenses | 10,866 | 9,577 | 8,527 | 8,177 | 8,982 | ||||||||||||||
Income from continuing operations | 979 | 1,594 | 1,100 | 1,144 | 751 | ||||||||||||||
Income (loss) from discontinued operations, net of tax1 | 36 | (1,686 | ) | (1,078 | ) | 164 | 197 | ||||||||||||
Net income (loss) | 1,015 | (92 | ) | 22 | 1,308 | 948 | |||||||||||||
Net income (loss) attributable to common shareholders | 915 | (183 | ) | (37 | ) | 1,256 | 849 | ||||||||||||
Weighted-average shares of common stock outstanding (in millions) | 326 | 326 | 326 | 326 | 326 | ||||||||||||||
Basic earnings (loss) per share: | |||||||||||||||||||
Continuing operations | $ | 2.70 | $ | 4.61 | $ | 3.20 | $ | 3.34 | $ | 1.98 | |||||||||
Discontinued operations | 0.11 | (5.17 | ) | (3.31 | ) | 0.50 | 0.61 | ||||||||||||
Total | $ | 2.81 | $ | (0.56 | ) | $ | (0.11 | ) | $ | 3.84 | $ | 2.59 | |||||||
Diluted earnings (loss) per share: | |||||||||||||||||||
Continuing operations | $ | 2.67 | $ | 4.55 | $ | 3.17 | $ | 3.32 | $ | 1.98 | |||||||||
Discontinued operations | 0.11 | (5.11 | ) | (3.28 | ) | 0.50 | 0.60 | ||||||||||||
Total | $ | 2.78 | $ | (0.56 | ) | $ | (0.11 | ) | $ | 3.82 | $ | 2.58 | |||||||
Dividends declared per share | 1.3675 | 1.3125 | 1.285 | 1.265 | 1.245 | ||||||||||||||
Total assets2 | $ | 46,646 | $ | 44,394 | $ | 48,039 | $ | 45,530 | $ | 41,444 | |||||||||
Long-term debt excluding current portion | 9,825 | 9,231 | 8,834 | 8,029 | 6,509 | ||||||||||||||
Capital lease obligations excluding current portion | 203 | 210 | 216 | 221 | 227 | ||||||||||||||
Preferred and preference stock of utility | 1,753 | 1,759 | 1,029 | 907 | 907 | ||||||||||||||
Common shareholders' equity | 9,938 | 9,432 | 10,055 | 10,583 | 9,841 | ||||||||||||||
Southern California Edison Company | |||||||||||||||||||
Operating revenue | $ | 12,562 | $ | 11,851 | $ | 10,577 | $ | 9,983 | $ | 9,965 | |||||||||
Operating expenses | 10,811 | 9,572 | 8,454 | 8,119 | 8,047 | ||||||||||||||
Net income | 1,000 | 1,660 | 1,144 | 1,092 | 1,371 | ||||||||||||||
Net income available for common stock | 900 | 1,569 | 1,085 | 1,040 | 1,226 | ||||||||||||||
Total assets | $ | 46,050 | $ | 44,034 | $ | 40,315 | $ | 35,906 | $ | 32,474 | |||||||||
Long-term debt excluding current portion | 9,422 | 8,828 | 8,431 | 7,627 | 6,490 | ||||||||||||||
Capital lease obligations excluding current portion | 203 | 210 | 216 | 221 | 227 | ||||||||||||||
Preferred and preference stock | 1,795 | 1,795 | 1,045 | 920 | 920 | ||||||||||||||
Common shareholder's equity | 10,343 | 9,948 | 8,913 | 8,287 | 7,446 | ||||||||||||||
Capital structure: | |||||||||||||||||||
Common shareholder's equity | 48.0 | % | 48.4 | % | 48.5 | % | 49.2 | % | 50.1 | % | |||||||||
Preferred and preference stock | 8.3 | % | 8.7 | % | 5.7 | % | 5.5 | % | 6.2 | % | |||||||||
Long-term debt | 43.7 | % | 42.9 | % | 45.8 | % | 45.3 | % | 43.7 | % | |||||||||
1 Effective December 17, 2012, Edison International no longer consolidated the earnings and losses of EME or its subsidiaries and has reflected its ownership interest in EME utilizing the cost method of accounting. Edison International considered EME to be an abandoned asset under GAAP, and, as a result, the operations of EME prior to December 17, 2012 and for all prior years are reflected as
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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 16. Discontinued Operations" for further information.
2 | Total assets includes assets from continuing and discontinued operations. |
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. References to Edison International refer to the consolidated group of Edison International and its subsidiaries.
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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 and delivering electricity. Edison International is also the parent company of subsidiaries that are engaged in competitive businesses related to the generation 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. Unless otherwise described, all of the information contained in this annual report relates to both filers.
(in millions) | 2013 | 2012 | 2013 vs 2012 Change | 2011 | |||||||||||
Net income (loss) attributable to Edison International | |||||||||||||||
Continuing operations | |||||||||||||||
SCE | $ | 900 | $ | 1,569 | $ | (669 | ) | $ | 1,085 | ||||||
Edison International Parent and Other | (21 | ) | (66 | ) | 45 | (44 | ) | ||||||||
Discontinued operations | 36 | (1,686 | ) | 1,722 | (1,078 | ) | |||||||||
Edison International | 915 | (183 | ) | 1,098 | (37 | ) | |||||||||
Less: Non-core items | |||||||||||||||
SCE: | |||||||||||||||
Asset impairment | (365 | ) | — | (365 | ) | — | |||||||||
2012 General Rate Case – repair deductions (2009 – 2011) | — | 231 | (231 | ) | — | ||||||||||
Edison International Parent and Other: | |||||||||||||||
Consolidated state deferred tax impacts related to EME | — | (37 | ) | 37 | (19 | ) | |||||||||
Gain on sale of Beaver Valley lease interest | 7 | 31 | (24 | ) | — | ||||||||||
Write-down of net investment in aircraft leases | — | — | — | (16 | ) | ||||||||||
Discontinued operations | 36 | (1,686 | ) | 1,722 | (1,078 | ) | |||||||||
Total non-core items | (322 | ) | (1,461 | ) | 1,139 | (1,113 | ) | ||||||||
Core earnings (losses) | |||||||||||||||
SCE | 1,265 | 1,338 | (73 | ) | 1,085 | ||||||||||
Edison International Parent and Other | (28 | ) | (60 | ) | 32 | (9 | ) | ||||||||
Edison International | $ | 1,237 | $ | 1,278 | $ | (41 | ) | $ | 1,076 | ||||||
Edison International's earnings are prepared in accordance with GAAP 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 sale of certain assets 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 Bankruptcy Code in the Bankruptcy Court. Edison International considers EME to be an abandoned asset under GAAP, and, as a result, the operations of EME prior to December 17, 2012 are reflected as discontinued operations.
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SCE's 2013 core earnings decreased $73 million for the year primarily due to lower income tax benefits, ceasing to record a return on rate base for San Onofre after the decision to permanently retire the plant, partially offset by lower incremental inspection and repair costs at San Onofre and lower operating costs. The earnings increase from the rate base growth was offset by the lower authorized 2013 return on common equity.
Edison International Parent and Other 2013 core losses decreased $32 million primarily due to higher core earnings from Edison Capital, lower costs and taxes.
Consolidated non-core items for 2013 and 2012 for Edison International included:
• | An impairment charge of $575 million ($365 million after tax) in 2013 related to the permanent retirement of San Onofre Units 2 and 3. |
• | An income tax benefit of $36 million for 2013 from a revised estimate of the tax impact of the expected future tax deconsolidation and separation of EME from Edison International. Edison International continues to consolidate EME for federal and certain combined state tax returns. Changes in the amount of tax attributes in 2013 affected income taxes of discontinued operations. Such benefits may or may not continue in future periods. For further information, see "Item 8. Notes to Consolidated Financial Statements—Note 7. Income Taxes." |
• | An after-tax earnings charge of $1.3 billion in 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 16. 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 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. The final determination of state income taxes was not completed until the first quarter of 2013 which resulted in $7 million of lower state income tax expense than previously estimated. |
See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations, including a comparison of 2012 results to 2011.
Permanent Retirement of San Onofre
Tube Leak and Response
Replacement steam generators were installed at San Onofre in 2010 and 2011. 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. The Unit was safely taken off-line and subsequent inspections revealed excessive tube to tube wear. 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 shut down since early 2012 and have undergone extensive inspections, testing and analysis following discovery of the leak. In October 2012, SCE submitted a restart plan to the Nuclear Regulatory Commission ("NRC"), seeking to restart Unit 2 at a reduced power level (70%) for an initial period of approximately five months, based on work done by engineering groups from three independent firms with expertise in steam generator design and manufacturing. SCE did not develop a restart plan for Unit 3.
Permanent Retirement
On June 6, 2013 SCE decided to permanently retire Units 2 and 3. SCE concluded that despite the NRC's extensive review of SCE's restart plan for Unit 2 starting in October 2012, there still remained considerable uncertainty about when the review process would be concluded. Given the considerable uncertainty of when or whether SCE would be permitted to restart Unit 2, SCE concluded that it was in the best interest of its customers, shareholders and other stakeholders to permanently retire the Units and focus on planning for the replacement resources which will eventually be required for grid reliability. SCE also concluded that its decision to retire the Units would facilitate more orderly planning for California's energy future without the uncertainty of whether, when or how long San Onofre would continue to operate.
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CPUC Review
In October 2012 the CPUC issued an Order Instituting Investigation ("OII") that consolidated all San Onofre issues in related regulatory proceedings to consider 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, operation and maintenance costs, and seismic study costs. The OII requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent collected in rate levels authorized in the 2012 GRC or other proceedings, be 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 OII, of costs and rate base related to San Onofre from SCE's rates. Various other parties have filed testimony in the OII asking for disallowance of some or all of the San Onofre-related costs, including costs in excess of the amount impaired by SCE, as described below. The first phase of the OII was focused on 2012 costs, including 2012 capital and operation and maintenance costs and the appropriate calculation to measure 2012 substitute market power costs. A proposed decision in the first phase of the OII was issued in November 2013. The proposed decision would allow $45 million in planned Unit 2 refueling outage costs but would disallow approximately $74 million in operation and maintenance costs authorized in rates plus 20% of the 2012 revenue requirement related to capital expenditures incurred during the extended outage for both Units. The disallowance would be subject to possible further review in the third phase of the OII. The proposed decision would permit recovery of routine operation and maintenance expense through May 2012 but defers a decision on recovery of incremental expenses incurred by SCE to the third phase of the OII. A final decision in the first phase is expected in the first quarter of 2014. The second phase was focused on whether to adjust customer rates to remove the plant from rate base and hearings were held in October 2013. A proposed decision in the second phase is expected in the first quarter of 2014. The third and fourth phases of the OII will focus on the steam generator replacement project itself, including the reasonableness of the project's costs, and the San Onofre 2013 revenue requirement, respectively, and have not yet been scheduled.
A summary of financial items related to San Onofre and implicated in the OII are as follows:
• | Approximately $1.25 billion of SCE's authorized revenue requirement collected since January 1, 2012 (subject to refund) is associated with operating and maintenance expenses, depreciation, taxes and return on SCE's investment in Unit 2, Unit 3 and common plant. In 2013, SCE recorded approximately $39 million in severance costs associated with its decision to retire both Units. Until funding of post June 6, 2013 activities related to the permanent closure of the plant is transitioned from base rates to SCE's nuclear decommissioning trusts established for that purpose, SCE will continue to record these costs through the San Onofre OII memorandum account, subject to reasonableness review. |
• | At May 31, 2013, SCE's net investment associated with San Onofre is set forth in the following table: |
(in millions) | Unit 2 | Unit 3 | Common Plant | Total | |||||||||||
Net investment1 | $ | 606 | $ | 430 | $ | 259 | $ | 1,295 | |||||||
Materials and supplies | — | — | 100 | 100 | |||||||||||
Construction work in progress | 25 | 99 | 106 | 230 | |||||||||||
Nuclear fuel | 153 | 216 | 102 | 471 | |||||||||||
Total investment | $ | 784 | $ | 745 | $ | 567 | $ | 2,096 | |||||||
1 | Includes net book value of the replacement steam generators of $542 million. |
• | 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 $602 million on the steam generator replacement project, not including inspection, testing and repair costs subsequent to the replacement steam generator leak in Unit 3. |
• | As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre were purchased in the market by SCE. These market power costs will be reviewed as part of the CPUC's OII proceeding. Estimated market power costs calculated in accordance with the OII methodology were approximately $680 million as of June 6, 2013, excluding avoided nuclear fuel costs which are no longer included as a reduction due to SCE's decision to permanently retire Units 2 and 3. Such amount includes costs of approximately $65 million associated with planned outage periods. SCE believes that such costs should be excluded as they would have been incurred even had the replacement steam generators performed as expected. Estimated market power costs calculated in accordance with the OII methodology from June 7, 2013 through December 31, 2013 were approximately $333 million. |
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Such amount includes costs of approximately $30 million associated with planned outage periods. SCE views the market power costs incurred from June 7, 2013 to be purchases made in the ordinary course to meet its customers’ needs as authorized by the CPUC-approved procurement plan rather than power or capacity that was acquired for cost recovery purposes as a replacement for San Onofre. The CPUC will ultimately determine a final methodology for estimating market power costs as it continues its review of the issues in the OII.
• | Through December 31, 2013, SCE's share of incremental inspection and repair costs totaled $115 million for both Units (not including payments made by MHI as described below). SCE recorded its share of payments made to date by MHI ($36 million) as a reduction of incremental inspection and repair costs in 2012. |
SCE continues to believe that the actions taken and costs incurred in connection with the San Onofre replacement steam generators, outages and permanent retirement have been prudent. Nevertheless, SCE cannot provide assurance 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. 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.
Accounting for Early Retirement of San Onofre Units 2 and 3
As a result of the decision to early retire San Onofre Units 2 and 3, GAAP requires reclassification of the amounts recorded in property, plant and equipment and related tangible operating assets to a regulatory asset to the extent that management concludes it is probable of recovery through future rates. Regulatory assets may also be recorded to the extent management concludes it is probable that direct and indirect costs incurred to retire Units 2 and 3 as of each reporting date are recoverable through future rates. These costs may include, but are not limited to, severance benefits to reduce the workforce at San Onofre to the staffing required to safely store and secure the plant prior to conducting decommissioning activities, losses on termination of purchase contracts, including nuclear fuel, and losses on disposition of excess inventory. GAAP also requires recognition of a liability to the extent management concludes it is probable SCE will be required to refund amounts from authorized revenues previously collected from customers.
In assessing whether to record regulatory assets as a result of the decision to retire San Onofre Units 2 and 3 early and whether to record liabilities for refunds to customers, SCE considered the interrelationship of recovery of costs and refunds to customers for accounting purposes, as such matters are being considered by the CPUC on a consolidated basis in the San Onofre OII. SCE also considered that it will continue to use certain portions of the plant (such as fuel storage, security facilities and buildings) as part of ongoing activities at the site. SCE additionally reviewed relevant regulatory precedents and statutory provisions regarding the regulatory recovery of early retired assets previously placed in service and related materials, supplies and fuel. Such precedents have generally permitted cost recovery of the remaining net investment in early retired assets, absent a finding of imprudency. Such precedents vary on whether a full, partial or no rate of return is allowed on the investment in such assets, but generally provide accelerated recovery when less than a full return is authorized. Furthermore, once the Units are removed from rate base, under normal principles of cost of service ratemaking and relevant statutory provisions, SCE should, absent imprudence, recover the costs it incurs to purchase power that might otherwise have been produced by San Onofre. SCE continues to believe that the actions it has taken and the costs it has incurred in connection with the San Onofre replacement steam generators and outages have been prudent.
As a result of such considerations, SCE considered a number of potential outcomes for the matters being considered by the CPUC in the San Onofre OII, none of which are assured, but a number of which in SCE's opinion appeared to be more likely than a number of other outcomes. SCE considered the likelihood of outcomes to determine the amount deemed probable of recovery. These outcomes included a number of variables, including recovery of and return on the components of SCE's net investment, and the potential for refunds to customers for either substitute power or operating costs occurring over different time periods. SCE also included in its consideration of possible outcomes, the requirement under GAAP to discount future cash flows from recovery of assets without a return at its incremental borrowing rate.
As a result of the foregoing assessment, SCE:
• | Reclassified $1,521 million of its total investment in San Onofre at May 31, 2013 as described above to a regulatory asset (“San Onofre Regulatory Asset”). Included in the San Onofre Regulatory Asset is approximately $404 million of property, plant and equipment, including construction work in progress, which is expected to support ongoing activities at the site. In addition, to the extent the San Onofre Regulatory Asset includes excess nuclear fuel and material and supplies, SCE will, if possible, sell such excess amounts to third parties and reduce the amount of the regulatory asset by such proceeds. |
• | Recorded an impairment charge of $575 million ($365 million after tax) in the second quarter of 2013. |
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As part of the decision to permanently retire the Units at San Onofre, SCE announced a workforce reduction of approximately 960 employees and had severance costs in 2013 of $39 million (SCE's share). The estimate for these costs was previously included in SCE's estimate to decommission the units. After acceptance of the decommissioning plan by the NRC, SCE expects a further workforce reduction of approximately 175 employees. SCE also recorded severance costs of $14 million related to the indirect employee impacts from the decision to early retire the Units.
As of December 31, 2013, SCE recorded a net regulatory asset of $1.3 billion comprised of: $1.56 billion of property, plant and equipment; $33 million estimated losses on disposition of nuclear fuel inventory; less $266 million for estimated refunds of authorized revenue recorded in excess of SCE’s costs of service, including a return on capital through June 6, 2013. SCE's judgment that the San Onofre Regulatory Asset recorded at December 31, 2013 is probable, though not certain, of recovery is based on SCE's knowledge of the facts and judgment in applying relevant regulatory principles to the issues under review in the OII proceeding and in accordance with GAAP. Such judgment is subject to considerable uncertainty, and regulatory principles and precedents are not necessarily binding and are capable of interpretation. The CPUC may or may not agree with SCE, after review of all of the facts and circumstances, and SCE may advocate positions that it believes are supported by relevant precedent and regulatory principles that are more favorable to SCE than the charges it has recorded in accordance with GAAP. The CPUC could also conclude that SCE acted imprudently regarding the San Onofre replacement steam generator project, including its response to the outage that commenced at the end of January 2012. Thus, there can be no assurance that the OII proceeding will provide for recoveries as estimated by SCE, including the recovery of costs recorded as a regulatory asset, or that the CPUC does not order refunds to customers from amounts that were previously authorized as subject to refund. Accordingly, the amount recorded for the San Onofre Regulatory Asset at December 31, 2013, is subject to change based upon future developments and the application of SCE's judgment to those events.
Third-Party Recovery
The replacement 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 with dispatch and to pay specified damages for certain repairs. MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power;" however, limitations in the contract are subject to applicable exceptions both in the contract and under law. SCE has advised MHI that it believes one or more of such exceptions apply and MHI's liability is not limited to $138 million, and MHI has advised SCE that it disagrees. In October 2013, after a prescribed 90-day waiting period from the service of an earlier notice of dispute, SCE sent MHI a formal request for binding arbitration under the auspices of the International Chamber of Commerce in accordance with the purchase contract seeking damages for all losses. In the request for arbitration, SCE alleges contract and tort claims and seeks at least $4 billion in damages on behalf of itself and in its capacity as Operating Agent for San Onofre. SCE also alleges that MHI totally and fundamentally failed to deliver what it promised, and that the contractual limitations of liability are subject to applicable exceptions in the contract and under law. MHI responded to SCE’s formal request in December 2013, asserting that the replacement steam generator project was a joint design venture, that the wear could not have been predicted and that SCE thwarted MHI’s repair efforts. MHI also asserted several counterclaims associated with work or services it claims it should be compensated for and which it values at approximately $41 million; SCE has denied any liability for the asserted counterclaims. Each of the other co-owners filed lawsuits against MHI, alleging claims arising from MHI's supplying the faulty steam generators. MHI has requested that these lawsuits be stayed pending the arbitration with SCE but the court has not yet ruled on this request.
SCE, on behalf of itself and the other San Onofre co-owners, has submitted seven invoices to MHI totaling $149 million for steam generator repair costs incurred through April 30, 2013. 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. In September 2013, SCE reiterated its request to MHI for payment of outstanding invoices. SCE has recorded its share of the invoice paid as a reduction of repair and inspection costs.
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San Onofre carries accidental property damage and carried accidental outage insurance issued by Nuclear Electric Insurance Limited ("NEIL") and has placed NEIL on notice of claims under both policies. The NEIL policies have a number of exclusions and limitations that NEIL may assert reduce or eliminate coverage, and SCE may choose to challenge NEIL’s application of any such exclusions and limitations. The estimated total claims under the accidental outage insurance through August 31, 2013 are approximately $397 million (SCE’s share of which is approximately $311 million). Pursuant to these proofs of loss, SCE is seeking the weekly indemnity amounts provided under the accidental outage policy for each Unit. Accidental outage policy benefits are reduced by 90% for the periods following announcement of the permanent retirement of the Units. The accidental outage insurance at San Onofre has been canceled as a result of the permanent retirement. SCE has not submitted a proof of loss under the accidental property damage insurance. No amounts have been recognized in SCE's financial statements, pending NEIL's response. SCE's current expectation is that NEIL will make a coverage determination by the end of the second quarter of 2014.
Continuing NRC Proceedings
As part of the NRC's review of the San Onofre outage and proceedings related to the possible restart of Unit 2, the NRC appointed an Augmented Inspection Team to review SCE's performance. In September 2013, the NRC issued an Inspection Report in connection with The Augmented Inspection Team’s review and SCE’s response to an earlier NRC Confirmatory Action Letter. The NRC’s report contained a preliminary “white” finding (low to moderate safety significance) and an apparent violation regarding the steam generators in Unit 3 and a preliminary “green” finding (very low safety significance) for Unit 2’s steam generators for failing to ensure that MHI’s modeling and analysis were adequate. Simultaneously, the NRC issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of San Onofre’s steam generators. In October 2013, SCE submitted comments to the NRC on the characterizations contained in the Inspection Report but chose not to contest the findings or violation, and the NRC finalized its finding in December 2013. In addition, the NRC's Office of Investigations has been conducting an investigation into the accuracy and completeness of information SCE provided to the Augmented Inspection Team. SCE has also been made aware of an investigation related to San Onofre by the NRC's Office of Inspector General, which generally reviews internal NRC affairs. Certain anti-nuclear groups and individual members of Congress have alleged that SCE knew of deficiencies in the steam generators when they were installed or otherwise did not correctly follow NRC requirements in connection with the design and installation of the replacement steam generators, something which SCE has vigorously denied, and have called for investigations, including by the Department of Justice. SCE cannot predict when or whether ongoing inquiries or investigations by the NRC will be completed or whether inquiries by other government agencies will be initiated. Should the NRC find a deficiency in SCE's 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 above.
Decommissioning
The decommissioning of a nuclear plant requires the management of three related activities: radiological decommissioning, non-radiological decommissioning and the management of spent nuclear fuel. The decommissioning process may take many years, as is expected at San Onofre. SCE is currently discussing a decommissioning agreement to govern the process with the decommissioning participants, as contemplated by the San Onofre operating agreement. SCE leases and holds an easement from the U.S. Navy for the land on which San Onofre is located. The easement granted by the U.S. Navy for San Onofre gives the Navy the right to set site-restoration requirements, which could exceed the NRC requirements and require SCE to restore the site to its original condition.
The process for the radiological decommissioning of a nuclear power plant is governed by NRC regulations. SCE expects that the non-radiological decommissioning of the site may eventually involve other governmental agencies and approvals. Under NRC regulations, the process for radiological decommissioning consists of three phases: initial activities, major decommissioning and storage activities, and license termination. Initial activities include providing a notice of permanent cessation of operations and of permanent removal of fuel from the reactor vessel shortly after the retirement of the plant has been announced. Within two years after the announcement of retirement, the licensee must also submit a post-shutdown decommissioning activities report, an irradiated fuel management plan and a site-specific decommissioning cost estimate.
On June 12, 2013, SCE began the initial activity phase of radiological decommissioning by filing with the NRC a certification of permanent cessation of power operations at San Onofre. Notifications of permanent removal of fuel from the reactor vessels were provided on June 28, 2013 and July 22, 2013 for Units 3 and 2, respectively. SCE currently estimates that it will provide the other initial activity phase plans and cost estimates by the end of 2014. Major radiological decommissioning activities may only start 90 days after the NRC receipt of the post-shutdown decommissioning activities report. The license termination phase will begin with the submission of a license termination plan, which is due not less than
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two years prior to the planned license termination. The NRC regulations regulate the use of decommissioning trust funds for radiological decommissioning by requiring that various decommissioning process milestones be met prior to the use of additional funds. SCE may also need NRC staff approval to use decommissioning funds for spent fuel management and non-radiological decommissioning.
SCE has nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $3.18 billion as of December 31, 2013, which is comprised of annual contributions made through rates and earnings on the trust funds’ balances. Other than the use of funds for the planning of radiological decommissioning (up to a maximum of 3% of a generic formula amount under NRC regulations, or $31 million), the CPUC must issue an order granting prior approval for withdrawal of decommissioning trust funds to be used for radiological decommissioning, non-radiological decommissioning and spent fuel management. The CPUC's authority to authorize the use of trust funds for decommissioning activities is provided by the Nuclear Facility Decommissioning Act of 1985 of the California Public Utilities Code. SCE has filed a request with the CPUC that would authorize early release of trust funds for costs up to a specified cost cap of $214 million.
Once access is authorized by the CPUC, SCE will fund decommissioning of San Onofre through funds in its nuclear decommissioning trust. In order to determine future funding levels, SCE makes regular forecasts of decommissioning cost estimates based on expert advice. Such forecasts are subject to a number of assumptions and uncertainties, such as future dismantling, transportation, labor and similar costs, the length of time that will be needed to decommission, prevailing rates of inflation, burial escalation rates and other assumptions.
In July 2013, SCE submitted supplemental testimony in the Nuclear Decommissioning Cost Triennial Proceeding ("NDCTP") that provided a decommissioning cost estimate for an early shutdown scenario of both Units 2 and 3. The supplemental testimony provided for a higher level of contributions than is currently collected in rates. However, SCE’s supplemental testimony requested the CPUC to defer an increase in the contribution level until SCE has completed an updated site-specific decommissioning cost estimate for San Onofre currently expected in by the end of 2014.
The total ARO liability related to San Onofre was revised based on the July 2013 update to the NDCTP discussed above. See "Item 8. Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Asset Retirement Obligation" for further information.
ERRA Balancing Account
Rates related to fuel and purchased power are set annually based on a forecast of the costs SCE expects to incur in the following year. Actual fuel and power costs that are greater/less than the forecast are tracked in the ERRA balancing account and collected/refunded to customers in subsequent periods. In August 2012, SCE filed its annual 2013 ERRA forecast, requesting a rate increase of approximately $500 million due to a variety of factors. The 2013 ERRA forecast proceeding was deferred by the Assigned Commissioner while issues related to the San Onofre outage are under consideration in the San Onofre OII. See "—Permanent Retirement of San Onofre" above.
As a result, until November 2013, SCE continued to recover in rates amounts authorized in the 2012 ERRA proceeding which are significantly below the costs incurred. As of December 31, 2013, the fuel and power procurement-related costs were under-collected by approximately $1 billion, which SCE has recorded as a regulatory asset on the basis that such amounts are probable of recovery.
The CPUC has also 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 generation revenue, or approximately $280 million. In July 2013, SCE triggered the mechanism and filed an application with the CPUC. Prior to the application, SCE had also filed a motion with the CPUC proposing an interim ERRA rate increase. In January 2014, the CPUC issued a proposed decision rejecting SCE's application, finding that if San Onofre had been operating normally in 2013, the undercollection would not have grown sufficiently to trigger the mechanism. SCE disagrees with the reasoning in the PD, but the procedural posture of SCE’s 2014 ERRA forecast proceeding (discussed below) renders the issue largely moot.
In October 2013, the CPUC issued a decision on SCE's 2013 ERRA forecast that approved a portion of SCE's 2013 ERRA forecast and allowed SCE to increase rates by approximately $160 million. Under the decision, SCE was required to defer collection of its forecasted net San Onofre replacement power costs (the difference between normal San Onofre costs and the San Onofre costs proposed in the 2013 ERRA forecast filing) until the resolution of such costs in the San Onofre OII proceeding. In addition, the decision directed SCE to exclude the net San Onofre costs from the ERRA trigger calculation. The decision made no determination regarding the accuracy of the methodology used to determine the net San Onofre costs or the reasonableness of the costs. Those determinations will be made in the San Onofre OII. SCE may finance deferred power procurement-related costs with commercial paper or other borrowing, subject to availability in the capital markets.
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In November 2013, SCE updated its annual 2014 ERRA forecast proceeding testimony, requesting a revenue requirement increase of approximately $1.97 billion, an increase of approximately 16% over the current 2013 total revenue requirement, beginning in January 2014. In response to an administrative law judge request, SCE subsequently estimated net San Onofre replacement costs to be approximately $467 million. These costs may be removed from the final decision in the 2014 ERRA forecast proceeding and deferred until the resolution of such costs in the San Onofre OII proceeding. SCE cannot predict the outcome of the proceeding. SCE expects a decision in the first half of 2014.
2015 General Rate Case
On November 12, 2013, SCE filed its 2015 GRC application which requested a 2015 base rate revenue requirement of $6.462 billion. Subsequently, SCE reduced its requested 2015 base rate revenue requirement to $6.383 billion to remove Four Corners costs from the proposed revenue requirement due to the completion of the sale of SCE's interest. After considering the effects of sales growth, SCE's request would be a $127 million increase over currently authorized base rate revenue. If the CPUC approves the requested rate increase and allocates the increase to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 2% and 0.6%, respectively. The application also proposed post-test year increases in 2016 and 2017, net of sales growth, of $313 million and $319 million, respectively. The requested revenue requirement increase is driven by the need to: maintain system reliability, including investment in infrastructure maintenance and replacement, accommodate customer load growth, and ongoing operation and maintenance expenses. The application includes forecasted shutdown operating and capital expenses for San Onofre. To the extent that some or all of these expenses are funded by its nuclear decommissioning trust, SCE will not recover such costs through base rates. The application also includes a request for 2015 – 2017 capital expenditures as discussed in "—Liquidity" below. SCE's proposed schedule in the proceeding anticipates a final decision on SCE's 2015 GRC by the end of 2014. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or when a final decision will be adopted.
Capital Program
Total capital expenditures (including accruals) were $3.5 billion in 2013 and $3.9 billion in 2012. The level of capital expenditures in 2013 was lower than the prior year, due to the full implementation in 2012 of the Edison SmartConnect® program, lower investments at San Onofre, lower costs on two transmission projects placed in service in 2013 and delays experienced with other transmission projects, offset by higher investment in distribution infrastructure replacement and improvement programs. SCE's capital program for 2014 – 2017 is focused primarily in the following areas:
• | Maintaining reliability and expanding the capability of SCE's transmission and distribution system through infrastructure replacements and improvements. |
• | Upgrading and constructing new transmission lines and substations for system reliability and increased access to renewable energy, including the Tehachapi, Coolwater-Lugo and West of Devers transmission and substation projects. |
• | Maintaining performance of SCE's natural gas, and hydro-electric generating plants. |
SCE forecasts capital expenditures in the range of $15.1 billion to $17.2 billion for 2014 – 2017. 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 "—Liquidity and Capital Resources—SCE—Capital Investment Plan."
EME Chapter 11 Bankruptcy Filing
In December 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. EME submitted its Plan of Reorganization in December 2013 ("December Plan of Reorganization"), which included the sale of substantially all of EME’s assets to NRG Energy, Inc. and the transfer of ownership of EME to unsecured creditors, to the Bankruptcy Court for confirmation. Under the December Plan of Reorganization, the remaining assets of EME, consisting of the NRG sale proceeds, certain EME tax benefits comprised of net operating loss and tax credit carryforwards and causes of action against Edison International or others that were not released under the December Plan of Reorganization, would have re-vested in the reorganized EME ("Reorganized EME").
In February 2014, Edison International, EME and the Consenting Noteholders entered into a Settlement Agreement pursuant to which EME amended its Plan of Reorganization to incorporate the terms of the Settlement Agreement, including extinguishing all existing claims between EME and Edison International. The Amended Plan of Reorganization, including the Settlement Agreement, is subject to the approval of the Bankruptcy Court, which is scheduled for consideration in March 2014.
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Under the Amended Plan of Reorganization, EME will emerge from bankruptcy free of liabilities but will remain an indirect wholly-owned subsidiary of Edison International, which will continue to be consolidated with Edison International for income tax purposes. On the effective date of the Amended Plan of Reorganization (“Effective Date”), all of the assets and liabilities of EME that are not otherwise discharged in the bankruptcy or transferred to NRG Energy will be transferred to a newly formed trust or entity under the control of EME’s existing creditors (the “Reorganization Trust”), except for (a) EME’s income tax attributes, which will be retained by the Edison International consolidated income tax group; (b) certain tax and pension related liabilities in the approximate amount of $350 million, which are being assumed by Edison International and for substantially all of which Edison International had joint and several responsibility; and (c) EME’s indirect interest in Capistrano Wind Partners and a small hydroelectric project, which is currently a lease investment of Edison Capital that is expected to be transferred to EME prior to the closing of the settlement.
Edison International has agreed to pay to the Reorganization Trust an amount equal to 50% of EME’s federal and California income tax benefits, which were not previously paid to EME under a tax allocation agreement between Edison International and EME that expired on December 31, 2013 (“EME Tax Attributes”) and which are estimated to be approximately $1.191 billion, subject to an estimate updating procedure set forth in the Settlement Agreement that is expected to take up to approximately six months from the Effective Date. On the Effective Date, Edison International will pay the Reorganization Trust $225 million in cash and the balance will be paid in two installment payments to be made on September 30, 2015 and 2016, respectively. The amount of the two installment payments with interest of 5% per annum from the Effective Date will be fixed once the estimate of the EME Tax Attributes is completed but are currently estimated to be approximately $199 million and $210 million, respectively, including applicable interest. Assuming continuation of existing law and tax rates, Edison International also anticipates realization of the tax benefits over a period similar to the period for which it pays for them, and pending the realization of the tax benefits, Edison International will finance the settlement from existing credit lines.
EME and the Reorganization Trust will release Edison International and its subsidiaries, officers, directors, and representatives from all claims, except for those deriving from commercial arrangements between SCE and certain EME subsidiaries and for obligations arising under the Settlement Agreement. Edison International and its subsidiaries that directly and indirectly own EME will provide a similar release to EME and the Reorganization Trust. Under the Amended Plan of Reorganization, Edison International and its subsidiaries will also be beneficiaries of orders of the Bankruptcy Court releasing them from claims of third parties in EME’s bankruptcy proceeding. The Reorganization Trust is obligated to set aside $50 million in escrow to secure its obligations to Edison International under the Settlement Agreement, including its obligation to protect against liabilities, if any, not discharged in the bankruptcy for which the Reorganization Trust remains responsible. Such escrowed amount will decline over time to zero on September 30, 2016.
Approval of the Amended Plan of Reorganization, including the Settlement Agreement, is subject to the determination of the Bankruptcy Court. The final estimate of EME Tax Attributes, which will fix Edison International’s installment obligations to the Reorganization Trust, may differ materially from the current estimate. Subject to effectuation of the settlement and the final determination of the EME Tax Attributes under the Settlement Agreement, Edison International anticipates that consolidated tax benefits it will retain will exceed the sum of liabilities it will assume and payments to the Reorganization Trust by approximately $200 million, and that the transactions contemplated by the Settlement Agreement, if effectuated, will result in its recording approximately $130 million in non-core income in the first quarter of 2014, which is net of amounts recorded prior to the first quarter. Edison International has recorded deferred income tax benefits of EME, less a valuation allowance for amounts that would no longer be available upon tax deconsolidation of EME of approximately $220 million and a $150 million provision for loss related to claims filed against EME in the bankruptcy. The net impact of these items has been approximately $70 million through December 31, 2013 and recorded as part of discontinued operations.
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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 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:
2013 | 2012 | 2011 | |||||||||||||||||||||||||
(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 | $ | 6,602 | $ | 5,960 | $ | 12,562 | $ | 6,682 | $ | 5,169 | $ | 11,851 | $ | 6,257 | $ | 4,320 | $ | 10,577 | |||||||||
Fuel and purchased power | — | 4,891 | 4,891 | — | 4,139 | 4,139 | — | 3,356 | 3,356 | ||||||||||||||||||
Operation and maintenance | 2,348 | 1,068 | 3,416 | 2,518 | 1,026 | 3,544 | 2,423 | 964 | 3,387 | ||||||||||||||||||
Depreciation, decommissioning and amortization | 1,622 | — | 1,622 | 1,562 | — | 1,562 | 1,426 | — | 1,426 | ||||||||||||||||||
Property and other taxes | 307 | — | 307 | 296 | (1 | ) | 295 | 285 | — | 285 | |||||||||||||||||
Asset impairment and disallowances | 575 | — | 575 | 32 | — | 32 | — | — | — | ||||||||||||||||||
Total operating expenses | 4,852 | 5,959 | 10,811 | 4,408 | 5,164 | 9,572 | 4,134 | 4,320 | 8,454 | ||||||||||||||||||
Operating income | 1,750 | 1 | 1,751 | 2,274 | 5 | 2,279 | 2,123 | — | 2,123 | ||||||||||||||||||
Interest income and other | 48 | — | 48 | 94 | — | 94 | 85 | — | 85 | ||||||||||||||||||
Interest expense | (519 | ) | (1 | ) | (520 | ) | (494 | ) | (5 | ) | (499 | ) | (463 | ) | — | (463 | ) | ||||||||||
Income before income taxes | 1,279 | — | 1,279 | 1,874 | — | 1,874 | 1,745 | — | 1,745 | ||||||||||||||||||
Income tax expense | 279 | — | 279 | 214 | — | 214 | 601 | — | 601 | ||||||||||||||||||
Net income | 1,000 | — | 1,000 | 1,660 | — | 1,660 | 1,144 | — | 1,144 | ||||||||||||||||||
Dividends on preferred and preference stock | 100 | — | 100 | 91 | — | 91 | 59 | — | 59 | ||||||||||||||||||
Net income available for common stock | $ | 900 | $ | — | $ | 900 | $ | 1,569 | $ | — | $ | 1,569 | $ | 1,085 | $ | — | $ | 1,085 | |||||||||
Core earnings1 | $ | 1,265 | $ | 1,338 | $ | 1,085 | |||||||||||||||||||||
Non-core earnings | |||||||||||||||||||||||||||
Asset impairment | (365 | ) | — | — | |||||||||||||||||||||||
2012 General Rate Case – repair deductions (2009 – 2011) | — | 231 | — | ||||||||||||||||||||||||
Total SCE GAAP earnings | $ | 900 | $ | 1,569 | $ | 1,085 | |||||||||||||||||||||
1 | See use of non-GAAP financial measures in "Management Overview—Highlights of Operating Results." |
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Utility Earning Activities
2013 vs 2012
Utility earning activities were primarily affected by the following:
• | Lower operating revenue of $80 million was primarily due to the following: |
• | A decrease in San Onofre-related estimated revenue of $303 million, as discussed below. |
• | An increase in CPUC-related revenue of $60 million primarily related to the increase in authorized revenue to support rate base growth and operating expenses which was partially offset by the lower CPUC-adopted 2013 return on common equity and Edison SmartConnect® revenue, resulting from the full deployment of the program in 2012. |
• | An increase in FERC-related revenue of $170 million primarily related to rate base growth and higher operating costs. |
• | Lower operation and maintenance expense of $170 million was primarily due to the following: |
• | $170 million decrease in San Onofre-related expense, as discussed below. |
• | $95 million decrease in expense in 2013 due to the full deployment of the Edison SmartConnect® program in 2012. |
• | $40 million decrease in severance costs due to the reductions in workforce (excluding San Onofre) that commenced in 2012. |
• | $85 million of higher operating costs primarily related to information technology, safety, legal and insurance costs. |
• | $45 million of planned outage costs at Mountainview, repair costs at Four Corners, and higher operating costs on CPUC- and FERC-related projects. |
• | Higher depreciation, decommissioning and amortization expense of $60 million was primarily related to increased transmission and distribution investments, including capitalized software costs, offset by the impact from ceasing depreciation on the San Onofre assets, beginning in June 2013. |
• | $575 million impairment charge ($365 million after tax) in 2013 related to the permanent retirement of San Onofre Units 2 and 3. |
• | Lower interest income and other of $46 million primarily due to lower AFUDC equity related to lower rates and construction work in progress balances in 2013, including SCE no longer accruing AFUDC on construction work in progress balances for San Onofre, pending the outcome of the San Onofre OII. In addition, SCE had higher other expenses due to a $20 million penalty that resulted from the Malibu Fire Order Instituting Investigation settlement that was imposed by the CPUC in 2013. See "Item 8. Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses." |
• | Higher interest expense of $25 million primarily due to higher balances on long-term debt to support rate base growth and lower AFUDC debt due to lower rates and construction work in progress balances in 2013. |
• | Higher income taxes of $65 million primarily due to lower income tax benefits, including lower repair deductions (as determined for income tax purposes). See "—Income Taxes" below for more information. |
On June 6, 2013, SCE decided to permanently retire San Onofre Units 2 and 3 and recorded an asset impairment charge of $575 million. See "Management Overview—Permanent Retirement of San Onofre" above for more information. Excluding the asset impairment, the results of San Onofre were slightly lower in 2013 as compared to 2012. Lower revenue and operating costs at San Onofre affects SCE period-to-period results as summarized below:
• | Decrease in revenue of $303 million in 2013 related to lower operating costs (as discussed below), no longer recognizing the return on San Onofre rate base and ceasing depreciation, beginning in June 2013, pending regulatory treatment in the San Onofre OII and the scheduled refueling outage in 2012. |
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• | Decrease in operation and maintenance expense of $170 million primarily due to lower operating costs of $109 million resulting from the early retirement of Units 2 and 3 in June 2013 and $35 million in 2012 related to the scheduled outage at Unit 2. In addition, SCE had lower incremental inspection and repair costs of $53 million (net of SCE's share of payments received from MHI in 2012), which were not offset in revenue above, pending regulatory treatment in the San Onofre OII. These factors were partially offset by additional severance costs of $27 million ($63 million and $36 million in 2013 and 2012, respectively). |
• | Decrease in depreciation of $67 million from ceasing depreciation on San Onofre beginning in June 2013. |
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 Edison SmartConnect® project and the Solar Photovoltaic project. |
• | 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 Edison SmartConnect®. |
• | 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 interest expense of $31 million was primarily due to higher outstanding balances on long-term debt due to new issuances. |
• | 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. |
Utility Cost-Recovery Activities
2013 vs. 2012
Utility cost-recovery activities were primarily affected by the following:
• | Higher fuel and purchased power expense of $752 million was primarily driven by higher power and gas prices in 2013, partially offset by lower realized losses on economic hedging activities ($56 million in 2013 compared to $227 million in 2012) and by a $43 million credit received from the ISO for SCE’s share of a settlement between the FERC and an ISO participant. |
• | Higher operation and maintenance expense of $42 million primarily due to costs for the GHG cap-and-trade program related to utility owned generation, higher costs related to transmission and distribution expenses, higher pension expenses, partially offset by lower spending on various public purpose programs. |
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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—Permanent Retirement of San Onofre" for further information). |
• | Higher operation and maintenance expense of $62 million was primarily due to an increase in pension and postretirement benefit contributions. |
Supplemental Operating Revenue Information
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $11.6 billion for 2013, $11.2 billion for 2012 and $10.0 billion for 2011.
The 2013 revenue reflects:
• | A rate increase of $435 million and a sales volume decrease of $29 million. The rate increase of $435 million is primarily due to the implementation of the 2012 GRC decision. |
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, see below. |
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 the California Department of Water Resources ("CDWR"), and does not recognize as revenue the amounts that SCE billed and collected from its customers for electric power purchased and sold by the CDWR to SCE's customers in 2011 as well as bond-related charges and direct access exit fees, both of which continue until 2022. These contracts were not considered a cost to SCE because SCE was acting as a limited agent to CDWR for these transactions. The amounts collected and remitted to CDWR were $1.1 billion in 2011, primarily related to the power contracts.
Income Taxes
SCE’s income tax provision increased by $65 million, or 30%, in 2013 compared to 2012. The effective tax rates were 21.8% and 11.4% for 2013 and 2012, respectively. The effective tax rate increase in 2013 was primarily due to lower tax benefits associated with repair deductions. Edison International made a voluntary election in 2009 to change its tax accounting method for certain tax repair costs incurred on SCE’s transmission, distribution and generation assets. Regulatory treatment for the 2009 – 2011 incremental repairs deductions taken after the 2009 tax accounting method change resulted in SCE recognizing a $231 earnings benefit in 2012. See "—2012 GRC Earnings Benefits from Repair Deductions" below for more information.
The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences, which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.
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SCE’s income tax provision decreased by $387 million, or 64%, in 2012 compared to 2011. The effective tax rates were 11.4% and 34.4% for 2012 and 2011, respectively. The 2012 effective tax rate included the $231 million earnings benefits related to the 2009 – 2011 repair costs mentioned above as well as earnings benefits for the 2012 repair costs.
See "Item 8. Notes to Consolidated Financial Statements—Note 7. Income Taxes" for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
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.
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 nonutility subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.
Income from Continuing Operations
The Edison International Parent and Other loss from continuing operations in 2013 decreased $45 million from 2012 primarily due to a $37 million charge in 2012 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 and a write-down of an investment in 2012. Included in Edison International Parent and Other are earnings from Edison Capital of $24 million in 2013 and $22 million in 2012. During 2012, Edison Capital sold its lease interest in Unit No. 2 of the Beaver Valley Nuclear Plant resulting in a $31 million benefit in 2012 and an additional income tax benefit of $7 million in 2013 from a revised estimate of state income taxes related to the sale. Edison Capital's 2013 results included income from the wind down of its asset portfolio while Edison Capital's 2012 results included higher income taxes.
The results in 2012 were lower than 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 loss in 2012, compared to 2011, included higher operating expenses and interest costs, increases in deferred income taxes as a result of higher state apportionment rates and a write down of an investment.
Income (Loss) from Discontinued Operations (Net of Tax)
Income (loss) from discontinued operations, net of tax, was $36 million, $(1.69 billion) and $(1.08 billion) for the years ended December 31, 2013, 2012 and 2011, respectively. The 2013 income from discontinued operations reflects a revised estimate of the tax impact of expected future deconsolidation and separation of EME from Edison International. 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 $1.05 billion recorded in the fourth quarter of 2011 resulting primarily from the impairment of the Homer City and other 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 16. Discontinued Operations."
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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 2014 obligations, capital expenditures and dividends through operating cash flows, tax benefits and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities to fund requirements.
Available Liquidity
At December 31, 2013 SCE had $2.46 billion available under its $2.75 billion credit facility, for further details see "Item 8. Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." As discussed in "Management Overview—ERRA Balancing Account," SCE may finance unrecovered power procurement-related costs as well as other balancing account undercollections and working capital requirements to support operations and capital expenditures with commercial paper or other borrowings, subject to availability in the capital markets.
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, 2013, SCE's debt to total capitalization ratio was 0.46 to 1.
Capital Investment Plan
SCE's forecasted capital expenditures for 2014 – 2017 include a capital forecast in the range of $15.1 billion to $17.2 billion. The range is based on an average variability of 12%. 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.
SCE's 2013 capital expenditures and the 2014 – 2017 capital expenditures forecast are set forth in the table below:
(in millions) | 2013 Actual | 2014 | 2015 | 2016 | 2017 | 2014 – 2017 Total | |||||||||||||
Transmission | $ | 1,099 | $ | 1,024 | $ | 1,074 | $ | 946 | $ | 962 | $ | 4,006 | |||||||
Distribution | 2,145 | 2,886 | 3,144 | 3,156 | 3,012 | 12,198 | |||||||||||||
Generation | 286 | 235 | 250 | 253 | 227 | 965 | |||||||||||||
Total estimated capital expenditures1 | $ | 3,530 | $ | 4,145 | $ | 4,468 | $ | 4,355 | $ | 4,201 | $ | 17,169 | |||||||
Total estimated capital expenditures for 2014 – 2017 (using variability discussed above) | $ | 3,647 | $ | 3,933 | $ | 3,850 | $ | 3,697 | $ | 15,127 | |||||||||
1 | Included in SCE's capital expenditures plan are projected environmental capital expenditures of approximately 15% for each year presented. The projected environmental capital expenditures are to comply with laws, regulations, and other nondiscretionary requirements. |
The 2014 planned capital expenditures for projects under CPUC jurisdiction are recovered through the authorized revenue requirement in SCE's 2012 GRC or through other CPUC-authorized mechanisms. Recovery of planned capital expenditures for projects under CPUC jurisdiction beyond 2014 is subject to the outcome of the 2015 GRC or other CPUC approvals. Recovery for 2014 – 2017 planned expenditures for projects under FERC jurisdiction will be pursued through FERC-authorized mechanisms.
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Transmission Projects
A summary of SCE's large transmission and substation projects during the next two years are presented below:
Project Name | Project Lifecycle Phase | Scheduled in Service Date | Direct Expenditures1(in millions) | 2014 – 2017 Forecast (in millions) | |||||
Tehachapi 1-11 | In construction | Late 2016 to Mid 2017 | $ | 3,174 | $ | 966 | |||
West of Devers | In licensing | 2019 – 2020 | 1,034 | 609 | |||||
Coolwater-Lugo | In licensing | 2018 | 813 | 531 | |||||
1 | Direct expenditures include direct labor, land and contract costs incurred for the respective projects and exclude overhead costs that are included in the capital expenditures forecasted for 2014 – 2017. |
Tehachapi Project
In response to opposition from the city of Chino Hills, CPUC proceedings to reexamine construction options, including undergrounding lines for a portion of the Tehachapi Project, were initiated. On July 11, 2013, the CPUC ordered SCE to underground a 3.5 mile portion of the line that traverses Chino Hills, setting a cost estimate of $224 million ($231 million in nominal dollars) for the underground portion. The cost estimate that SCE had proposed for the underground portion of the Tehachapi Project was $360 million, which is reflected in the table above. In September 2013, SCE filed a petition with the CPUC to modify the CPUC's orders pertaining to the scope of the underground project and defer the associated cost adjustments. In January 2014, the CPUC issued a decision permitting SCE to modify the scope of the project to include the necessary voltage control equipment omitted from the earlier decision and increasing the cost estimate by an additional $23 million which is reflected in the table above. In addition to the cost increase related to the undergrounding, in October 2013, the CPUC ordered SCE to implement FAA related scope changes, such as aviation marking and lighting. The FAA related costs and additional estimate updates are also reflected in the table above. The CPUC has not yet issued a decision on what the appropriate vehicle would be to make future adjustments to the cost estimate for the project. The partial undergrounding of the transmission lines could potentially delay the completion of the Tehachapi Project and create additional costs and curtailment charges. Cost recovery for the project is subject to FERC review and approval.
West of Devers Project
West of Devers Project will upgrade SCE's existing West of Devers transmission line system by replacing a portion of the existing 220 kV transmission lines and associated structures with higher-capacity transmission lines and structures. The West of Devers project is intended to facilitate the delivery of electricity produced by new electric generation resources that are being developed or being planned in eastern Riverside County.
Coolwater-Lugo Transmission Project
The Coolwater-Lugo Project will provide additional 220 kV transmission capacity needed in the Kramer Junction and Lucerne Valley areas of San Bernardino County to alleviate an existing bottleneck in order to facilitate interconnection of current and future renewable generation projects. The Coolwater-Lugo scope primarily consists of installing new transmission lines and new substation facilities.
Distribution Projects
Distribution expenditures include projects and programs to meet customer load growth requirements, reliability and infrastructure replacement needs (including replacement of poles to meet current compliance and safety standards), information and other technology and related facility requirements (sometimes referred to as "general plant").
Generation Projects
Generation expenditures include hydro-related capital expenditures associated with infrastructure and equipment replacement and renewal of FERC operating licenses. Infrastructure expenditures include dam improvements, flowline and substation refurbishments, and powerline replacements. Equipment replacement expenditures include transformers, automation, switchgear, hydro turbine repowers, generator rewinds, and small generator replacements.
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Future Energy Storage Requirements
In October of 2013, the CPUC issued a decision adopting policies and targets for energy storage procurement. Under the Energy Storage Procurement Framework and Design Program, SCE is required to procure a total of 580 MW (of the 1325 total MW for the three California investor-owned utilities) of energy storage by 2020 and to install and deliver the storage to the grid by the end of 2024. SCE may request deferment of up to 80% of its procurement targets if it can show unreasonableness of cost or lack of an operationally viable number of bids in the solicitations. SCE is required to hold competitive solicitations in 2014, 2016, 2018, and 2020. SCE is also required to file an application for procuring the specified energy storage resources before each procurement cycle and solicitation. SCE’s first Energy Storage Procurement Application will be filed on March 1, 2014 and its first energy storage solicitation will be held on December 1, 2014.
Regulatory Proceedings
Energy Efficiency Incentive Mechanism
In December 2013, the incentive awarded by the CPUC was $13.5 million for the 2011 energy efficiency program performance period and an opportunity to earn an additional $5 million in 2014 based on the results of a subsequent audit of 2011 energy efficiency programs that is expected to be performed in 2014.
For the 2012 performance period incentive, SCE will file its request for the incentives after the CPUC releases its financial and management audit reports, expected in the third quarter of 2014. SCE estimates it could be awarded an additional $16 million in 2014 for the 2012 period, pending the completion of the CPUC's financial and management audits for that program period. There is no assurance that the CPUC will make an award for any given year.
FERC Formula Rates
In November 2013, the FERC approved a settlement on SCE’s formula rate request that the FERC previously had accepted, subject to refund and settlement procedures. The settlement will determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP"), through December 31, 2017. The settlement provides for a base ROE of 9.30%, the previously authorized 50 basis point incentive for CAISO participation and individual, previously authorized project incentives. This results in a FERC weighted average ROE of approximately 10.45%. The settlement ROE will remain in effect until at least June 30, 2015, when the moratorium, provided for in the settlement, on modifications to the formula rate tariff ends. The transmission revenue requirement and rates that have been in effect and billed to customers since January 1, 2012, were based on a total FERC weighted average ROE of 11.1%. The settlement's provisions and adjustments resulted in retail customer refunds of approximately $178.5 million, which will be returned through lower rates to retail customers beginning in the second quarter of 2014. Under the settlement, the interim rates approved by the FERC (effective on October 1, 2013) were modified on January 1, 2014 through an annual update filing made by SCE in November 2013. The 2014 formula rate update increased the transmission revenue requirement by $32 million to $821 million, mainly due to additional transmission investment. The FERC settlement did not result in a material impact to earnings.
Dividend Restrictions
The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% on a 13-month weighted average basis. At December 31, 2013, SCE's 13-month weighted-average common equity component of total capitalization was 49.2% and the maximum additional dividend that SCE could pay to Edison International under this limitation was approximately $247 million, resulting in a restriction on net assets of approximately $11.9 billion.
During 2013, SCE made $486 million in dividend payments to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the level of capital expenditures, operating cash flows and earnings.
Margin and Collateral Deposits
Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at December 31, 2013, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.
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Some of the power procurement contracts contain provisions that require SCE to maintain an investment grade credit rating from the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral.
The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of December 31, 2013.
(in millions) | ||||
Collateral posted as of December 31, 20131 | $ | 147 | ||
Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade | 77 | |||
Posted and potential collateral requirements2 | $ | 224 | ||
1 | Collateral provided to counterparties and other brokers consisted of $10 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $19 million of cash reflected in "Other current assets" on the consolidated balance sheets and $118 million in letters of credit and surety bonds. |
2 | There would be no significant increase to SCE's total posted and potential collateral requirements based on SCE's forward positions as of December 31, 2013 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level. |
Regulatory Balancing Accounts
SCE's cash flows are affected by regulatory balancing accounts over- or under-collections. Over- and under-collections represent differences between cash collected in current rates for specified forecasted costs and the costs actually incurred. With some exceptions, SCE seeks to adjust rates on an annual basis or at other designated times to recover or refund the balances recorded in its balancing account. Under- or over-collections in these balancing accounts impact cash flows and can change rapidly. Over- and under-collections accrue interest based on a three-month commercial paper rate published by the Federal Reserve.
As of December 31, 2013, SCE had regulatory balancing account net over-collections of $554 million, primarily consisting of $1.7 billion of overcollections related to public purpose-related and energy efficiency program costs, greenhouse gas auction revenue, and base rate differences. Over-collections for public purpose-related programs are expected to decrease as costs are incurred to fund programs established by the CPUC. Greenhouse gas auction revenue and base rate differences are anticipated to be refunded in 2014 through a rate adjustment during the second quarter of 2014. The overcollections were partially offset by under-collections of $1 billion related to fuel and power procurement-related costs (see "Management Overview—ERRA Balancing Account" for further discussion). See "Item 8. Notes to Consolidated Financial Statements—Note 11. Regulatory Assets and Liabilities" for further information.
Edison International Parent and Other
Edison International Parent and Other's liquidity and its ability to pay operating expenses and dividends to common shareholders is dependent on dividends from SCE and access to bank and capital markets. At December 31, 2013 Edison International had $1.2 billion available under its credit facility, for further details, see "Item 8. Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." In December 2013, Edison International implemented a commercial paper program for short-term borrowings.
The debt covenant in Edison International's credit facility requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. The ratio is defined in the credit agreement and generally excluded the consolidated debt and total capital of EME during the periods it was consolidated for financial reporting purposes. At December 31, 2013, Edison International's consolidated debt to total capitalization ratio was 0.45 to 1.
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Historical Cash Flows
SCE
(in millions) | 2013 | 2012 | 2011 | ||||||||
Net cash provided by operating activities | $ | 3,284 | $ | 4,086 | $ | 3,261 | |||||
Net cash provided by financing activities | 508 | 256 | 799 | ||||||||
Net cash used by investing activities | (3,783 | ) | (4,354 | ) | (4,260 | ) | |||||
Net increase (decrease) in cash and cash equivalents | $ | 9 | $ | (12 | ) | $ | (200 | ) | |||
Net Cash Provided by Operating Activities
Net cash from operating activities decreased $802 million in 2013 compared to 2012 primarily due to the following:
• | $307 million cash outflow due to tax payments of $28 million in 2013 compared to tax receipts of $279 million in 2012. |
• | $205 million decrease from balancing accounts primarily composed of: |
• | $885 million decrease resulting from higher ERRA balancing account under-collections for fuel and power procurement-related costs in 2013 compared to 2012. The change in the ERRA balancing account decreased operating cash flows by $1.1 billion in 2013 compared to a decrease in operating cash flows by $257 million in 2012. |
• | $210 million decrease primarily due to increased spending and lower funding of public purpose and energy efficiency programs. |
• | $725 million increase primarily due to the implementation of the 2012 GRC decision which resulted in a rate increase in January 2013 to collect both the 2012 and 2013 rate changes. |
• | $165 million increase resulting from an increase in GHG allowance proceeds in 2013. |
• | $151 million cash outflow related to workforce reduction severance costs in 2013. |
• | timing of cash receipts and disbursements related to working capital items. |
Net cash from operating activities increased $825 million in 2012 compared to 2011 primarily due to the following:
• | $265 million increase from balancing accounts composed of: |
• | $375 million increase resulting from actual electricity sales exceeding forecasted electricity sales primarily related to warmer weather during the summer months; |
• | $150 million increase primarily due to the funding of public purpose and energy efficiency programs; |
• | $110 million increase resulting from greenhouse gas emission auction proceeds; and |
• | $370 million decrease resulting from lower balancing account overcollections for fuel and power procurement-related costs in 2012 when compared to 2011. The 2012 decrease in overcollections was due to lower realized power and natural gas prices compared to the amounts forecasted in rates. |
• | $193 million increase resulting from a tax refund relating to the 2011 net operating loss carryback; |
• | $68 million cash inflow resulting from proceeds of U.S. Treasury Grants relating to solar photovoltaic projects and other specific energy-related projects made available as a result of the American Recovery and Reinvestment Act of 2009; |
• | $60 million cash inflow resulting from a security deposit received related to transmission and distribution construction; and |
• | timing of cash receipts and disbursements related to working capital items. |
43
Net Cash Provided by Financing Activities
The following table summarizes cash provided by financing activities for 2013, 2012 and 2011. Issuances of debt and preference stock are discussed in "Item 8. Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "—Note 13. Preferred and Preference Stock."
(in millions) | 2013 | 2012 | 2011 | ||||||||
Issuances of first and refunding mortgage bonds, net | $ | 1,973 | $ | 391 | $ | 887 | |||||
Payments of senior notes | (820 | ) | (6 | ) | (14 | ) | |||||
Net increases (decreases) in short-term borrowings, net | (1 | ) | (250 | ) | 419 | ||||||
Issuances of preference stock, net | 387 | 804 | 123 | ||||||||
Payments of common stock dividends to Edison International | (486 | ) | (469 | ) | (461 | ) | |||||
Redemptions of preference stock | (400 | ) | (75 | ) | — | ||||||
Bonds remarketed, net | 195 | — | — | ||||||||
Bonds purchased | (196 | ) | — | (86 | ) | ||||||
Payments of preferred and preference stock dividends | (101 | ) | (82 | ) | (59 | ) | |||||
Settlement of stock-based awards (facilitated by a third party) | (137 | ) | (103 | ) | (49 | ) | |||||
Other | 94 | 46 | 39 | ||||||||
Net cash provided by financing activities | $ | 508 | $ | 256 | $ | 799 | |||||
Net Cash Used by Investing Activities
Cash flows from investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Amounts paid for capital expenditures were $3.6 billion for 2013 and $4.1 billion for both 2012 and 2011, primarily related to transmission, distribution and generation investments. Net purchases of nuclear decommissioning trust investments and other were $334 million, $215 million and $167 million for 2013, 2012 and 2011, respectively. In addition, in 2013 SCE received $181 million for the sale of its ownership interest in Units 4 and 5 of the Four Corners Generating Station.
Edison International Parent and Other
The table below sets forth condensed historical cash flow from continuing operations for Edison International Parent and Other adjusted for the non-cash impact related to the treatment of discontinued operations.
(in millions) | 2013 | 2012 | 2011 | ||||||||
Net cash provided (used) by operating activities | $ | (81 | ) | $ | (115 | ) | $ | 20 | |||
Net cash provided by financing activities | 73 | 20 | 30 | ||||||||
Net cash provided (used) by investing activities | (25 | ) | 108 | 5 | |||||||
Net increase (decrease) in cash and cash equivalents | |||||||||||