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.
Electric Power Industry Trends
Multiple factors are converging to put the electric power industry on the cusp of significant change. These factors include:
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leveling of demand due to decelerating population growth, demand side management of energy and an increase in distributed- or self-generation;
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prioritization by public policymakers of initiatives to reduce carbon emissions and advance competition;
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increased need for infrastructure replacement and development to accommodate new technologies; and
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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."
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
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.
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."
For Palo Verde, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below.
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.
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.
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.
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
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
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
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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
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.
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."
EXECUTIVE OFFICERS OF EDISON INTERNATIONAL
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:
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.
Puget Sound Energy is a regulated energy utility in Washington State and is not a parent, affiliate or subsidiary of Edison International.
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.
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.
EXECUTIVE OFFICERS OF SOUTHERN CALIFORNIA EDISON COMPANY
As set forth in Article IV of SCE's Bylaws, the elected officers of SCE are chosen annually by, and serve at the pleasure of, SCE's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the above officers 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:
See footnote 4 under Executive Officers of Edison International above.
See footnote 1 under Executive Officers of Edison International above.
Entergy Nuclear Operations, Inc. is a subsidiary of Entergy Corporation, an integrated energy company and is not a parent, affiliate or subsidiary of SCE.
See footnote 3 under Executive Officers of Edison International above.
PART II
ITEM 5.
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.
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.
Comparison of Five-Year Cumulative Total Return
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.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Selected Financial Data: 2009 - 2013
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
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.
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.
ITEM 7.
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.
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.
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.
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:
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.
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.
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.
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
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.
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:
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Maintaining reliability and expanding the capability of SCE's transmission and distribution system through infrastructure replacements and improvements.
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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.
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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.
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.
RESULTS OF OPERATIONS
SCE
SCE's results of operations are derived mainly through two sources:
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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.
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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:
See use of non-GAAP financial measures in "Management Overview-Highlights of Operating Results."
Utility Earning Activities
2013 vs 2012
Utility earning activities were primarily affected by the following:
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Lower operating revenue of $80 million was primarily due to the following:
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A decrease in San Onofre-related estimated revenue of $303 million, as discussed below.
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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.
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An increase in FERC-related revenue of $170 million primarily related to rate base growth and higher operating costs.
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Lower operation and maintenance expense of $170 million was primarily due to the following:
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$170 million decrease in San Onofre-related expense, as discussed below.
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$95 million decrease in expense in 2013 due to the full deployment of the Edison SmartConnect® program in 2012.
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$40 million decrease in severance costs due to the reductions in workforce (excluding San Onofre) that commenced in 2012.
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$85 million of higher operating costs primarily related to information technology, safety, legal and insurance costs.
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$45 million of planned outage costs at Mountainview, repair costs at Four Corners, and higher operating costs on CPUC- and FERC-related projects.
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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.
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$575 million impairment charge ($365 million after tax) in 2013 related to the permanent retirement of San Onofre Units 2 and 3.
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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."
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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.
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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:
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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).
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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:
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Higher operating revenue was primarily due to the following:
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$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
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$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.
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Higher operation and maintenance expense due to the following:
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$112 million in accrued severance costs from current and approved reductions in staffing;
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$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
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$85 million of lower costs related to information technology, transmission and distribution expenses, San Onofre and benefits realized from Edison SmartConnect®.
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Higher depreciation, decommissioning and amortization expense of $136 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs.
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$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.
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Higher interest expense of $31 million was primarily due to higher outstanding balances on long-term debt due to new issuances.
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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.
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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:
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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.
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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.
2012 vs. 2011
Utility cost-recovery activities were primarily affected by the following:
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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).
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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:
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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:
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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
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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:
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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
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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.
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."
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:
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.
Transmission Projects
A summary of SCE's large transmission and substation projects during the next two years are presented below:
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.
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.
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.
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.
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.
Historical Cash Flows
SCE
Net Cash Provided by Operating Activities
Net cash from operating activities decreased $802 million in 2013 compared to 2012 primarily due to the following:
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$307 million cash outflow due to tax payments of $28 million in 2013 compared to tax receipts of $279 million in 2012.
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$205 million decrease from balancing accounts primarily composed of:
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$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.
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$210 million decrease primarily due to increased spending and lower funding of public purpose and energy efficiency programs.
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$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.
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$165 million increase resulting from an increase in GHG allowance proceeds in 2013.
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$151 million cash outflow related to workforce reduction severance costs in 2013.
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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:
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$265 million increase from balancing accounts composed of:
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$375 million increase resulting from actual electricity sales exceeding forecasted electricity sales primarily related to warmer weather during the summer months;
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$150 million increase primarily due to the funding of public purpose and energy efficiency programs;
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$110 million increase resulting from greenhouse gas emission auction proceeds; and
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$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.
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$193 million increase resulting from a tax refund relating to the 2011 net operating loss carryback;
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$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;
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$60 million cash inflow resulting from a security deposit received related to transmission and distribution construction; and
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timing of cash receipts and disbursements related to working capital items.
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."
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.
Net Cash Provided (Used) by Continuing Operating Activities
Net cash from continuing operating activities increased $34 million in 2013 compared to 2012 primarily due to the timing of payments and receipts relating to interest, operating costs and income taxes.
Net cash from continuing operating activities decreased $135 million in 2012 compared to 2011 primarily due to net tax payments of approximately $114 million in 2012 compared to net tax receipts of approximately $33 million in 2011.
Net Cash Provided by Continuing Financing Activities
Net cash provided by continuing financing activities were as follows:
Net Cash Provided by Continuing Investing Activities
Net cash provided by continuing investing activities during 2013 relate to Edison International's investment of $25 million in equity interests of competitive energy-related businesses, including the acquisition of SoCore Energy, LLC, a distributed solar developer focused on commercial rooftop installations.
Net cash provided by continuing investing activities during 2012 related to Edison International's sale of its lease interest in Unit No. 2 of the Beaver Valley Nuclear Power Plant to a third party for $108 million.
Contractual Obligations and Contingencies
Contractual Obligations
Edison International Parent and Other and SCE's contractual obligations as of December 31, 2013, for the years 2014 through 2018 and thereafter are estimated below.
For additional details, see "Item 8. Notes to Consolidated Financial Statements-Note 5. Debt and Credit Agreements." Amount includes interest payments totaling $9.21 billion and $56 million over applicable period of the debt for SCE and Edison International Parent and Other, respectively.
Certain power purchase agreements entered into with independent power producers are treated as operating or capital leases. At December 31, 2013, minimum operating lease payments for power purchase agreements were $1.3 billion in 2014, $1.3 billion in 2015, $1.3 billion in 2016, $1.4 billion in 2017, $1.3 billion in 2018, and $17.6 billion for the thereafter period. At December 31, 2013, minimum capital lease payments for power purchase agreements were $33 million in 2014, $33 million 2015, $33 million for 2016, $33 million for 2017, $33 million for 2018, and $356 million for the thereafter period (amounts include executory costs and interest of $118 million and $194 million, respectively). For further discussion, see "Item 8. Notes to Consolidated Financial Statements-Note 12. Commitments and Contingencies."
At December 31, 2013, SCE's minimum other operating lease payments were primarily related to vehicles, office space and other equipment. For further discussion, see "Item 8. Notes to Consolidated Financial Statements-Note 12. Commitments and Contingencies."
For additional details, see "Item 8. Notes to Consolidated Financial Statements-Note 12. Commitments and Contingencies." At December 31, 2013, other commitments were primarily related to maintaining reliability and expanding SCE's transmission and distribution system.
At December 31, 2013, Edison International Parent and Other and SCE had estimated contributions to the pension and PBOP plans. SCE's estimated contributions are $187 million, $191 million, $218 million, and $160 million in 2014, 2015, 2016 and 2017, respectively. Edison International Parent and Other estimated contributions are $27 million, $25 million, $29 million, and $25 million for the same respective periods. The estimated contributions for Edison International and SCE are not available beyond 2017. These amounts represent estimates that are based on assumptions that are subject to change. See "Item 8. Notes to Consolidated Financial Statements-Note 8. Compensation and Benefit Plans" for further information.
At December 31, 2013, Edison International and SCE had a total net liability recorded for uncertain tax positions of $705 million and $400 million, respectively, which is excluded from the table. Edison International and SCE cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the IRS.
The contractual obligations table does not include derivative obligations and asset retirement obligations, which are discussed in "Item 8. Notes to Consolidated Financial Statements-Note 6. Derivative Instruments and Hedging Activities," and "-Note 1. Summary of Significant Accounting Policies," respectively.
Contingencies
Edison International has a contingency related to the Potential Claims by EME and SCE has contingencies related to the Permanent Retirement of San Onofre, SED Investigations, Four Corners New Source Review Litigation, Nuclear Insurance, Wildfire Insurance and Spent Nuclear Fuel which are discussed in "Item 8. Notes to Consolidated Financial Statements-Note 12. Commitments and Contingencies."
Environmental Remediation
SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, SCE records the lower end of this reasonably likely range of costs (classified as "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
As of December 31, 2013, SCE had identified 19 material sites for remediation and recorded an estimated minimum liability of $110 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Item 8. Notes to Consolidated Financial Statements-Note 12. Commitments and Contingencies" for further discussion.
Off-Balance Sheet Arrangements
Edison International's indirect subsidiary, Edison Capital has one remaining leveraged lease investment and also has investments in affordable housing projects that apply the equity method of accounting. These off-balance sheet transactions are not material to Edison International's consolidated financial statements. SCE has variable interests in power purchase contracts with variable interest entities and a variable interest in unconsolidated Trust I and Trust II that issued $475 million (aggregate liquidation preference) of 5.625% and $400 million (aggregate liquidation preference) of 5.10%, trust securities, respectively, to the public, see "Item 8. Notes to Consolidated Financial Statements-Note 3. Variable Interest Entities."
Environmental Developments
For a discussion of environmental developments, see "Item 1. Business-Environmental Regulation of Edison International and Subsidiaries."
MARKET RISK EXPOSURES
Edison International and SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. Derivative instruments are used, as appropriate, to manage market risks including market risks of SCE's customers. For a further discussion of market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Item 8. Notes to Consolidated Financial Statements-Note 6. Derivative Instruments and Hedging Activities" and "-Note 4. Fair Value Measurements."
Interest Rate Risk
Edison International and SCE are exposed to changes in interest rates primarily as a result of its financing and short-term investing and borrowing activities used for liquidity purposes, to fund business operations and to fund capital investments. The nature and amount of Edison International and SCE's long-term and short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. Changes in interest rates may impact SCE's authorized rate of return for the period beyond 2014, see "Item 1. Business-Overview of Ratemaking Process-CPUC" for further discussion. The following table summarizes the increase or decrease to the fair value of long-term debt including the current portion as of December 31, 2013, if the market interest rates were changed while leaving all other assumptions the same:
Commodity Price Risk
SCE and its customers are exposed to the risk of a change in the market price of natural gas, electric power and transmission congestion. SCE's hedging program reduces exposure to variability in market prices related to SCE's purchases and sales of electric power and natural gas. SCE expects recovery of its related hedging costs through the ERRA balancing account or CPUC-approved procurement plans, and as a result, exposure to commodity price is not expected to impact earnings, but may impact timing of cash flows. SCE's hedging program reduces customer exposure to variability in market prices. As part of this program, SCE enters into energy options, swaps, forward arrangements, tolling arrangements, and congestion revenue rights ("CRRs"). The transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans.
Fair Value of Derivative Instruments
With some exceptions, derivative instruments are included in the consolidated balance sheets at fair value. Realized gains and losses from derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no impact on earnings. SCE does not use hedge accounting for these transactions due to this regulatory accounting treatment. For further discussion on fair value measurements and the fair value hierarchy, see "Item 8. Notes to Consolidated Financial Statements-Note 4. Fair Value Measurements."
The fair value of outstanding derivative instruments used to mitigate exposure to commodity price risk was a net liability of $821 million and $851 million at December 31, 2013 and 2012, respectively. The following table summarizes the increase or decrease to the fair values of outstanding derivative instruments included in the consolidated balance sheets as of December 31, 2013, if the electricity prices or gas prices were changed while leaving all other assumptions constant:
Credit Risk
For information related to credit risks, see "Item 8. Notes to Consolidated Financial Statements-Note 6. Derivative Instruments and Hedging Activities."
Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements,
including master netting agreements. As of December 31, 2013, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:
SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.
Exposure excludes amounts related to contracts classified as normal purchases and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable.
The exposure in this category relates to long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
The accounting policies described below are considered critical to obtaining an understanding of Edison International and SCE's consolidated financial statements because their application requires the use of significant estimates and judgments by management in preparing the consolidated financial statements. Management estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the estimate requires significant assumptions and changes in the estimate or, the use of alternative estimates, that could have a material impact on Edison International's results of operations or financial position. For more information on Edison International's accounting policies, see "Item 8. Notes to Consolidated Financial Statements-Note 1. Summary of Significant Accounting Policies."
Rate Regulated Enterprises
Nature of Estimate Required. SCE follows the accounting principles for rate-regulated enterprises which are required for entities whose rates are set by regulators at levels intended to recover the estimated costs of providing service, plus a return on net investment, or rate base. Regulators may also impose certain penalties or grant certain incentives. Due to timing and other differences in the collection of revenue, these principles allow a cost that would otherwise be charged as an expense by an unregulated entity to be capitalized as a regulatory asset if it is probable that such cost is recoverable through future rates; conversely the principles allow creation of a regulatory liability for amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred.
Key Assumptions and Approach Used. SCE's management assesses at the end of each reporting period whether regulatory assets are probable of future recovery by considering factors such as the current regulatory environment, the issuance of rate orders on recovery of the specific or a similar incurred cost to SCE or other rate-regulated entities, and other factors that would indicate that the regulator will treat an incurred cost as allowable for ratemaking purposes. Using these factors, management has determined that existing regulatory assets and liabilities are probable of future recovery or settlement. This determination reflects the current regulatory climate and is subject to change in the future.
Effect if Different Assumptions Used. Significant management judgment is required to evaluate the anticipated recovery of regulatory assets, the recognition of incentives and revenue subject to refund, as well as the anticipated cost of regulatory liabilities or penalties. If future recovery of costs ceases to be probable, all or part of the regulatory assets and liabilities would have to be written off against current period earnings. At December 31, 2013, the consolidated balance sheets included regulatory assets of $7.78 billion and regulatory liabilities of $5.76 billion. If different judgments were reached on recovery of costs and timing of income recognition, SCE's earnings may vary from the amounts reported.
Application to San Onofre
As discussed in "Management Overview-Permanent Retirement of San Onofre," on June 6, 2013, SCE decided to permanently retire San Onofre Units 2 and 3. 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 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 assessment, SCE reclassified $1,521 million of its total investment in San Onofre at May 31, 2013 as a regulatory asset and recorded an impairment charge of $575 million.
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 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. See "Management Overview-Permanent Retirement of San Onofre" for further discussion.
Accounting for Contingencies, Guarantees and Indemnities
Nature of Estimates Required. Edison International and SCE record loss contingencies when management determines that the outcome of future events is probable of occurring and when the amount of the loss can be reasonably estimated. When a guarantee or indemnification subject to authoritative guidance is entered into, Edison International and SCE record a liability for the estimated fair value of the underlying guarantee or indemnification. Gain contingencies are recognized in the financial statements when they are realized.
Key Assumptions and Approach Used. The determination of a reserve for a loss contingency is based on management judgment and estimates with respect to the likely outcome of the matter, including the analysis of different scenarios. Liabilities are recorded or adjusted when events or circumstances cause these judgments or estimates to change. In assessing whether a loss is a reasonable possibility, Edison International and SCE may consider the following factors, among others: the nature of the litigation, claim or assessment, available information, opinions or views of legal counsel and other advisors, and the experience gained from similar cases. Edison International and SCE provide disclosures for material contingencies when there is a reasonable possibility that a loss or an additional loss may be incurred. Some guarantees and indemnifications could have a significant financial impact under certain circumstances, and management also considers the probability of such circumstances occurring when estimating the fair value.
Effect if Different Assumptions Used. Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and could have a significant impact on the liabilities, revenue and expenses recorded on the consolidated financial statements. In addition, for guarantees and indemnities actual results may differ from the amounts recorded and disclosed and could have a significant impact on Edison International's and SCE's consolidated financial statements. For a discussion of contingencies, guarantees and indemnities, see "Item 8. Notes to Consolidated Financial Statements-Note 12. Commitments and Contingencies."
Potential Claims by EME
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's 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 in December 2013. Under the December Plan of Reorganization, the remaining assets of EME would include causes of action against Edison International that were not released under the December Plan of Reorganization and would have re-vested in Reorganized EME.
Under the Internal Revenue Code and applicable state statutes, Edison International Parent is jointly liable for qualified retirement plans and federal and specific state tax liabilities. As a result of the deconsolidation and the existence of joint liabilities, Edison International has recorded liabilities at December 31, 2013 of $325 million for qualified retirement plans
related to plan participants of EME and joint tax liabilities. Under the qualified plan documents and tax allocation agreements, EME is obligated to pay for such liabilities and, accordingly, at December 31, 2013 Edison International has recorded corresponding receivables from EME.
The outcome of the EME bankruptcy proceeding as well as any litigation brought by EME against Edison International is uncertain. Accordingly, management judgment was required to assess the collectability of the receivables recorded and outcome of the bankruptcy proceeding. At December 31, 2013, management concluded that it is probable that a loss would be incurred and has recorded an estimated loss of $150 million. The outcome of the EME bankruptcy could result in losses different than the amounts recorded by Edison International and such amounts could be material.
In February 2014, Edison International, EME and the Consenting Noteholders entered into a Settlement Agreement pursuant to which EME amended its Plan of Reorganization. The Amended Plan of Reorganization, including the Settlement Agreement, is subject to the approval of the Bankruptcy Court. See "Management Overview-EME Chapter 11 Bankruptcy Filing" for further information.
Nuclear Decommissioning - Asset Retirement Obligation
Key Assumptions and Approach Used. The liability to decommission SCE's nuclear power facilities is based on decommissioning studies performed in 2010 for Palo Verde and a 2013 updated decommissioning cost estimate for the retirement of both San Onofre Units 2 and 3. See "Management Overview-Permanent Retirement of San Onofre" for further discussion of the plans for decommissioning of San Onofre. The studies estimate that SCE will spend approximately $7.1 billion through 2053 to decommission San Onofre and Palo Verde. Decommissioning cost estimates are updated in each Nuclear Decommissioning Triennial Proceeding. The current ARO estimates for San Onofre and Palo Verde are based on the assumptions from these decommissioning studies:
•
Decommissioning Costs. The estimated costs for labor, dismantling and disposal costs, depth of site remediation, energy and miscellaneous costs.
•
Escalation Rates. Annual escalation rates are used to convert the decommissioning cost estimates in base year dollars to decommissioning cost estimates in future-year dollars. Escalation rates are primarily used for labor, material, equipment, energy and low level radioactive waste burial costs. SCE's current estimate is based on SCE's decommissioning cost methodology used for ratemaking purposes, escalated at rates ranging from 1.5% to 7.3% (depending on the cost element) annually.
•
Timing. Cost estimates for Palo Verde are based on an assumption that decommissioning will commence promptly after the current NRC operating licenses expire. The Palo Verde 1, 2, 3 operating licenses currently expire in 2045, 2046 and 2047 respectively. Cost estimates for San Onofre are based on an assumption that decommissioning will commence in 2014. For further information, see "Management Overview-Permanent Retirement of San Onofre."
•
Spent Fuel Dry Storage Costs. Cost estimates are based on an assumption that the DOE will begin to take spent fuel in 2024, and will remove the last spent fuel from the San Onofre and Palo Verde sites by 2051 and 2076, respectively. Costs for spent fuel monitoring are included until 2051 and 2076, respectively.
•
Changes in decommissioning technology, regulation, and economics. The current cost studies assume the use of current technologies under current regulations and at current cost levels.
Effect if Different Assumptions Used. The ARO for decommissioning SCE's nuclear facilities was $3.3 billion at December 31, 2013. As discussed in "Management Overview-Permanent Retirement of San Onofre" SCE expects to complete an updated site-specific decommissioning plan for San Onofre by the end of 2014 which once received may result in material revisions to the recorded ARO liability. Changes in the estimated costs or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission these facilities which could have a material effect on the recorded liability and related regulatory asset.
The following table illustrates the increase to the ARO and regulatory asset if the escalation rate was adjusted while leaving all other assumptions constant:
Pensions and Postretirement Benefits Other than Pensions
Nature of Estimate Required. Authoritative accounting guidance requires companies to recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets and liabilities in the balance sheet; the assets and/or liabilities are normally offset through other comprehensive income (loss). In accordance with authoritative guidance for rate-regulated enterprises, regulatory assets and liabilities are recorded instead of charges and credits to other comprehensive income (loss) for its postretirement benefit plans that are recoverable in utility rates. Edison International and SCE have a fiscal year-end measurement date for all of its postretirement plans.
Key Assumptions of Approach Used. Pension and other postretirement obligations and the related effects on results of operations are calculated using actuarial models. Two critical assumptions, discount rate and expected return on assets, are important elements of plan expense and liability measurement. Additionally, health care cost trend rates are critical assumptions for postretirement health care plans. These critical assumptions are evaluated at least annually. Other assumptions, which require management judgment, such as rate of compensation increases, rates of retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.
As of December 31, 2013, Edison International's and SCE's pension plans had a $4.2 billion and $3.7 billion benefit obligation, respectively, and total 2013 expense for these plans was $188 million and $176 million, respectively. As of December 31, 2013, the benefit obligation for both Edison International's and SCE's PBOP plans was $2.2 billion and total 2013 expense for Edison International's and SCE's plans were $32 million and $31 million, respectively. Annual contributions made to most of SCE's pension plans are currently recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the related annual expense.
Edison International and SCE used the following critical assumptions to determine expense for pension and other postretirement benefit for 2013:
*
Not applicable to pension plans.
The discount rate enables Edison International and SCE to state expected future cash flows at a present value on the measurement date. Edison International and SCE select its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. The AON-Hewitt yield curve is considered in determining the discount rate.
To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns on plan assets. A portion of PBOP trusts asset returns are subject to taxation, so the 6.7% rate of return on plan assets above is determined on an after-tax basis. Actual time-weighted, annualized returns on the pension plan assets were 16.6%, 14.5% and 7.8% for the one-year, five-year and ten-year periods ended December 31, 2013, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 18.6%, 13.7%, and 6.5% over these same periods. Accounting principles provide that differences between expected and actual returns are recognized over the average future service of employees.
The health care cost trend rate gradually declines to 5.0% for 2020 and beyond.
Pension expense is recorded for SCE based on the amount funded to the trusts, as calculated using an actuarial method required for ratemaking purposes, in which the impact of market volatility on plan assets is recognized in earnings on a more gradual basis. Any difference between pension expense calculated in accordance with ratemaking methods and pension expense calculated in accordance with authoritative accounting guidance for pension is accumulated as a regulatory asset or liability, and is expected, over time, to be recovered from or returned to customers. As of December 31, 2013, this cumulative difference amounted to a regulatory asset of $177 million, meaning that the accounting method has recognized more in expense than the ratemaking method since implementation of authoritative guidance for employers' accounting for pensions in 1987.
As of December 31, 2013, Edison International and SCE both had unrecognized pension costs of $383 million, and unrecognized PBOP costs of $19 million and $15 million, respectively. The unrecognized pension and PBOP costs primarily consisted of the cumulative impact of the reduced discount rates on the respective benefit obligations and the cumulative difference between the expected and actual rate of return on plan assets. Of these deferred costs, $353 million of SCE's pension costs and $15 million of SCE's PBOP costs are recorded as regulatory assets, an offset to the underfunded liabilities of these plans, and will be amortized to expense over the average expected future service of employees.
Edison International's and SCE's pension and PBOP plans are subject to limits established for federal tax deductibility. SCE funds its pension and PBOP plans in accordance with amounts allowed by the CPUC. Executive pension plans and competitive power generation PBOP plans have no plan assets.
Effect if Different Assumptions Used. Changes in the estimated costs or timing of pension and other postretirement benefit obligations, or the assumptions and judgments used by management underlying these estimates, could have a material effect on the recorded expenses and liabilities.
The following table summarizes the increase or (decrease) to projected benefit obligation for pension and the accumulated benefit obligation for PBOP if the discount rate were changed while leaving all other assumptions constant:
A one percentage point increase in the expected rate of return on pension plan assets would decrease both Edison International's and SCE's current year expense by $32 million and a one percentage point increase in the expected rate of return on PBOP plan assets would decrease both Edison International's and SCE's current year expense by $17 million.
The following table summarizes the increase or (decrease) to accumulated benefit obligation and annual aggregate service and interest costs for PBOP if the health care cost trend rate was changed while leaving all other assumptions constant:
Income Taxes
Nature of Estimates Required. As part of the process of preparing its consolidated financial statements, Edison International and SCE are required to estimate income taxes for each jurisdiction in which they operate. This process involves estimating actual current period tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within Edison International and SCE's consolidated balance sheets, including net operating loss and tax credit carryforwards that can be used to reduce liabilities in future periods.
Edison International and SCE takes certain tax positions they believe are in accordance with the applicable tax laws. However, these tax positions are subject to interpretation by the IRS, state tax authorities and the courts. Edison International and SCE determine uncertain tax positions in accordance with the authoritative guidance.
Key Assumptions and Approach Used. Accounting for tax obligations requires management judgment. Edison International and SCE's management uses judgment in determining whether the evidence indicates it is more likely than not, based solely on the technical merits, that a tax position will be sustained, and to determine the amount of tax benefits to be recognized. Judgment is also used in determining the likelihood a tax position will be settled and possible settlement outcomes. In assessing uncertain tax positions Edison International and SCE consider, among others, the following factors: the facts and circumstances of the position, regulations, rulings, and case law, opinions or views of legal counsel and other advisers, and
the experience gained from similar tax positions. Edison International and SCE's management evaluates uncertain tax positions at the end of each reporting period and makes adjustments when warranted based on changes in fact or law.
Effect if Different Assumptions Used. Actual income taxes may differ from the estimated amounts which could have a significant impact on the liabilities, revenue and expenses recorded in the financial statements. Edison International and SCE continue to be under audit or subject to audit for multiple years in various jurisdictions. Significant judgment is required to determine the tax treatment of particular tax positions that involve interpretations of complex tax laws. A tax liability has been recorded with respect to tax positions in which the outcome is uncertain and the effect is estimable. Such liabilities are based on judgment and a final determination could take many years from the time the liability is recorded. Furthermore, settlement of tax positions included in open tax years may be resolved by compromises of tax positions based on current factors and business considerations that may result in material adjustments to income taxes previously estimated.
Application to Net Operating Loss and Tax Credit Carryforwards
At December 31, 2013, Edison International has net operating losses and tax credit carryforwards of $2.2 billion. Under federal and California tax regulations, a tax deconsolidation of EME in future periods as provided for in EME's December Plan of Reorganization, would result in EME retaining a portion of such carryforward tax benefits and reducing the amounts that Edison International would be eligible to use in future periods. As a result, Edison International has recorded a valuation allowance equal to the estimated amount of such tax benefits as of December 31, 2013 as calculated under the applicable federal and California tax regulations.
In February 2014, Edison International, EME and the Consenting Noteholders entered into a Settlement Agreement pursuant to which EME has amended its Plan of Reorganization. The Amended Plan of Reorganization, including the Settlement Agreement, is subject to the approval of the Bankruptcy Court. Under the Settlement Agreement, Edison International would retain all of EME’s carryforward tax benefits. As this agreement was entered into in 2014 and is subject to approval by the Bankruptcy Court, it is accounted for as a subsequent event under GAAP and not reflected in the 2013 financial statements (referred as a "Type II" subsequent event) and for which disclosure is required. See "Management Overview-EME Chapter 11 Bankruptcy Filing" for further information.
NEW ACCOUNTING GUIDANCE
New accounting guidance is discussed in "Item 8. Notes to Consolidated Financial Statements-Note 1. Summary of Significant Accounting Policies-New Accounting Guidance."
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to Item 7A is included in the MD&A under the headings "Market Risk Exposures"
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Shareholders of Edison International
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in equity and cash flows present fairly, in all material respects, the financial position of Edison International and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15 (a) (2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 25, 2014
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Shareholder of Southern California Edison Company
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in equity and cash flows present fairly, in all material respects, the financial position of Southern California Edison Company and its subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15 (a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
February 25, 2014
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
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The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Income
Southern California Edison Company
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Balance Sheets
Southern California Edison Company
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Balance Sheets
Southern California Edison Company
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Cash Flows
Southern California Edison Company
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Changes in Equity
Southern California Edison Company
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Organization and Basis of Presentation
Edison International is the parent holding company of Southern California Edison Company ("SCE"). SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000 square mile area of southern California. Edison International is also the parent company of subsidiaries that are engaged in competitive businesses related to the delivery or use of electricity. Such competitive business activities are currently not material to report as a separate business segment. These combined notes to the consolidated financial statements apply to both Edison International and SCE unless otherwise described. Edison International's consolidated financial statements include the accounts of Edison International, SCE and other wholly owned and controlled subsidiaries. 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. SCE's consolidated financial statements include the accounts of SCE and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated from the consolidated financial statements.
Edison International's and SCE's accounting policies conform to accounting principles generally accepted in the United States of America, including the accounting principles for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utility Commission ("CPUC") and the Federal Energy Regulatory Commission ("FERC"). SCE applies authoritative guidance for rate-regulated enterprises to the portion of its operations in which regulators set rates at levels intended to recover the estimated costs of providing service, plus a return on net investments in assets, or rate base. Regulators may also impose certain penalties or grant certain incentives. Due to timing and other differences in the collection of electric utility revenue, these principles require an incurred cost that would otherwise be charged to expense by a nonregulated entity to be capitalized as a regulatory asset if it is probable that the cost is recoverable through future rates; and conversely the principles require recording of a regulatory liability for amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred. SCE assesses, at the end of each reporting period, whether regulatory assets are probable of future recovery. See Note 11 for composition of regulatory assets and liabilities.
Beginning in the fourth quarter of 2012, Edison Mission Energy ("EME") met the definition of a discontinued operation and was classified separately in Edison International's consolidated financial statements. Effective December 17, 2012, Edison International no longer consolidates the earnings and losses of EME or its subsidiaries and has reflected its ownership interest in EME utilizing the cost method of accounting prospectively. Except as indicated, amounts in the notes to the consolidated financial statements related to continuing operations of Edison International. See Note 16 for information related to discontinued operations.
The preparation of financial statements in conformity with United States generally accepted accounting principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reported period. Actual results could differ from those estimates.
Cash Equivalents
Cash equivalents included investments in money market funds. Generally, the carrying value of cash equivalents equals the fair value, as these investments have original maturities of 3 months or less. The cash equivalents were as follows:
Cash is temporarily invested until required for check clearing from the primary disbursement accounts. Checks issued, but not yet paid by the financial institution, are reclassified from cash to accounts payable at the end of each reporting period as follows:
Allowance for Uncollectible Accounts
Allowances for uncollectible accounts are provided based upon a variety of factors, including historical amounts written-off, current economic conditions and assessment of customer collectability.
Inventory
Inventory is primarily composed of materials, supplies and spare parts, and stated at the lower of cost or market, cost being determined by the average cost method.
As a result of the permanent retirement of San Onofre, SCE has reclassified $100 million of its material, supplies and spare parts to a regulatory asset, see Note 9 for further details.
Energy Credits and Allowances
Renewable energy certificates or credits ("RECs") represent rights established by governmental agencies for the environmental, social, and other nonpower qualities of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets. Retail sellers of electricity obtain RECs through renewable power purchase agreements, internal generation or separate purchases in the market to comply with renewables portfolio standards established in certain such governmental agencies. RECs are the mechanism used to verify renewables portfolio standards compliance and are recognized at the lower of weighted-average cost or market when amounts purchased are in excess of the amounts needed to comply with RPS requirements. The cost of purchased RECs is recoverable as part of the cost of purchased power.
SCE is allocated greenhouse gas ("GHG") allowances annually which it is then required to sell them into quarterly auctions. GHG proceeds from the auction are recorded as a regulatory liability to be refunded to customers. SCE purchases GHG allowances from quarterly auctions or bilateral parties to satisfy its GHG emission compliance obligations and recovers such costs of GHG allowances from customers. GHG allowances held for use are classified as "Other current assets" on the consolidated balance sheets and are stated, similar to an inventory method, at the lower of weighted-average cost or market. SCE had GHG allowances of $135 million and $41 million at December 31, 2013 and 2012, respectively. GHG emission obligations were $102 million and zero at December 31, 2013 and 2012, respectively and are classified as "Other current liabilities" on the consolidated balance sheets.
Property, Plant and Equipment
Plant additions, including replacements and betterments, are capitalized. SCE capitalizes as part of plant additions direct material and labor and indirect costs such as construction overhead, administrative and general costs, pension and benefits, and property taxes. The CPUC authorizes a rate for each of the indirect costs which are allocated to each project based on either labor or total costs. In addition, allowance for funds used during construction ("AFUDC") is capitalized by SCE for certain projects.
Estimated useful lives (authorized by the CPUC) and weighted-average useful lives of SCE's property, plant and equipment, are as follows:
As a result of the permanent retirement of San Onofre, SCE had reclassified property, plant and equipment, including nuclear fuel to a regulatory asset, see Note 9 for further information.
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $1.31 billion, $1.26 billion and $1.16 billion for 2013, 2012 and 2011, respectively. Depreciation expense stated as a percent of average original cost of depreciable utility plant was, on a composite basis, 4.2%, 4.3% and 4.3% for 2013, 2012 and 2011, respectively. Replaced or retired property costs are charged to the accumulated provision for depreciation.
Nuclear fuel for the Palo Verde Nuclear Power Plant is recorded as utility plant (nuclear fuel in the fabrication and installation phase is recorded as construction in progress) in accordance with CPUC ratemaking procedures. Nuclear fuel is amortized using the units of production method.
AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction and is capitalized during certain plant construction. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset. AFUDC equity represents a method to compensate SCE for the estimated cost of equity used to finance utility plant additions and is recorded as part of construction in progress. AFUDC equity was $72 million, $96 million and $96 million in 2013, 2012 and 2011, respectively. AFUDC debt was $33 million, $40 million and $42 million in 2013, 2012 and 2011, respectively.
Major Maintenance
Major maintenance costs for SCE's power plant facilities and equipment are expensed as incurred.
Asset Retirement Obligations
The fair value of a liability for an asset retirement obligation ("ARO") is recorded in the period in which it is incurred, including a liability for the fair value of a conditional ARO, if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. When an ARO liability is initially recorded, SCE capitalizes the cost by increasing the carrying amount of the related long-lived asset. For each subsequent period, the liability is increased for accretion expense and the capitalized cost is depreciated over the useful life of the related asset.
SCE is in the process of developing a comprehensive decommissioning plan following its decision to permanently retire San Onofre. See Note 9 for further details. The ARO liability related to San Onofre increased by $455 million in the second quarter of 2013 based on an updated decommissioning cost estimate for the retirement of San Onofre Units 2 and 3. The total ARO liability related to San Onofre Units 2 and 3 at December 31, 2013 was $2.68 billion.
The following table summarizes the changes in SCE's ARO liability, including San Onofre and Palo Verde:
An ARO represents the present value of a future obligation. Accretion is an increase in the liability to account for the time value of money resulting from discounting.
AROs related to decommissioning of SCE's nuclear power facilities are based on site-specific studies conducted as part of each Nuclear Decommissioning Cost Triennial Proceeding ("NDCTP"). The initial establishment of a nuclear-related ARO is at fair value. Revisions of an ARO are established for updated site-specific decommissioning cost estimates. SCE adjusts its nuclear decommissioning obligation into a nuclear-related ARO regulatory asset and also records an ARO regulatory liability as a result of timing differences between the recognition of costs and the recovery of costs through the ratemaking process. For further discussion, see "Nuclear Decommissioning" below and Notes 4 and 10.
Impairment of Long-Lived Assets
Impairments of long-lived assets are evaluated based on a review of estimated future cash flows expected to be generated whenever events or changes in circumstances indicate that the carrying amount of such investments or assets may not be recoverable. If the carrying amount of a long-lived asset exceeds expected future cash flows, undiscounted and without interest charges, an impairment loss is recognized in the amount of the excess of fair value over the carrying amount. Fair value is determined via market, cost and income based valuation techniques, as appropriate. SCE's impaired assets are recorded as a regulatory asset if it is deemed probable that such amounts will be recovered from customers.
Leases
SCE enters into power purchase agreements that may contain leases, as discussed under "Power Purchase Agreements" below. SCE has entered into a number of agreements to lease property and equipment in the normal course of business. Minimum lease payments under operating leases are levelized (total minimum lease payments divided by the number of years of the lease) and recorded as rent expense over the terms of the leases. Lease payments in excess of the minimum are recorded as rent expense in the year incurred.
Capital leases are reported as long-term obligations on the consolidated balance sheets in "Other deferred credits and other long-term liabilities." As a rate-regulated enterprise, SCE's capital lease amortization expense and interest expense are reflected in "Purchased power" on the consolidated statements of income.
Nuclear Decommissioning
Decommissioning costs, which are recovered through non-bypassable customer rates over the term of each nuclear facility's operating license, are recorded as a component of depreciation expense, with a corresponding credit to the ARO regulatory liability. Amortization of the ARO asset (included within the unamortized nuclear investment) and accretion of the ARO liability are deferred as increases to the ARO regulatory liability account, resulting in no impact on earnings.
SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts. The cost of removal amounts, in excess of amounts collected for assets not legally required to be removed, are classified as regulatory liabilities.
Due to regulatory recovery of SCE's nuclear decommissioning expense, nuclear decommissioning activities do not affect SCE's earnings. SCE's nuclear decommissioning trust investments primarily consist of debt and equity investments that are classified as available-for-sale. Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on electric utility revenue. Unrealized gains and losses on decommissioning trust funds increase or decrease the trust assets and the related regulatory asset or liability and have no impact on electric utility revenue or decommissioning expense. SCE reviews each security for other-than-temporary impairment on the last day of each month. If the fair value on the last day of two consecutive months is less than the cost for that security, SCE recognizes a loss for the other-than-temporary impairment. If the fair value is greater or less than the cost for that security at the time of sale, SCE recognizes a related realized gain or loss, respectively.
Deferred Financing Costs
Debt premium, discount and issuance expenses incurred in connection with obtaining financing are deferred and amortized on a straight-line basis. Under CPUC ratemaking procedures, SCE's debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt. SCE had unamortized losses on reacquired debt of $222 million and $228 million at December 31, 2013 and 2012, respectively, reflected as long-term "Regulatory assets" in the consolidated balance sheets. Edison International and SCE had unamortized debt issuance costs of $84 million and $79 million at December 31, 2013, respectively, and $73 million and $67 million at December 31, 2012, respectively, reflected in "Other long-term assets" on the consolidated balance sheets. Amortization of deferred financing costs charged to interest expense is as follows:
Revenue Recognition
Revenue is recognized when electricity is delivered and includes amounts for services rendered but unbilled at the end of each reporting period and reflected in "Electric utility revenue" on the consolidated income statements. Rates charged to customers are based on CPUC and FERC-authorized revenue requirements. CPUC rates are implemented subsequent to final approval.
CPUC and FERC rates decouple authorized revenue from the volume of electricity sales. Differences between amounts collected and authorized levels are either collected from or refunded to customers, and therefore, SCE earns revenue equal to amounts authorized.
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.
SCE bills certain sales and use taxes levied by state or local governments to its customers. Included in these sales and use taxes are franchise fees, which SCE pays to various municipalities (based on contracts with these municipalities) in order to operate within the limits of the municipality. SCE bills these franchise fees to its customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SCE's ability to collect from the customer, are accounted for on a gross basis and reflected in electric utility revenue and other operation and maintenance expense. SCE's franchise fees billed to customers and recorded as electric utility revenue were $116 million, $98 million and $101 million in 2013, 2012 and 2011, respectively. When SCE bills and collects taxes from customers, these taxes are remitted to the taxing authorities and are not recognized as electric utility revenue.
Power Purchase Agreements
SCE enters into power purchase agreements in the normal course of business. A power purchase agreement may be considered a variable interest in a variable interest entity. Under this classification, the power purchase agreement is evaluated to determine if SCE is the primary beneficiary in the variable interest entity, in which case, such entity would be consolidated. None of SCE's power purchase agreements resulted in consolidation of a variable interest entity at December 31, 2013 and 2012. See Note 3 for further discussion of power purchase agreements that are considered variable interests.
A power purchase agreement may also contain a lease for accounting purposes. This generally occurs when a power purchase agreement (signed or modified after June 30, 2003) designates a specific power plant in which the buyer purchases substantially all of the output and does not otherwise meet a fixed price per unit of output exception. SCE has a number of power purchase agreements that contain leases. SCE's recognition of lease expense conforms to the ratemaking treatment for SCE's recovery of the cost of electricity and is recorded in purchased power. These agreements are classified as operating leases as electricity is delivered at rates defined in power sales agreements. See Note 12 for further discussion of SCE's power purchase agreements, including agreements that are classified as capital leases for accounting purposes.
A power purchase agreement that does not contain a lease may be classified as a derivative subject to a normal purchase and sale exception, in which case the power purchase agreement is classified as an executory contract and accounted for on an accrual basis. Most of SCE's QF contracts are not required to be recorded on the consolidated balance sheets because they either do not meet the definition of a derivative or meet the normal purchase and sale exception. However, SCE purchases power from certain QFs in which the contract pricing is based on a natural gas index, but the power is not generated with natural gas. These contracts are not eligible for the normal purchase and sale exception and are recorded as a derivative on the consolidated balance sheets at fair value. See Note 6 for further information on derivatives and hedging activities.
Power purchase agreements that do not meet the above classifications are accounted for on an accrual basis.
Derivative Instruments and Hedging Activities
SCE records derivative instruments on its consolidated balance sheets as either assets or liabilities measured at fair value unless otherwise exempted from derivative treatment as normal purchases or sales. The normal purchases and sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Realized gains and losses from SCE's derivative instruments are expected to be recovered from or refunded to customers through regulatory mechanisms and, therefore, SCE's fair value changes have no impact on purchased-
power expenses or earnings. SCE does not use hedge accounting for derivative transactions due to regulatory accounting treatment.
Where SCE's derivative instruments are subject to a master netting agreement and certain criteria are met, SCE presents its derivative assets and liabilities on a net basis on its consolidated balance sheets. In addition, derivative positions are offset against margin and cash collateral deposits. The results of derivative activities are recorded as part of cash flows from operating activities on the consolidated statements of cash flows. See Note 6 for further information on derivative and hedging activities.
Stock-Based Compensation
Stock options, performance shares, deferred stock units and restricted stock units have been granted under Edison International's long-term incentive compensation programs. Generally, Edison International does not issue new common stock for settlement of equity awards. Rather, a third party is used to purchase shares from the market and delivery for settlement of option exercises, performance shares and restricted stock units. Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. Deferred stock units granted to management are settled in cash and represent a liability. Restricted stock units are settled in common stock; however, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.
Stock-based compensation expense is recognized on a straight-line basis over the requisite service period. For awards granted to retirement-eligible participants stock compensation expenses are recognized on a prorated basis over the initial year or over the period between the date of grant and the date the participant first becomes eligible for retirement.
SCE 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 SCE's net assets of $11.9 billion.
Earnings Per Share
Edison International computes earnings per common share ("EPS") using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's participating securities are stock-based compensation awards payable in common shares, including performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares once the awards are vested. EPS attributable to Edison International common shareholders was computed as follows:
In addition to the participating securities discussed above, Edison International also may award stock options which are payable in common shares and are included in the diluted earnings per share calculation. Stock option awards to purchase 3,977,894, 7,492,552 and 5,847,094 shares of common stock for the years ended December 31, 2013, 2012 and 2011, respectively, were outstanding, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares during the respective periods and, therefore, the effect would have been antidilutive.
Income Taxes
Edison International and SCE estimate their income taxes for each jurisdiction in which they operate. This involves estimating current period tax expense along with assessing temporary differences resulting from differing treatment of items (such as depreciation) for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Investment tax credits are deferred and amortized to income tax expense over the lives of the properties or the term of the power purchase agreement of the respective project while production tax credits are recognized in income tax expense in the period in which they are earned.
Interest income, interest expense and penalties associated with income taxes are reflected in "Income tax expense" on the consolidated statements of income.
Edison International's eligible subsidiaries are included in Edison International's consolidated federal income tax and combined state tax returns. Edison International has tax-allocation and payment agreements with certain of its subsidiaries. Pursuant to an income tax-allocation agreement approved by the CPUC, SCE's tax liability is computed as if it filed its federal and state income tax returns on a separate return basis.
New Accounting Guidance
Accounting Guidance Adopted in 2013
Offsetting Assets and Liabilities
In January 2013, the FASB issued accounting standard updates modifying the disclosure requirements about the nature of an entity's right of offsetting recognized assets and liabilities in the statement of financial position under master netting agreements and similar arrangements associated with derivative instruments, repurchase agreements and securities lending transactions. The guidance requires increased disclosure of the gross and net recognized assets and liabilities, collateral positions and descriptions of setoff rights. Edison International and SCE adopted this guidance effective January 1, 2013. The adoption of this standard did not impact the consolidated income statements, balance sheets or cash flows of Edison International or SCE. See Note 6 for further details.
Items Reclassified Out of Accumulated Other Comprehensive Income
In February 2013, the FASB issued an accounting standards update which requires disclosure related to items reclassified out of accumulated other comprehensive income ("AOCI"). The guidance requires companies to present separately, for each component of other comprehensive income, current period reclassifications and the remainder of the current-period other comprehensive income. In addition, for certain current period reclassifications, an entity is required to disclose the effect of the item reclassified out of AOCI on the respective line item(s) of net income. Edison International and SCE adopted this guidance effective January 1, 2013. See Note 14 for further details.
Accounting Guidance Not Yet Adopted
In July 2013, the FASB issued an accounting standards update that will require that an unrecognized tax benefit be presented on the balance sheet as a reduction of a deferred tax asset for a net operating loss ("NOL") or tax credit carryforward under certain circumstances. Edison International and SCE adopted this guidance effective January 1, 2014 and it did not have a material impact on the consolidated financial statements.
Note 2. Property, Plant and Equipment
SCE's property, plant and equipment included in the consolidated balance sheets is composed of the following:
As a result of the permanent retirement of San Onofre, SCE reclassified utility plant and nuclear fuel into a regulatory asset. For further details, see Note 9.
Capitalized Software Costs
SCE capitalizes costs incurred during the application development stage of internal use software projects to property, plant, and equipment. SCE amortizes capitalized software costs ratably over the expected lives of the software, ranging from 5 to 15 years and commencing upon operational use. At December 31, 2013 and 2012, capitalized software costs were $1.6 billion and $1.5 billion and accumulated amortization was $839 million and $651 million, respectively. Amortization expense for capitalized software was $251 million, $217 million and $156 million in 2013, 2012 and 2011, respectively. At December 31, 2013, amortization expense is estimated to be approximately $255 million annually for 2014 through 2018.
Jointly Owned Utility Projects
SCE owns interests in several generating stations and transmission systems for which each participant provides its own financing. SCE's proportionate share of these projects is reflected in the consolidated balance sheets and included in the above table. SCE's proportionate share of expenses for each project is reflected in the consolidated statements of income. A portion of the investments in Palo Verde generating stations is included in regulatory assets on the consolidated balance sheets. For further information see Note 11.
The following is SCE's investment in each project as of December 31, 2013:
In addition to the projects above, SCE has ownership interests in jointly owned power poles with other companies.
Sale of Interests in Four Corners Units 4 and 5
In December 2013, SCE completed the sale of its ownership interest in Units 4 and 5 of the Four Corners Generating Station, a coal-fired electric generating facility in New Mexico, to the operator of the facility, Arizona Public Service Company and received net proceeds of approximately $181 million. Under the sale agreement, SCE remains responsible for its pro-rata share of certain environmental liabilities, including penalties arising from environmental violations arising prior to the sale. The sale of Four Corners resulted in a $166 million benefit to SCE's ratepayers and, therefore, will not affect SCE's earnings.
Note 3. Variable Interest Entities
A VIE is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE. Commercial and operating activities are generally the factors that most significantly impact the economic performance of such VIEs. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
Variable Interest in VIEs that are not Consolidated
Power Purchase Contracts
SCE has power purchase agreements ("PPAs") that are classified as variable interests in VIEs, including tolling agreements through which SCE provides the natural gas to fuel the plants and contracts with qualifying facilities ("QFs") that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. Since payments for capacity are the primary source of income, the most significant economic activity for these VIEs is the operation and maintenance of the power plants.
As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. Under these contracts, SCE recovers the costs incurred through demonstration of compliance with its CPUC-approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 12. As a result, there is no significant potential exposure to loss to SCE from its variable interest in these VIEs. The aggregate contracted capacity dedicated to SCE for these VIE projects was 5,183 MW and 2,198 MW at December 31, 2013 and 2012, respectively, and the amounts that SCE paid to these projects were $715 million and $397 million for the years ended December 31, 2013 and 2012, respectively. These amounts are recoverable in customer rates, subject to reasonableness review.
Unconsolidated Trusts of SCE
SCE Trust I and Trust II were formed in 2012 and 2013, respectively, for the exclusive purpose of issuing the 5.625% and 5.10% trust preference securities, respectively (“trust securities”). The trusts are VIEs. SCE has concluded that it is not the primary beneficiary of these VIEs as it does not have the obligation to absorb the expected losses or the right to receive the expected residual returns of the trusts. SCE Trust I and Trust II issued $475 million and $400 million, respectively, (cumulative, liquidation amount of $25 per share) to the public and $10,000 of common stock each to SCE. The trusts invested the proceeds of these trust securities in Series F and Series G Preference Stock issued by SCE in the principal amount of $475 million and $400 million (cumulative, $2,500 per share liquidation value), respectively, which have substantially the same payment terms as the trust securities.
The Series F and Series G Preference Stock and the corresponding trust securities do not have a maturity date. Upon any redemption of any shares of the Series F or Series G Preference Stock, a corresponding dollar amount of trust securities will be redeemed by the applicable trust (for further information see Note 13). The applicable trust will make distributions at the same rate and on the same dates on the applicable series of trust securities when and if the SCE board of directors declares and makes dividend payments on the Series F or Series G Preference Stock. The applicable trusts will use any dividends it receives on the Series F or Series G Preference Stock to make its corresponding distributions on the applicable series of trust securities. If SCE does not make a dividend payment to either trust, SCE would be prohibited from paying dividends on its
common stock. SCE has fully and unconditionally guaranteed the payment of the trust securities and trust distributions, if and when SCE pays dividends on the Series F and Series G Preference Stock.
The Trust I and Trust II balance sheets as of December 31, 3013, and 2012 consisted of investments of $475 million and $400 million in the Series F and Series G Preference Stock respectively, $475 million and $400 million of trust securities, respectively and $10,000 each of common stock. The trusts' income statements consisted of both dividend income and dividend distributions in the amounts for Trust I of $27 million and $17 million for the years ended December 31, 2013 and 2012, respectively, and $19 million for the year ending December 31, 2013 for Trust II.
Note 4. Fair Value Measurements
Recurring Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or liability considers assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk. As of December 31, 2013 and 2012, nonperformance risk was not material for Edison International and SCE.
Assets and liabilities are categorized into a three-level fair value hierarchy based on valuation inputs used to determine fair value.
Level 1 - The fair value of Edison International and SCE's Level 1 assets and liabilities is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. This level includes exchange-traded equity securities and derivatives, U.S. treasury securities and money market funds.
Level 2 - Edison International and SCE's Level 2 assets and liabilities include fixed income securities, primarily consisting of U.S. government and agency bonds, municipal bonds and corporate bonds, and over-the-counter derivatives. The fair value of fixed income securities is determined using a market approach by obtaining quoted prices for similar assets and liabilities in active markets and inputs that are observable, either directly or indirectly, for substantially the full term of the instrument.
The fair value of SCE's over-the-counter derivative contracts is determined using an income approach. SCE uses standard pricing models to determine the net present value of estimated future cash flows. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. A primary price source that best represents trade activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes, prices from exchanges or comparison to executed trades are used to validate and corroborate the primary price source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity.
Level 3 - The fair value of SCE's Level 3 assets and liabilities is determined using the income approach through various models and techniques that require significant unobservable inputs. This level includes over-the-counter options, tolling arrangements and derivative contracts that trade infrequently such as congestion revenue rights ("CRRs") and long-term power agreements. Edison International Parent and Other does not have any Level 3 assets and liabilities.
Assumptions are made in order to value derivative contracts in which observable inputs are not available. Changes in fair value are based on changes to forward market prices, including extrapolation of short-term observable inputs into forecasted prices for illiquid forward periods. In circumstances where fair value cannot be verified with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. Modeling methodologies, inputs and techniques are reviewed and assessed as markets continue to develop and more pricing information becomes available and the fair value is adjusted when it is concluded that a change in inputs or techniques would result in a new valuation that better reflects the fair value of those derivative contracts.
SCE
The following table sets forth assets and liabilities of SCE that were accounted for at fair value by level within the fair value hierarchy:
Represents the netting of assets and liabilities under master netting agreements and cash collateral across the levels of the fair value hierarchy. Netting among positions classified within the same level is included in that level.
Approximately 70% and 66% of SCE's equity investments were located in the United States at December 31, 2013 and 2012, respectively.
Includes corporate bonds, which were diversified and included collateralized mortgage obligations and other asset backed securities of $47 million and $56 million at December 31, 2013 and 2012, respectively.
Excludes net receivables of $12 million at December 31, 2013 and net payables of $1 million at December 31, 2012, which consist of interest and dividend receivables as well as receivables and payables related to SCE's pending securities sales and purchases.
Edison International
Assets measured at fair value consisted of money market funds of $68 million and $107 million at December 31, 2013 and 2012, respectively, classified as Level 1.
SCE Fair Value of Level 3
The following table sets forth a summary of changes in SCE's fair value of Level 3 net derivative assets and liabilities:
Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.
Edison International and SCE recognize the fair value for transfers in and transfers out of each level at the end of each reporting period. There were no transfers between any levels during 2013 and 2012.
Valuation Techniques Used to Determine Fair Value
The process of determining fair value is the responsibility of SCE's risk management department, which report to SCE's chief financial officer. This department obtains observable and unobservable inputs through broker quotes, exchanges and internal valuation techniques that use both standard and proprietary models to determine fair value. Each reporting period, the risk and finance departments collaborate to determine the appropriate fair value methodologies and classifications for each derivative. Inputs are validated for reasonableness by comparison against prior prices, other broker quotes and volatility fluctuation thresholds. Inputs used and valuations are reviewed period-over-period and compared with market conditions to determine reasonableness.
The following table sets forth SCE's valuation techniques and significant unobservable inputs used to determine fair value for significant Level 3 assets and liabilities:
Level 3 Fair Value Sensitivity
Congestion Revenue Rights
For CRRs, where SCE is the buyer, generally increases (decreases) in forecasted load in isolation would result in increases (decreases) to the fair value. In general, an increase (decrease) in electricity and gas prices at illiquid locations tends to result in increases (decreases) to fair value; however, changes in electricity and gas prices in opposite directions may have varying results on fair value.
Tolling Arrangements
The fair values of SCE's tolling arrangements contain intrinsic value and time value. Intrinsic value is the difference between the market price and strike price of the underlying commodity. Time value is made up of several components, including volatility, time to expiration, and interest rates. The option model for tolling arrangements reflects plant specific information such as operating and start-up costs.
For tolling arrangements where SCE is the buyer, increases in volatility of the underlying commodity prices would result in increases to fair value as it represents greater price movement risk. As power and gas prices increase, the fair value of tolling arrangements tends to increase. The valuation of tolling arrangements is also impacted by the correlation between gas and power prices. As the correlation increases, the fair value of tolling arrangements tends to decline.
Nuclear Decommissioning Trusts
SCE's investment policies and CPUC requirements place limitations on the types and investment grade ratings of the securities that may be held by the nuclear decommissioning trust funds. These policies restrict the trust funds from holding alternative investments and limit the trust funds' exposures to investments in highly illiquid markets. With respect to equity and fixed income securities, the trustee obtains prices from third-party pricing services which SCE is able to independently corroborate as described below. A primary price source is identified by the trustee based on asset type, class or issue for each security. The trustee monitors prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the trustee or SCE's investment managers challenge an assigned price and determine that another price source is considered to be preferable. Parameters and predetermined tolerance thresholds are established by asset class based on past experience and an understanding of valuation process techniques. The trustee “scrubs” prices against defined parameters tolerances and performs research and resolves variances beyond the set parameters. SCE reviewed the process/procedures of both the pricing services and the trustee to gain an understanding of the inputs/assumptions and valuation techniques used to price each asset type/class and to reach a conclusion that their pricing controls are satisfactory. This consisted of SCE's review of their written detailed process/procedures and service organization control reports, as well as follow-up conversations based on our written questions. This assists SCE in determining if the valuations represent exit price fair value and that investments are appropriately classified in the fair value hierarchy. Additionally, SCE corroborates the fair values of securities by comparison to other market-based price sources obtained by SCE's investment managers. Differences outside established thresholds are followed-up with the trustee and resolved. The results of this process have demonstrated that vendor and trustee pricing controls are satisfactory. For each reporting period, SCE reviews the trustee determined fair value hierarchy and overrides the trustee level classification when appropriate. Due to its regulatory treatment, SCE's fair value transactions are recovered in rates.
Fair Value of Long-Term Debt Recorded at Carrying Value
The carrying value and fair value of Edison International and SCE's long-term debt:
The fair value of Edison International and SCE's short-term and long-term debt is classified as Level 2 and is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit information.
The carrying value of Edison International and SCE's trade receivables and payables, other investments, and short-term debt approximates fair value.
Note 5. Debt and Credit Agreements
Long-Term Debt
The following table summarizes long-term debt (rates and terms are as of December 31, 2013) of Edison International and SCE:
Edison International and SCE long-term debt maturities over the next five years are the following:
Liens and Security Interests
Almost all of SCE's properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage bonds as collateral for borrowed funds obtained from pollution-control bonds issued by government agencies. SCE has a debt covenant that requires a debt to total capitalization ratio be met. At December 31, 2013, SCE was in compliance with this debt covenant.
Credit Agreements and Short-Term Debt
The following table summarizes the status of the credit facilities at December 31, 2013:
In 2013, SCE and Edison International Parent amended their credit facilities to extend the maturity dates to July 2018 for $2.75 billion and $1.25 billion, respectively. The credit facility for SCE is generally used to support commercial paper and letters of credit issued for procurement-related collateral requirements, balancing account undercollections and for general corporate purposes, including working capital requirements to support operations and capital expenditures. Borrowings under Edison International Parent's credit facility are used for general corporate purposes.
At December 31, 2013, SCE's outstanding commercial paper was $175 million at a weighted-average interest rate of 0.24%. The commercial paper was supported by the $2.75 billion multi-year revolving credit facility. At December 31, 2013, letters of credit issued under SCE's credit facility aggregated $116 million and are scheduled to expire in twelve months or less. At December 31, 2012, the outstanding commercial paper was $175 million at a weighted-average interest rate of 0.37%.
At December 31, 2013, Edison International Parent's outstanding commercial paper was $34 million at a weighted-average interest rate of 0.55%. This commercial paper was supported by the $1.25 billion multi-year revolving credit facility. At December 31, 2012, Edison International Parent had no outstanding short-term debt.
Financing Subsequent to December 31, 2013
In January 2014, SCE issued $300 million of floating rate first and refunding mortgage bonds due in 2015. The proceeds from this bond were used for working capital to fund the ERRA balancing account undercollections.
Note 6. Derivative Instruments and Hedging Activities
Derivative financial instruments are used to manage exposure to commodity price risk. These risks are managed in part by entering into forward commodity transactions, including options, swaps and futures. To mitigate credit risk from counterparties in the event of nonperformance, master netting agreements are used whenever possible and counterparties may be required to pledge collateral depending on the creditworthiness of each counterparty and the risk associated with the transaction.
Commodity Price Risk
Commodity price risk represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's electricity price exposure arises from energy purchased from and sold to wholesale markets as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities and power purchase agreements. SCE's natural gas price exposure arises from natural gas purchased for the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and power purchase agreements in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.
Credit and Default Risk
Credit and default risk represents the potential impact that can be caused if a counterparty were to default on its contractual obligations and SCE would be exposed to spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to the sales of excess power and realized gains on derivative instruments.
Certain power contracts contain master netting agreements or similar agreements, which generally allows counterparties subject to the agreement to setoff amounts when certain criteria are met, such as in the event of default. The objective of netting is to reduce credit exposure. Additionally, to reduce SCE's risk exposures counterparties may be required to pledge collateral depending on the credit worthiness of each counterparty and the risk associated with the transaction.
Certain power contracts contain a provision that requires SCE to maintain an investment grade rating from each of the major credit rating agencies, referred to as a credit-risk-related contingent feature. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The net fair value of all derivative liabilities with these credit-risk-related contingent features was $49 million and $6 million as of December 31, 2013 and 2012, respectively, for which SCE has posted no collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2013, SCE would be required to post collateral in the amount of $5 million, excluding the impact of unpaid closed positions as their settlement is not impacted by the credit-risk-related contingent features.
Fair Value of Derivative Instruments
SCE presents its derivative assets and liabilities on a net basis on its consolidated balance sheets when subject to master netting agreements or similar agreements. Derivative positions are offset against margin and cash collateral deposits. In addition, SCE has provided collateral in the form of letters of credit. Collateral requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments and other factors. The following table summarizes the gross and net fair values of SCE's commodity derivative instruments:
In addition, at December 31, 2013 and 2012, SCE had posted $19 million and $8 million, respectively, of collateral that is not offset against derivative liabilities and is reflected in "Other current assets" on the consolidated balance sheets.
Income Statement Impact of Derivative Instruments
SCE recognizes realized gains and losses on derivative instruments as purchased power expense and expects that such gains or losses will be part of the purchase power costs recovered from customers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from customers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.
The following table summarizes the components of SCE's economic hedging activity:
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for SCE hedging activities:
Note 7. Income Taxes
Current and Deferred Taxes
Edison International's sources of income (loss) before income taxes are:
The components of income tax expense (benefit) by location of taxing jurisdiction are:
The components of net accumulated deferred income tax liability are:
Net Operating Loss and Tax Credit Carryforwards
As of December 31, 2013, Edison International has $1.9 billion of net operating loss carryforwards (tax effected) of which $36 million expire between 2015 and 2025, and the remainder expires in 2031 and 2032. Edison International also has $399 million of federal tax credit carryforwards of which $376 million expire between 2029 and 2033 and the remainder has no expiration date.
As of December 31, 2013, SCE has $371 million of net operating loss carryforwards (tax effected) of which $18 million expire between 2015 and 2017, and the remainder expire in 2031 and 2033. SCE also has $55 million of federal tax credit carryforwards of which $41 million expire between 2030 and 2033 and the remainder has no expiration date.
Edison International has recorded deferred tax assets related to net operating losses and tax credit carryforwards that pertain to Edison International's consolidated or combined federal and state tax returns, including approximately $1.6 billion related to EME. Edison International continues to consolidate EME for federal and certain combined state tax returns. EME’s Plan of Reorganization, filed in December 2013 ("December Plan of Reorganization"), provides for the transfer of Edison International’s ownership interest to the creditors which would result in a tax deconsolidation of EME. Under federal and state tax regulations, the tax deconsolidation of EME will reduce the amounts of net operating loss and tax credits carryforwards that Edison International would be eligible to use in future periods. As a result of EME's December Plan of Reorganization that would result in a tax deconsolidation of EME, Edison International has recorded a valuation allowance of $1.380 billion based on the estimated amount of such benefits as calculated under the applicable federal and state tax regulations as of December 31, 2013. The deferred income tax benefits recognized by Edison International less the valuation allowance for amounts that would no longer be available upon tax deconsolidation of EME was approximately $220 million. See Note 16 for subsequent events related to the EME bankruptcy.
As of December 31, 2013, Edison International has a tax basis of $544 million (tax-effected) in the stock of EME. To the extent that Edison International's tax basis in EME stock is positive upon tax deconsolidation, Edison International may be entitled to claim a tax deduction equal to the amount of its tax basis. A change in Edison International’s tax basis in the stock of EME can result from a number of items, including, but not limited to, utilization of net operating loss carryforwards and tax payments. Edison International has not recorded a deferred tax asset at December 31, 2013 related to potential tax benefits from a tax deduction related to its tax basis in EME.
Effective Tax Rate
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision:
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 2009 - 2011 incremental repairs deductions taken after the 2009 tax accounting method change resulted in SCE recognizing a $231 million earnings benefit in 2012.
Includes incremental repair benefit recorded in 2013 and 2012. See discussion of repair deductions below.
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.
Accounting for Uncertainty in Income Taxes
Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained upon examination. The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.
Unrecognized Tax Benefits
The following table provides a reconciliation of unrecognized tax benefits for continuing and discontinued operations:
Unrecognized tax benefits of EME have been deconsolidated as a result of the bankruptcy filing by EME, except for tax liabilities that Edison International is jointly liable with EME under the Internal Revenue Code and applicable state statues. See Note 16 for further information. During 2013, Edison International increased the amount of unrecognized tax benefits related to the taxable gain on sale of EME’s international assets by $50 million as a result of unfavorable developments during the fourth quarter of 2013.
As of December 31, 2013 and 2012, if recognized, $653 million and $622 million respectively, of the unrecognized tax benefits would impact Edison International's effective tax rate; and $374 million and $388 million, respectively, of the unrecognized tax benefits would impact SCE's effective tax rate.
Tax Disputes
The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included proposed adjustments for the following two items:
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A proposed adjustment increasing the taxable gain on the 2004 sale of EME's international assets, which if sustained, would result in a federal tax payment of approximately $206 million, including interest and penalties through December 31, 2013, see Note 16.
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A proposed adjustment to disallow a component of SCE's repair allowance deduction, which if sustained, would result in a federal tax payment of approximately $100 million, including interest through December 31, 2013.
Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011. During the fourth quarter of 2013, the Internal Revenue Service advised Edison International that it intends to issue technical advice adverse to Edison International supporting the proposed adjustment by IRS examination increasing the taxable gain on the 2004 sale of EME’s international assets (the technical advice adverse to Edison International was received in February 2014). The technical advice did not address penalties. Edison International is continuing to protest the asserted penalty with IRS Appeals. Edison International anticipates that the IRS will issue a deficiency notice for the tax, interest and possibly penalties related to this issue at the conclusion of the IRS appeals process. After the receipt of such deficiency notice, Edison International will have 90 days to file a petition in United States Tax Court. If a petition is not timely filed, Edison International anticipates after the expiration of the 90-day period, the IRS will assess the underpayment of tax, interest and penalties, if any, and demand payment.
Tax Years 2007 - 2009
The IRS examination phase of tax years 2007 through 2009 was completed during the first quarter of 2013. Edison International received a Revenue Agent Report from the IRS on February 28, 2013 which included a proposed adjustment to disallow a component of SCE's repair allowance deduction (similar to the 2003 - 2006 tax years). The proposed adjustment to disallow a component of SCE's repair allowance deduction, if sustained, would result in a federal tax payment of approximately $74 million, including interest through December 31, 2013. Edison International disagrees with the proposed adjustment and filed a protest with the IRS in April 2013.
Accrued Interest and Penalties
The total amount of accrued interest and penalties related to income tax liabilities for continuing and discontinued operations are:
The net after-tax interest and penalties recognized in income tax expense are:
Note 8. Compensation and Benefit Plans
Employee Savings Plan
The 401(k) defined contribution savings plan is designed to supplement employees' retirement income. The following employer contributions were made for continuing operations:
Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
Noncontributory defined benefit pension plans (some with cash balance features) cover most employees meeting minimum service requirements. SCE recognizes pension expense for its nonexecutive plan as calculated by the actuarial method used for ratemaking. The expected contributions (all by the employer) for Edison International and SCE are approximately $200 million and $173 million, respectively, for the year ending December 31, 2014. Annual contributions made to most of SCE's pension plans are anticipated to be recovered through CPUC-approved regulatory mechanisms. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.
The funded position of Edison International's pension is sensitive to changes in market conditions. Changes in overall interest rate levels significantly affect the company's liabilities, while assets held in the various trusts established to fund Edison International's long-term pension are affected by movements in the equity and bond markets. Due to SCE's regulatory recovery treatment, the unfunded status is offset by a regulatory asset.
Non-Executive Retirement Plan Liabilities of EME
The employees of EME and its subsidiaries participate in a number of qualified retirement plans that are sponsored by either Edison International or SCE. Under these benefit plans EME is obligated to make contributions to fund the costs of the plans. Edison International Parent has not guaranteed the obligations of EME, however, under the Internal Revenue Code and applicable state statutes, Edison International Parent is jointly liable for qualified retirement plans. As a result of the EME Chapter 11 bankruptcy filing, Edison International has a long-term liability of $35 million and $80 million at December 31, 2013 and 2012, respectively, related to employees of EME participation in these plans which is reflected in the table below. For further information on the EME Chapter 11 bankruptcy filing, refer to Note 16.
Transfer of Certain Pension Benefits to Edison International
In 2012, Edison International agreed to assume the liabilities for active employees of SCE and EME under the specified plans related to pension benefits. During bankruptcy, EME is obligated to fund costs incurred on an after tax basis each pay period while SCE is obligated to reimburse Edison International upon settlement of liabilities on an after tax basis.
Information on pension plan assets and benefit obligations for continuing and discontinued operations is shown below.
The retirement plan liabilities of EME have been deconsolidated as a result of the bankruptcy filing by EME, except for qualified pension plans that Edison International is jointly liable with EME under the Internal Revenue Code. See Note 16 for further information.
Pension expense components for continuing operations are:
Includes the amount of net loss reclassified from other comprehensive loss. The amount reclassified for Edison International was $2 million for the year ended December 31, 2013.
Includes the amount of net loss reclassified from other comprehensive loss. The amount reclassified for Edison International and SCE was $11 million and $7 million for the year ended December 31, 2013, respectively.
Under GAAP, a settlement is recorded when lump-sum payments exceed estimated annual service and interest costs. Lump-sum payments to employees retiring in 2013 from the SCE Retirement Plan (primarily due to workforce reductions described below) exceeded the estimated service and interest costs for the year. A settlement requires re-measurement of both the plan pension obligations and plan assets as of the date of the settlement. The re-measurement of the SCE Retirement Plan during 2013 resulted in total actuarial gains of $563 million, including $558 million for SCE. The actuarial gains are primarily due to an increase in the discount rate (from 3.75% at December 31, 2012 to 4.25% as of May 31, 2013, 4.50% as of August 31, 2013 and 4.75% as of December 31, 2013) due to higher interest rates and performance of the plan assets.
After re-measurement, GAAP requires an acceleration of a portion of unrecognized net losses attributable to such lump-sum payments as additional pension expense as reflected in the above table. The additional pension expense related to SCE did not impact net income as such amounts are probable of recovery through future rates.
The projected benefit obligations exceeded the fair value of the SCE Retirement Plan assets by $478 million, including $449 million for SCE, at December 31, 2013 compared to $1.11 billion, including $1.07 billion for SCE, at December 31, 2012.
Other changes in pension plan assets and benefit obligations recognized in other comprehensive income for continuing operations:
In accordance with authoritative guidance on rate-regulated enterprises, SCE records regulatory assets and liabilities instead of charges and credits to other comprehensive income (loss) for the portion of SCE's postretirement benefit plans that are recoverable in utility rates. The estimated pension amounts that will be amortized to expense in 2014 for continuing operations are as follows:
The amount of net loss expected to be reclassified from other comprehensive loss for Edison International's continuing operations and SCE is $6 million and $4 million, respectively.
Edison International and SCE used the following weighted-average assumptions to determine pension expense for continuing operations:
The following benefit payments, which reflect expected future service, are expected to be paid:
Postretirement Benefits Other Than Pensions ("PBOP(s)")
Most employees retiring at or after age 55 with at least 10 years of service may be eligible for postretirement medical, dental, vision and life insurance benefits. Eligibility for a company contribution toward the cost of these benefits in retirement depends on a number of factors, including the employee's years of service, hire date, and retirement date. Under the terms of the Edison International Health and Welfare Plan (“PBOP Plan”) each participating employer (Edison International or its participating subsidiaries) is responsible for the costs and expenses of all PBOP benefits with respect to its employees and former employees. A participating employer may terminate the PBOP benefits with respect to its employees and former employees, as may SCE (as Plan sponsor), and, accordingly, the participants' PBOP benefits are not vested benefits.
The expected contributions (all by the employer) for PBOP benefits for SCE are $14 million for the year ended December 31, 2014. Annual contributions made to SCE plans are anticipated to be recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the total annual expense for these plans.
SCE has established three voluntary employee beneficiary associations trusts (“VEBA Trusts”) that can only be used to pay for retiree health care benefits of SCE. Once funded into the VEBA Trusts, neither SCE nor Edison International can subsequently terminate benefits and recover remaining amounts in the VEBA Trusts. Participants of the PBOP Plan do not have a beneficial interest in the VEBA Trusts. The VEBA Trust assets are sensitive to changes in market conditions. Changes in overall interest rate levels significantly affect the company's liabilities, while assets held in the various trusts established to fund Edison International's other postretirement benefits are affected by movements in the equity and bond markets. Due to SCE's regulatory recovery treatment, the unfunded status is offset by a regulatory asset.
Information on PBOP Plan assets and benefit obligations for continuing and discontinued operations is shown below:
The postretirement plan liabilities of EME have been deconsolidated as a result of the bankruptcy filing by EME. EME Homer City, a subsidiary of EME terminated the benefits of its employees in the PBOP Plan during 2012. In January 2014, EME settled and the Bankruptcy Court approved the settlement of all the EME Homer City employee claims to the EME Homer City PBOP Plan. EME has requested approval of the Bankruptcy Court to terminate the benefits of its employees and employees of its subsidiaries in the PBOP Plan upon confirmation of their Plan of Reorganization. Participation in the PBOP Plan by employees of EME and its subsidiaries
(other than Homer City) has been permitted under EME's shared services agreement approved by the Bankruptcy Court subject to funding of paid claims. Edison International is not obligated to continue to provide benefits to EME employees under the PBOP Plan, nor can the VEBA Trusts be used to pay for benefits of EME participants. See Note 16 for further information.
PBOP expense components for continuing operations are:
Due to the reduction in workforce, SCE has incurred costs for extended retiree health care coverage.
In accordance with authoritative guidance on rate-regulated enterprises, SCE records regulatory assets and liabilities instead of charges and credits to other comprehensive income (loss) for the portion of SCE's postretirement benefit plans that are recoverable in utility rates. The estimated PBOP amounts that will be amortized to expense in 2014 for continuing operations are as follows:
Edison International and SCE used the following weighted-average assumptions to determine PBOP expense for continuing operations:
A one-percentage-point change in assumed health care cost trend rate would have the following effects on continuing operations:
The following benefit payments are expected to be paid:
Plan Assets
Description of Pension and Postretirement Benefits Other than Pensions Investment Strategies
The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination of asset classes, and may have active and passive investment strategies within asset classes. Target allocations for 2013 and 2012 pension plan assets are 30% for U.S. equities, 16% for non-U.S. equities, 35% for fixed income, 15% for opportunistic and/or alternative investments and 4% for other investments. Target allocations for 2013 and 2012 PBOP plan assets are 41% for U.S. equities, 17% for non-U.S. equities, 34% for fixed income, 7% for opportunistic and/or alternative investments, and 1% for other investments. Edison International employs multiple investment management firms. Investment managers within each asset class cover a range of investment styles and approaches. Risk is managed through diversification among multiple asset classes, managers, styles and securities. Plan, asset class and individual manager performance is measured against targets. Edison International also monitors the stability of its investment managers' organizations.
Allowable investment types include:
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United States Equities: Common and preferred stocks of large, medium, and small companies which are predominantly United States-based.
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Non-United States Equities: Equity securities issued by companies domiciled outside the United States and in depository receipts which represent ownership of securities of non-United States companies.
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Fixed Income: Fixed income securities issued or guaranteed by the United States government, non-United States governments, government agencies and instrumentalities including municipal bonds, mortgage backed securities and corporate debt obligations. A portion of the fixed income positions may be held in debt securities that are below investment grade.
Opportunistic, Alternative and Other Investments:
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Opportunistic: Investments in short to intermediate term market opportunities. Investments may have fixed income and/or equity characteristics and may be either liquid or illiquid.
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Alternative: Limited partnerships that invest in non-publicly traded entities.
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Other: Investments diversified among multiple asset classes such as global equity, fixed income currency and commodities markets. Investments are made in liquid instruments within and across markets. The investment returns are expected to approximate the plans' expected investment returns.
Asset class portfolio weights are permitted to range within plus or minus 3%. Where approved by the fiduciary investment committee, futures contracts are used for portfolio rebalancing and to reallocate portfolio cash positions. Where authorized, a few of the plans' investment managers employ limited use of derivatives, including futures contracts, options, options on futures and interest rate swaps in place of direct investment in securities to gain efficient exposure to markets. Derivatives are not used to leverage the plans or any portfolios.
Determination of the Expected Long-Term Rate of Return on Assets
The overall expected long-term rate of return on assets assumption is based on the long-term target asset allocation for plan assets and capital markets return forecasts for asset classes employed. A portion of the PBOP trust asset returns are subject to taxation, so the expected long-term rate of return for these assets is determined on an after-tax basis.
Capital Markets Return Forecasts
SCE's capital markets return forecast methodologies primarily use a combination of historical market data, current market conditions, proprietary forecasting expertise, complex models to develop asset class return forecasts and a building block approach. The forecasts are developed using variables such as real risk-free interest, inflation, and asset class specific risk premiums. For equities, the risk premium is based on an assumed average equity risk premium of 5% over cash. The forecasted return on private equity and opportunistic investments are estimated at a 2% premium above public equity, reflecting a premium for higher volatility and lower liquidity. For fixed income, the risk premium is based off of a comprehensive modeling of credit spreads.
Fair Value of Plan Assets
The PBOP Plan and the Southern California Edison Company Retirement Plan Trust (Master Trust) assets include investments in equity securities, U.S. treasury securities, other fixed-income securities, common/collective funds, mutual funds, other investment entities, foreign exchange and interest rate contracts, and partnership/joint ventures. Equity securities, U.S. treasury securities, mutual and money market funds are classified as Level 1 as fair value is determined by observable, unadjusted quoted market prices in active or highly liquid and transparent markets. Common/collective funds are valued at the net asset value ("NAV") of shares held. Although common/collective funds are determined by observable prices, they are classified as Level 2 because they trade in markets that are less active and transparent. The fair value of the underlying investments in equity mutual funds and equity common/collective funds are based upon stock-exchange prices. The fair value of the underlying investments in fixed-income common/collective funds, fixed-income mutual funds and other fixed income securities including municipal bonds are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information. Foreign exchange and interest rate contracts are classified as Level 2 because the values are based on observable prices but are not traded on an exchange. Futures contracts trade on an exchange and therefore are classified as Level 1. The partnerships classified as Level 2 can be readily redeemed at NAV and the underlying investments are liquid, publicly traded fixed-income securities which have observable prices. The remaining partnerships/joint ventures are classified as Level 3 because fair value is determined primarily based upon management estimates of future cash flows. Other investment entities are valued similarly to common collective funds and are therefore classified as Level 2. The Level 1 registered investment companies are either mutual or money market funds. The remaining funds in this category are readily redeemable at NAV and classified as Level 2 and are discussed further at footnote 7 to the pension plan master trust investments table below.
Edison International reviews the process/procedures of both the pricing services and the trustee to gain an understanding of the inputs/assumptions and valuation techniques used to price each asset type/class. The trustee and Edison International's validation procedures for pension and PBOP equity and fixed income securities are the same as the nuclear decommissioning trusts. For further discussion see Note 4. The values of Level 1 mutual and money market funds are publicly quoted. The trustees obtain the values of common/collective and other investment funds from the fund managers. The values of partnerships are based on partnership valuation statements updated for cash flows. SCE's investment managers corroborate the trustee fair values.
Pension Plan
The following table sets forth the Master Trust investments for Edison International and SCE that were accounted for at fair value as of December 31, 2013 by asset class and level within the fair value hierarchy:
The following table sets forth the Master Trust investments that were accounted for at fair value as of December 31, 2012 by asset class and level within the fair value hierarchy:
Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relates to the Federal National Mortgage Association and the Federal Home Loan Mortgage Corporation.
Corporate stocks are diversified. For 2013 and 2012, respectively, performance is primarily benchmarked against the Russell Indexes (51% and 60%) and Morgan Stanley Capital International (MSCI) index (49% and 40%).
Corporate bonds are diversified. At December 31, 2013 and 2012, respectively, this category includes $78 million and $65 million for collateralized mortgage obligations and other asset backed securities of which $15 million and $7 million are below investment grade.
At December 31, 2013 and 2012, respectively, the common/collective assets were invested in equity index funds that seek to track performance of the Standard and Poor's (S&P 500) Index (27% and 29%), Russell 1000 indexes (28% and 28%) and the MSCI Europe, Australasia and Far East (EAFE) Index (15% and 11%). A non-index U.S. equity fund representing 23% and 25% of this category for 2013 and 2012, respectively, is actively managed. Another fund representing 6% and 6% of this category for 2013 and 2012, respectively, is a global asset allocation fund.
Partnerships/joint venture Level 2 investments consist primarily of a partnership which invests in publicly traded fixed income securities, primarily from the banking and finance industry and U.S. government agencies. At December 31, 2013 and 2012, respectively, approximately 64% and 56% of the Level 3 partnerships are invested in (1) asset backed securities, including distressed mortgages and (2) commercial and residential loans and debt and equity of banks. The remaining Level 3 partnerships are invested in small private equity and venture capital funds. Investment strategies for these funds include branded consumer products, early stage technology, California geographic focus, and diversified US and non-US fund-of-funds.
Other investment entities were primarily invested in (1) emerging market equity securities, (2) a hedge fund that invests through liquid instruments in a global diversified portfolio of equity, fixed income, interest rate, foreign currency and commodities markets, and (3) domestic mortgage backed securities.
Level 1 of registered investment companies primarily consisted of a global equity mutual fund which seeks to outperform the MSCI World Total Return Index. Level 2 primarily consisted of a short-term bond fund.
At December 31, 2013 and 2012, approximately 67% and 66%, respectively, of the publicly traded equity investments, including equities in the common/collective funds, were located in the United States.
The following table sets forth a summary of changes in the fair value of Edison International's and SCE's Level 3 investments:
Postretirement Benefits Other than Pensions
The following table sets forth the VEBA Trust assets for SCE that were accounted for at fair value as of December 31, 2013 by asset class and level within the fair value hierarchy:
The following table sets forth the VEBA Trust assets for SCE that were accounted for at fair value as of December 31, 2012 by asset class and level within the fair value hierarchy:
At December 31, 2013 and 2012, respectively, 60% and 60% of the common/collective assets are invested in a large cap index fund which seeks to track performance of the Russell 1000 index. 23% and 23% of the assets in this category are in index funds which seek to track performance in the MSCI Europe, Australasia and Far East (EAFE) Index. 6% and 6% of this category are invested in a privately managed bond fund and 7% and 6% in a fund which invests in equity securities the fund manager believes are undervalued.
Corporate stock performance is primarily benchmarked against the Russell Indexes (50% and 50%) and the MSCI All Country World (ACWI) index (50% and 50%) for 2013 and 2012, respectively.
Corporate notes and bonds are diversified and include approximately $29 million and $20 million for commercial collateralized mortgage obligations and other asset backed securities at December 31, 2013 and 2012, respectively.
At December 31, 2013 and 2012, respectively, 78% and 82% of the Level 3 partnerships category is invested in (1) asset backed securities including distressed mortgages, (2) distressed companies and (3) commercial and residential loans and debt and equity of banks.
Level 1 U.S. government and agency securities are U.S. treasury bonds and notes. Level 2 primarily relates to the Federal Home Loan Mortgage Corporation and the Federal National Mortgage Association.
Level 1 registered investment companies consist of an investment grade corporate bond mutual fund and a money market fund.
Other includes $76 million and $73 million of municipal securities at December 31, 2013 and 2012, respectively.
At December 31, 2013 and 2012, approximately 65% and 66%, respectively, of the publicly traded equity investments, including equities in the common/collective funds, were located in the United States.
The following table sets forth a summary of changes in the fair value of PBOP Level 3 investments:
Stock-Based Compensation
Edison International maintains a shareholder approved incentive plan (the 2007 Performance Incentive Plan) that includes stock-based compensation. The maximum number of shares of Edison International's common stock authorized to be issued or transferred pursuant to awards under the 2007 Performance Incentive Plan, as amended, is 49.5 million shares, plus the number of any shares subject to awards issued under Edison International's prior plans and outstanding as of April 26, 2007, which expire, cancel or terminate without being exercised or shares being issued ("carry-over shares"). As of December 31, 2013, Edison International had approximately 23 million shares remaining for future issuance under its stock-based compensation plans.
The following table summarizes total expense and tax benefits (expense) associated with stock based compensation:
Reflected in "Operation and maintenance" on Edison International's and SCE's consolidated statements of income.
2 Reflected in "Settlements of stock-based compensation, net" in the financing section of Edison International's and SCE's consolidated statements of cash flows.
Stock Options
Under various plans, Edison International has granted stock options at exercise prices equal to the average of the high and low price and, beginning in 2007, at the closing price at the grant date. Edison International may grant stock options and other awards related to or with a value derived from its common stock to directors and certain employees. Options generally expire 10 years after the grant date and vest over a period of four years of continuous service, with expense recognized evenly over the requisite service period, except for awards granted to retirement-eligible participants, as discussed in "Stock-Based Compensation" in Note 1. Additionally, Edison International will substitute cash awards to the extent necessary to pay tax withholding or any government levies.
The fair value for each option granted was determined as of the grant date using the Black-Scholes option-pricing model. The Black-Scholes option-pricing model requires various assumptions noted in the following table:
The expected term represents the period of time for which the options are expected to be outstanding and is primarily based on historical exercise and post-vesting cancellation experience and stock price history. The risk-free interest rate for periods within the contractual life of the option is based on a zero coupon U.S. Treasury STRIPS (separate trading of registered interest and principal of securities) whose maturity equals the option's expected term on the measurement date. Expected volatility is based on the historical volatility of Edison International's common stock for the length of the option's expected term for 2013. The volatility period used was 74 months, 83 months and 84 months at December 31, 2013, 2012 and 2011, respectively.
The following is a summary of the status of Edison International's stock options:
At December 31, 2013, total unrecognized compensation cost related to stock options and the weighted-average period the cost is expected to be recognized are as follows:
Supplemental Data on Stock Options
Performance Shares
A target number of contingent performance shares were awarded to executives in March 2013, 2012 and 2011 and vest at the end of a three year period for each grant. The vesting of the grants is dependent upon market and financial performance conditions and service conditions as defined in the grants for each of the years. The number of performance shares earned from each year's grants could range from zero to twice the target number (plus additional units credited as dividend equivalents). Performance shares earned are settled half in cash and half in common stock; however, Edison International has discretion under certain of the awards to pay the half subject to cash settlement in common stock. The portion of performance shares that can be settled in cash is classified as a share-based liability award. The fair value of these shares is remeasured at each reporting period and the related compensation expense is adjusted. Compensation expense related to these shares is based on the grant-date fair value, which for each share is determined as the closing price of Edison International common stock on the grant date; however, with respect to the portion of the performance shares payable in common stock that is subject to the financial performance condition described above, the number of performance shares expected to be earned is subject to revision and update at each reporting period, with a related adjustment of compensation expense. Performance shares expense is recognized ratably over the requisite service period based on the fair values determined (subject to the adjustments discussed above), except for awards granted to retirement-eligible participants.
The fair value of market condition performance shares is determined using a Monte Carlo simulation valuation model.
The following is a summary of the status of Edison International's nonvested performance shares:
Relates to performance shares that will be paid in 2014 as performance targets were met at December 31, 2013.
Restricted Stock Units
Restricted stock units were awarded to Edison International's and SCE's executives in March 2013, 2012 and 2011 and vest and become payable in January 2016, 2015 and 2014, respectively. Each restricted stock unit awarded includes a dividend equivalent feature and is a contractual right to receive one share of Edison International common stock, if vesting requirements are satisfied. The vesting of Edison International's restricted stock units is dependent upon continuous service through the end of the three-calendar-year-plus-two-days vesting period.
The following is a summary of the status of Edison International's nonvested restricted stock units:
The fair value for each restricted stock unit awarded is determined as the closing price of Edison International common stock on the grant date.
Workforce Reductions
In 2012, SCE commenced multiple efforts to reduce its workforce in order to reflect SCE's strategic direction to optimize its cost structure, moderate customer rate increases and align its cost structure with its peers. In addition, in June 2013, SCE announced plans to permanently retire San Onofre, which resulted in additional workforce reductions. See Note 9 for further information. Through December 31, 2013, SCE's share of estimated cash severance for these efforts totaled $213 million. The following table provides a summary of changes in the accrued severance liability associated with these reductions:
The liability presented in the table above is reflected in "Other current liabilities" on the consolidated balance sheets. The severance costs are included in "Operation and maintenance" on the consolidated income statements.
Note 9. 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.
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:
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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.
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At May 31, 2013, SCE's net investment associated with San Onofre was $2.1 billion, including the net book value of remaining property, plant and equipment, construction work-in-progress, nuclear fuel inventory and materials and supplies.
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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.
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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. 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.
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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:
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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.
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Recorded an impairment charge of $575 million ($365 million after tax) in the second quarter of 2013.
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.
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.
Note 10. Other Investments
Nuclear Decommissioning Trusts
Future decommissioning costs of removal of SCE's nuclear assets are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $23 million per year through SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC.
The following table sets forth amortized cost and fair value of the trust investments:
Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $5.6 billion, $2.1 billion and $2.8 billion for the years ended December 31, 2013, 2012 and 2011, respectively. Unrealized holding gains, net of losses, were $1.7 billion and $1.6 billion at December 31, 2013 and 2012, respectively.
The following table sets forth a summary of changes in the fair value of the trusts:
Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.
Note 11. Regulatory Assets and Liabilities
Included in SCE's regulatory assets and liabilities are regulatory balancing accounts. CPUC authorized balancing account mechanisms require SCE to refund or recover any differences between forecasted and actual costs. The CPUC has authorized balancing accounts for specified costs or programs such as fuel, purchased-power, demand-side management programs, nuclear decommissioning and public purpose programs. Certain of these balancing accounts include a return on rate base of 7.90% in 2013 and 8.74% in 2012. The CPUC also authorizes the use of a balancing account to recover from or refund to customers differences in revenue resulting from actual and forecasted electricity sales.
Balancing account over and under collections represent differences between cash collected in current rates for specified forecasted costs and such costs that are actually incurred. Under-collections are recorded as regulatory balancing account assets. Over-collections are recorded as regulatory balancing account liabilities. 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 accounts. Regulatory balancing accounts that SCE does not expect to collect or refund in the next 12 months are reflected in the long-
term section of the consolidated balance sheets. Under and over collections accrue interest based on a three-month commercial paper rate published by the Federal Reserve.
Amounts included in regulatory assets and liabilities are generally recorded with corresponding offsets to the applicable income statement accounts.
Regulatory Assets
SCE's regulatory assets included on the consolidated balance sheets are:
SCE's regulatory assets related to energy derivatives are primarily an offset to unrealized losses on derivatives. The regulatory asset changes based on fluctuations in the fair market value of the contracts, which expire in 1 to 10 years.
SCE's regulatory assets related to deferred income taxes represent tax benefits passed through to customers. The CPUC requires SCE to pass through certain deferred income tax benefits to customers by reducing electricity rates, thereby deferring recovery of such amounts to future periods. Based on current regulatory ratemaking and income tax laws, SCE expects to recover its regulatory assets related to deferred income taxes over the life of the assets that give rise to the accumulated deferred income taxes, approximately from 1 to 45 years.
SCE's regulatory assets related to pensions and other post-retirement plans represent the unfunded net loss and prior service costs of the plans (see "Pension Plans and Postretirement Benefits Other than Pensions" discussion in Note 8). This amount is being recovered through rates charged to customers as the plans are funded.
SCE's unamortized investments include nuclear assets related to Palo Verde which are expected to be recovered by 2027 and SCE's unamortized coal plant investment which is being recovered through December 2015. Unamortized investments also include legacy meters retired as part of the Edison SmartConnect® program which are expected to be recovered by 2017. Although SCE's unamortized investments are classified as regulatory assets on the consolidated balance sheets, they continue to be a component of rate base and earned a rate of return of 7.90% in 2013 and 8.74% in 2012, except for the Mohave generating station, which did not earn a rate of return in 2013 or 2012 and the legacy meters, which earned a rate of return of 6.46% in 2013 and 2012.
For information on regulatory assets related to San Onofre, see Note 9.
SCE's net regulatory asset related to its unamortized loss on reacquired debt will be recovered over the remaining original amortization period of the reacquired debt over periods ranging from 1 to 30 years.
SCE's 2013 nuclear-related investment include assets and accumulated depreciation related to the ARO for Palo Verde.
Regulatory Liabilities
SCE's regulatory liabilities included on the consolidated balance sheets are:
SCE's regulatory liabilities related to costs of removal represent differences between asset removal costs recorded and amounts collected in rates for those costs.
The regulatory liability related to asset retirement obligations represents the nuclear decommissioning trust assets in excess of the related asset retirement obligations. The decrease in this regulatory liability resulted from a revision to the asset retirement obligations of San Onofre. For further information, see Note 1.
Regulatory Balancing Accounts
The following table summarizes the significant components of regulatory balancing accounts included in the above tables of regulatory assets and liabilities:
Note 12. Commitments and Contingencies
Third-Party Power Purchase Agreements
SCE enters into various agreements to purchase power and electric capacity, including:
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Renewable Energy Contracts - California law requires retail sellers of electricity to comply with an RPS by delivering renewable energy, primarily through power purchase contracts. Renewable energy contract payments generally consist of payments based on a fixed price per megawatt hour. As of December 31, 2013, SCE had 108 renewable energy contracts that were approved by the CPUC and met critical contract provisions which expire at various dates between 2014 and 2035.
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Qualifying Facility Power Purchase Agreements - Under the Public Utility Regulatory Policies Act of 1978 ("PURPA"), electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are qualifying co-generation facilities and qualifying small power production facilities ("QFs"). As of December 31, 2013, SCE had 139 QF contracts which expire at various dates between 2014 and 2030.
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Other Power Purchase Agreements - In accordance with the SCE's CPUC-approved long-term procurement plans, SCE has entered into capacity agreements with third parties, including 32 combined heat and power contracts, 15 tolling arrangements, 4 power call options and 55 resource adequacy contracts. SCE's obligations under a portion of these agreements are limited to payments for the availability of such resources.
At December 31, 2013, the undiscounted future minimum expected payments for the SCE power purchase agreements that have been approved by the CPUC and have completed major milestones for construction were as follows:
Many of the power purchase agreements that SCE entered into with independent power producers are treated as operating and capital leases. The following table shows the future minimum expected payments due under the contracts that are treated as operating and capital leases (these amounts are also included in the table above). The future expected payments for capital leases are discounted to their present value in the table below using SCE's incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the amount representing interest.
Operating lease expense for these power purchase agreements was $1.5 billion in 2013, $1.3 billion in 2012 and $1.4 billion in 2011. The timing of SCE's recognition of the lease expense conforms to ratemaking treatment for SCE's recovery of the cost of electricity and is included in purchased power.
At December 31, 2013 and 2012, SCE's net capital leases reflected in utility plant on the consolidated balance sheets were $209 million and $216 million, including accumulated amortization of $39 million and $33 million, respectively. SCE had $6 million and $6 million included in "Other current liabilities" and $203 million and $210 million included in "Other deferred credits and other liabilities," representing the present value of the minimum lease payments due under these contracts recorded on the consolidated balance sheets at December 31, 2013 and 2012, respectively.
Other Lease Commitments
The following summarizes the estimated minimum future commitments for SCE's noncancelable other operating leases (excluding SCE's power purchase agreements discussed above):
Operating lease expense for other leases (primarily related to vehicles, office space and other equipment) were $78 million in 2013, $75 million in 2012 and $66 million in 2011.
Nuclear Decommissioning Commitment
SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts. The recorded liability to decommission SCE's nuclear power facilities is $3.3 billion as of December 31, 2013, based on decommissioning studies performed in 2010 for Palo Verde and a 2013 updated decommissioning cost estimate for the retirement of both San Onofre Units 2 and 3. Changes in the estimated costs, timing of decommissioning or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission. SCE currently estimates that it will spend approximately $7.1 billion through 2053 to decommission its nuclear facilities. This estimate is based on SCE's decommissioning cost methodology used for ratemaking purposes, escalated at rates ranging from 1.5% to 7.3% (depending on the cost element) annually. These costs are expected to be funded from independent decommissioning trusts, which received contributions of $23 million in 2013, 2012 and 2011. SCE estimates annual after-tax earnings on the decommissioning funds of 4.2% to 5.7%. If the assumed return on trust assets is not earned, it is probable that additional funds needed for decommissioning will be recoverable through rates in the future. If the assumed return on trust assets is greater than estimated, funding amounts may be reduced through future decommissioning proceedings.
Decommissioning expense under the ratemaking method was $23 million for 2013, 2012 and 2011. The ARO for decommissioning SCE's nuclear facilities was $3.3 billion and $2.6 billion at December 31, 2013 and 2012, respectively. See Note 4 and Note 10 for discussion on the nuclear decommissioning trusts. Total expenditures for the decommissioning of San Onofre Unit 1 were $599 million from the beginning of the project in 1998 through December 31, 2013.
Other Commitments
The following summarizes the estimated minimum future commitments for SCE's other commitments:
Costs incurred for other commitments were $153 million in 2013, $249 million in 2012 and $281 million in 2011. SCE has fuel supply contracts which require payment only if the fuel is made available for purchase.
As a result of the decision to permanently retire San Onofre Units 2 and 3, SCE has submitted fuel contract delivery cancellation notices for the nuclear fuel contractual arrangements. As of December 31, 2013, SCE had accrued a liability of $33 million related to estimated costs associated with the cancellation and management of future deliveries of nuclear fuel and recorded a regulatory asset for recovery of costs in the future. See Note 9 for further discussion of SCE's decision to permanently retire San Onofre.
Indemnities
Edison International and SCE have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business.
Edison International and SCE have provided indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and indemnities for specified environmental liabilities and income taxes with respect to assets sold. Edison International's and SCE's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison International and SCE may have recourse against third parties. Edison International and SCE have not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.
SCE has indemnified the City of Redlands, California in connection with Mountainview's California Energy Commission permit for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.
Contingencies
In addition to the matters disclosed in these Notes, Edison International and SCE are involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International and SCE believe the outcome of these other proceedings will not, individually or in the aggregate, materially affect its results of operations or liquidity.
San Onofre
SCE believes that the actions taken and costs incurred in connection with the San Onofre replacement steam generators and outages have been prudent. Accordingly, SCE considers its operating, capital, and market power costs recoverable through base rates and the ERRA balancing account (as reduced by the impairment recorded in 2013). 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. SCE will pursue recoveries arising from available agreements, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements. See Note 9 for further details.
Potential Claims by EME
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 credits, 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 reorganized EME (“Reorganized EME”).
EME has indicated that it is preparing a complaint containing claims similar to those alleged by the Official Committee of Unsecured Creditors in a motion filed in the Bankruptcy Court on August 1, 2013 against Edison International, SCE, certain other subsidiaries of Edison International, and present and former directors of Edison International, SCE and EME. Such motion was accompanied by a draft complaint which has not been filed or served. The draft complaint set forth a variety of allegations against the defendants, including, among other things, that $925 million in dividends paid by EME to Mission Energy Holding Company in 2007 are recoverable, that $183 million paid by EME under the Tax Allocation Agreement in September 2012 was improper, that EME was operated between 2010 and 2012 for Edison International’s benefit and not in accordance with fiduciary duties owed to EME and its creditors, that amending the Tax Allocation Agreement to have it expire on December 31, 2013 was a breach of fiduciary duty, that Edison International has historically overcharged EME for
shared services, that Edison International and certain of its competitive subsidiaries are alter egos of, and should be substantively consolidated with, EME, and are therefore liable for EME’s debts, and that utilization by Edison International and SCE of bonus depreciation following EME’s filing for bankruptcy was a violation of the automatic stay in the EME bankruptcy. Edison International has not been served with a complaint by EME, but if served would vigorously contest such allegations.
Edison International has filed claims against EME for payment of EME’s allocated or stand-alone pension and tax liabilities. On January 2, 2014, EME filed its objections to Edison International's claims and a motion to estimate certain claims including claims filed by Edison International.
In February 2014, Edison International, EME and the Consenting Noteholders entered into a Settlement Agreement pursuant to which EME amended its Plan of Reorganization (“Amended Plan of Reorganization”). The Amended Plan of Reorganization, including the Settlement Agreement, is subject to the approval of the Bankruptcy Court. If the Settlement agreement is not approved or is not effectuated for any other reason, EME may still bring the complaint mentioned above. For more information on the Settlement Agreement, see Note 16.
San Gabriel Valley Windstorm Investigation
In November 2011, a windstorm resulted in significant damage to SCE’s electric system and service outages for SCE customers primarily in the San Gabriel Valley. The CPUC directed its Safety and Enforcement Division (“SED”) to conduct an investigation focused on the cause of the outages, SCE’s service restoration effort, and SCE’s customer communications during the outages. The SED issued its final report on January 11, 2013. The report asserts that SCE and others with whom SCE shares utility poles violated certain CPUC safety rules applicable to overhead line construction, maintenance and operation, which may have caused the failures of affected poles and supporting cables. The report also concludes that SCE’s restoration time was not adequate and makes other assertions. Additionally, the report contends that SCE violated CPUC rules by failing to preserve evidence relevant to the investigation when it did not retain damaged poles that were replaced following the windstorm. In February 2014, SCE entered into agreements with the SED to settle this matter and another, unrelated matter involving SCE's system. Both settlements are subject to CPUC approval.
Four Corners Environmental Matters
In October 2011, four private environmental organizations filed a CAA citizen lawsuit against the co-owners of Four Corners. The complaint alleges that certain work performed at the Four Corners generating units 4 and 5, over the approximate periods of 1985 - 1986 and 2007 - 2010, constituted plant “major modifications” and the plant's failure to obtain permits and install best available control technology ("BACT") violated the PSD requirements and the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violations of BACT air emissions limits. The lawsuit seeks injunctive and declaratory relief, civil penalties, including a mitigation project and litigation costs. In November 2012, the parties requested a stay of the litigation to allow for settlement discussion, and the matter is currently stayed. In December 2013, SCE sold its ownership interest in generating units 4 and 5 to APS. Under the sale agreement SCE remains responsible for its pro-rata share of certain environmental liabilities, including penalties in the event they arise from environmental violations prior to the sale. In addition, under the terms of the sale agreement, SCE retains the liability for its proportionate share of expenses occurring as a result of new environmental regulations applicable to the coal ash and combustion residuals deposited at the landfill at Four Corners during the period that SCE held its ownership interest in Four Corners if such new regulations are adopted. SCE is unable to estimate a possible loss or range of loss associated with these matters.
Environmental Remediation
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operation and maintenance, monitoring and site closure. Unless there is a single probable amount, Edison International records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
At December 31, 2013, Edison International's recorded estimated minimum liability to remediate its 19 identified sites in which the upper end of the range of the costs is at least $1 million at SCE was $110 million, including $73 million related to San Onofre. In addition to these sites, SCE also has 39 immaterial sites for which the total minimum recorded liability was
$4 million. Of the $114 million total environmental remediation liability for SCE, $110 million has been recorded as a regulatory asset. SCE expects to recover $36 million through an incentive mechanism that allows SCE to recover 90% of its environmental remediation costs at certain sites (SCE may request to include additional sites) and $74 million through a mechanism that allows SCE to recover 100% of the costs incurred at certain sites through customer rates. Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at the identified material sites and immaterial sites could exceed its recorded liability by up to $162 million and $7 million, respectively, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes.
SCE expects to clean up and mitigate its identified sites over a period of up to 30 years. Remediation costs for each of the next four years are expected to range from $6 million to $27 million. Costs incurred for years ended December 31, 2013, 2012 and 2011 were $8 million, $10 million and $16 million, respectively.
Based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to estimates.
Nuclear Insurance
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 San Onofre and Palo Verde have purchased the maximum private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor licensees. If a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.
Based on its ownership interests, SCE could be required to pay a maximum of approximately $255 million per nuclear incident. However, it would have to pay no more than approximately $38 million per incident in any one year. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.
NEIL, a mutual insurance company owned by entities with nuclear facilities, issues primary property damage, decontamination and excess property damage and accidental outage insurance policies. At San Onofre and Palo Verde, property damage insurance covers losses up to $500 million, including decontamination costs. Decontamination liability and excess property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than the federal requirement of a minimum of approximately $1.06 billion. Property damage insurance also covers damages caused by acts of terrorism up to specified limits. Additional outage insurance covers part of replacement power expenses during an accident-related nuclear unit outage. The accidental outage insurance at San Onofre has been canceled as a result of the permanent retirement, but that insurance continues to be in effect at Palo Verde.
If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $52 million per year. Insurance premiums are charged to operating expense.
Wildfire Insurance
Severe wildfires in California have given rise to large damage claims against California utilities for fire-related losses alleged to be the result of the failure of electric and other utility equipment. Invoking a California Court of Appeal decision, plaintiffs pursuing these claims have relied on the doctrine of inverse condemnation, which can impose strict liability (including liability for a claimant's attorneys' fees) for property damage. Prolonged drought conditions in California have also increased the risk of severe wildfire events. On September 1, 2013, Edison International, renewed its liability insurance coverage, which included coverage for SCE's wildfire liabilities up to a $500 million limit (with a self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up this insurance coverage could result in additional self-insured costs in the event of multiple wildfire occurrences during the policy period (September 1, 2013 to May 31, 2014). SCE also has additional coverage for certain wildfire liabilities of $450 million, which applies when total covered wildfire claims exceed $550 million, through May 31, 2014. SCE may experience coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.
Spent Nuclear Fuel
Under federal law, the Department of Energy ("DOE") is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.
In June 2010, the United States Court of Federal Claims issued a decision granting SCE and the San Onofre co-owners damages of approximately $142 million (SCE share $112 million) to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. SCE received payment from the federal government in the amount of the damage award in November 2011. SCE has returned to the San Onofre co-owners their respective share of the damage award paid. In December 2013, the CPUC approved SCE's proposal to return the SCE share of the award to customers based on the amount that customers actually contributed for fuel storage costs; resulting in approximately $94 million of the SCE share being returned to customers and the remaining $18 million being returned to shareholders. SCE, as operating agent, filed a lawsuit on behalf of the San Onofre owners against the DOE in the Court of Federal Claims in December 2011 seeking damages of approximately $98 million for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel for the period from January 1, 2006 to December 31, 2010. Additional legal action would be necessary to recover damages incurred after December 31, 2010. All damages recovered by SCE are subject to CPUC review as to how these amounts would be distributed among customers, shareholders, or to offset fuel decommissioning or storage costs.
Note 13. Preferred and Preference Stock of Utility
SCE's authorized shares are: $100 cumulative preferred - 12 million shares, $25 cumulative preferred - 24 million shares and preference with no par value - 50 million shares. SCE's outstanding shares are not subject to mandatory redemption. There are no dividends in arrears for the preferred or preference shares. Shares of SCE's preferred stock have liquidation and dividend preferences over shares of SCE's common stock and preference stock. All cumulative preferred shares are redeemable. When preferred shares are redeemed, the premiums paid, if any, are charged to common equity. No preferred shares were issued or redeemed in the years ended December 31, 2013, 2012 and 2011. There is no sinking fund requirement for redemptions or repurchases of preferred shares.
Shares of SCE's preference stock rank junior to all of the preferred stock and senior to all common stock. Shares of SCE's preference stock are not convertible into shares of any other class or series of SCE's capital stock or any other security. There is no sinking fund requirement for redemptions or repurchases of preference shares.
Preferred stock and preference stock is:
Shares of Series A preference stock, issued in 2005, may be redeemed in whole or in part. Shares of Series D preference stock, issued in 2011, may not be redeemed prior to March 1, 2016. After March 1, 2016, SCE may redeem the shares at par, in whole or in part. Shares of Series E preference stock, issued in 2012, may be redeemed at par, in whole or in part, after February 1, 2022. Shares of Series F and G preference stock, issued in 2012 and 2013, respectively, may be redeemed at par, in whole, but not in part, at any time prior to June 15, 2017 and March 15, 2018, respectively, if certain changes in tax or investment company laws occur. After June 15, 2017 and March 15, 2018, SCE may redeem the Series F and G shares, respectively, at par, in whole or in part. Shares of Series F and G preference stock were issued to SCE Trust I and SCE Trust II, respectively, special purpose entities formed to issue trust securities as discussed in Note 3. The proceeds from the sale of the shares of Series G were used to redeem all outstanding shares of Series B and C preference stock. Preference shares are not subject to mandatory redemption.
At December 31, 2013 declared dividends related to SCE's preferred and preference stock were $30 million.
Note 14. Accumulated Other Comprehensive Loss
Included in the Edison International accumulated other comprehensive loss at December 31, 2011 was $34 million (net of tax) of unrealized losses from cash flow hedges and $5 million (net of tax) from prior service costs from pension and PBOP Plans. These balances were included in other comprehensive income during 2012 resulting in a zero balance at December 31, 2012. The changes in accumulated comprehensive income, excluding the items above, were as follows:
Excludes the amount of unrealized losses from cash flow hedges and prior service costs arising from pension and PBOP.
These items are included in the computation of net periodic pension and PBOP expense.
Note 15. Interest and Other Income and Other Expenses
Interest and other income and other expenses are as follows:
In 2013, SCE and the Safety and Enforcement Division of the CPUC agreed to terms of a settlement agreement related to the 2007 wildfire in Malibu, California. The settlement agreement resulted in SCE paying a total of $37 million, $17 million of which will be allocated to pole safety studies and remediation in the Malibu area and a $20 million penalty paid to the State General Fund.
Note 16. Discontinued Operations
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's December Plan of Reorganization 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.
Deconsolidation
EME and those subsidiaries in Chapter 11 proceedings retained control of their assets and are authorized to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court. 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. During the fourth quarter of 2012, Edison International recorded a full impairment of the investment in EME as a result of the deconsolidation of EME, recognition of losses previously deferred in accumulated other comprehensive income, a provision for losses from the EME bankruptcy and estimated tax impacts related to the expected future tax deconsolidation and separation of EME from Edison International. The aggregate impact of these matters resulted in an after tax charge of $1.3 billion. 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 discontinued operations in the consolidated financial statements.
Edison International will not be affected by changes in EME's future financial results, other than those changes related to certain tax matters. Edison International has evaluated the continuing cash flows with EME and determined that these cash flows generated are indirect and immaterial. Edison International's continuing cash flows will not include any significant revenue-producing and cost-generating activities of EME. Shared services support that Edison International and EME provided each other was not material to Edison International's cash flows. Summarized results of discontinued operations:
Before Edison International classified EME as discontinued operations, Edison International had accounted for EME's Homer City as a discontinued operation. The operating results shown above reflect the operating results of Homer City through December 14, 2012. On December 14, 2012, Homer City and an affiliate of GECC completed the Homer City Master Transaction Agreement ("MTA") between EME Homer City Generation L.P. and General Electric Capital Corporation for the divestiture by Homer City of substantially all of its remaining assets and certain specified liabilities. In the third quarter of 2012, EME recorded a $113 million charge ($68 million after tax) to write down assets held for sale to net realizable value during the third quarter of 2012. The charge was reduced to $89 million ($53 million after tax) when the transaction closed. In the fourth quarter of 2011, EME recorded an impairment charge of $1.03 billion related to Homer City's long-lived assets.
Contingencies
Under the Internal Revenue Code and applicable state statutes, Edison International Parent is jointly liable for qualified retirement plans and federal and specific state tax liabilities. As a result of the deconsolidation and the existence of joint liabilities, Edison International has recorded liabilities at December 31, 2013 of $325 million comprised of $35 million for qualified retirement plans related to plan participants of EME and $290 million for joint tax liabilities. Under the qualified plan documents and tax allocation agreements, EME is obligated to pay for such liabilities and, accordingly, at December 31, 2013 Edison International has recorded corresponding receivables from EME.
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 on August 1, 2013 against Edison International, SCE, certain other subsidiaries of Edison International, and present and former directors of Edison International, SCE and EME. See EME potential claims discussed in Note 12. Edison International has not been served with a complaint by EME, but if served would vigorously contest such allegations.
The outcome of the EME bankruptcy proceeding as well as any litigation brought by EME against Edison International is uncertain. At December 31, 2013, management concluded that it is probable that a loss would be incurred and estimated a loss of $150 million. The outcome of the EME bankruptcy could result in losses different than the amounts recorded by Edison International and such amounts could be material.
For a discussion of contingencies related to EME, see Tax Disputes discussed in Note 7 and potential litigation discussed in Note 12.
Subsequent Event
In February 2014, subsequent to the preparation of the financial statements, 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.
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 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.
As the Settlement Agreement was entered into in 2014 and is subject to approval by the Bankruptcy Court, it is accounted for as a subsequent event under GAAP and not reflected in the 2013 financial statements (referred to as a "Type II" subsequent event).
Note 17. Supplemental Cash Flows Information
Supplemental cash flows information is:
SCE's accrued capital expenditures at December 31, 2013, 2012 and 2011 were $661 million, $671 million and $685 million, respectively. Accrued capital expenditures will be included as an investing activity in the consolidated statements of cash flow in the period paid.
Note 18. Related Party Transactions
Edison International and SCE provide and receive various services to and from its subsidiaries and affiliates. Services provided to Edison International by SCE are priced at fully loaded cost (i.e., direct cost of good or service and allocation of overhead cost). Specified administrative services such as payroll, employee benefit programs, all performed by Edison International or SCE employees, are shared among all affiliates of Edison International. Costs are allocated based on one of the following formulas: percentage of time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and number of employees). Edison International allocates various corporate administrative and general costs to SCE and other subsidiaries using established allocation factors. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.
At December 31, 2013, Edison International has recorded receivables from EME of $325 million. Revenue from services provided to EME and affiliates during 2013, 2012 and 2011 were $2 million, $7 million and $5 million, respectively. See Note 16 for further information. In addition, Edison International has recorded deferred credits at December 31, 2013 and 2012 of $120 million and $36 million, respectively, representing amounts that would become due and payable to Capistrano Wind Holdings upon utilization of net operating loss and tax credit carryforwards under tax allocation agreements.
SCE has recorded a liability of $10 million at December 31, 2013 for power purchased under the Walnut Creek project. In 2008, EME was awarded by SCE, through a competitive bidding process, a 10-year power sales contract with SCE for the output of a 479 MW gas-fired peaking facility referred to as the Walnut Creek project. The power sales agreement was approved by the CPUC and FERC in 2008. Deliveries under the power sales agreement commenced in June 2013. Purchase power recorded by SCE during 2013 from the Walnut Creek project was $93 million.
Note 19. Quarterly Financial Data (Unaudited)
Edison International's quarterly financial data is as follows:
During the second quarter of 2013, SCE recorded an impairment charge of $575 million ($365 million after tax) related to the permanent retirement of San Onofre Units 2 and 3.
During the fourth quarter of 2012, SCE implemented the 2012 GRC Decision which resulted in an earnings impact of approximately $500 million.
During the fourth quarter of 2012, SCE corrected errors, primarily related to deferred taxes, that resulted in a net earnings benefit of $33 million which were not considered material to the current and prior period consolidated financial statements.
During the fourth quarter of 2012, Edison International recorded a full impairment of its investment in EME. See Note 16 for further information.
SCE's quarterly financial data is as follows:
During the second quarter of 2013, SCE recorded an impairment charge of $575 million ($365 million after tax) related to the permanent retirement of San Onofre Units 2 and 3.
During the fourth quarter of 2012, SCE implemented the 2012 GRC Decision which resulted in an earnings impact of approximately $500 million.
During the fourth quarter of 2012, SCE corrected errors, primarily related to deferred taxes, that resulted in a net earnings benefit of $33 million which were not considered material to the current and prior period consolidated financial statements.
Due to the seasonal nature of Edison International and SCE's business, a significant amount of revenue and earnings are recorded in the third quarter of each year. As a result of rounding, the total of the four quarters does not always equal the amount for the year.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Based on an evaluation of Edison International’s and SCE’s disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as of December 31, 2013, Edison International’s and SCE’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by Edison International and SCE in reports that the companies file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, Edison International’s and SCE’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by Edison International and SCE in the reports that Edison International and SCE file or submit under the Exchange Act is accumulated and communicated to Edison International’s and SCE’s management, including Edison International’s and SCE’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Management's Report on Internal Control Over Financial Reporting
Edison International's and SCE's respective management are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f), for Edison International and its subsidiaries and SCE, respectively. Under the supervision and with the participation of their respective principal executive officer and principal financial officer, Edison International's and SCE's management conducted an evaluation of the effectiveness of their respective internal controls over financial reporting based on the framework set forth in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on their evaluations under the COSO framework, Edison International's and SCE's respective management concluded that Edison International's and SCE's respective internal controls over financial reporting were effective as of December 31, 2013. Edison International's internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report on the financial statements included in Item 8 of this report, which is incorporated herein by this reference. This annual report does not include an attestation report of SCE's independent registered public accounting firm regarding internal control over financial reporting. Management’s report for SCE is not subject to attestation by the independent registered public accounting firm.
Changes in Internal Control Over Financial Reporting
There were no changes in Edison International’s or SCE's internal control over financial reporting during the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, Edison International’s or SCE's internal control over financial reporting.
Jointly Owned Utility Plant
Edison International's and SCE's respective scope of evaluation of internal control over financial reporting includes their Jointly Owned Utility Projects.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information concerning executive officers of Edison International is set forth in Part I in accordance with General Instruction G(3), pursuant to Instruction 3 to Item 401(b) of Regulation S-K. Other information responding to Item 10 will appear in Edison International's and SCE's definitive Proxy Statement (the "Joint Proxy Statement") to be filed with the SEC in connection with Edison International's and SCE's Annual Shareholders' Meeting to be held on April 24, 2014, under the headings "Item 1: Election of Directors," and "Board Committees" and is incorporated herein by this reference.
The Edison International Employee Ethics and Compliance Code is applicable to all officers and employees of Edison International and its subsidiaries, including SCE. The Code is available on Edison International's Internet website at www.edisoninvestor.com at "Corporate Governance." Any amendments or waivers of Code provisions for the Company's principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, will be posted on Edison International's Internet website at www.edisoninvestor.com.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information responding to Item 11 will appear in the Joint Proxy Statement under the headings "Compensation Discussion and Analysis," "Compensation Committee Interlocks and Insider Participation," "Executive Compensation" and "Director Compensation" and is incorporated herein by this reference, and under the heading "Compensation Committee Report," which is incorporated by reference in accordance with Instruction G(3) pursuant to Instruction 2 to Item 407(e)(5) of Regulation S-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information responding to Item 12 will appear in the Joint Proxy Statement under the heading "Information About Our Stock Ownership," and is incorporated herein by this reference.
Equity Compensation Plans
The following Table sets forth, for each of Edison International's Equity compensation plans, the number of shares of Edison International Common Stock subject to outstanding options, warrant and rights to acquire such stock, the weighted-average exercise price of those outstanding options, warrants and rights, and the number of shares remaining available for future award grants as of December 31, 2013.
This amount includes 17,204,920 shares covered by outstanding stock options, 313,001 shares that could be delivered for outstanding performance share awards, 539,689 shares covered by outstanding restricted stock unit awards, and 224,624 shares covered by outstanding deferred stock unit awards. The weighted-average exercise price of awards outstanding under equity compensation plan approved by security holders reflected in column (b) above is calculated based on the outstanding stock options under these plans as the other forms of wards outstanding have no exercise price.
This amount is the aggregate number of shares available for new awards under the Edison International 2007 Performance Incentive Plan as of December 31, 2013, and includes shares that have become available from the Edison International Equity Compensation Plan and the Edison International 2000 Equity Plan (together, the "Prior Plans"). However, no additional awards have been granted under the Prior Plans since April 26, 2007, and all awards granted since that date have been made under the Edison International 2007 Performance Incentive Plan. The maximum number of shares or Edison International Common Stock that may be issued or transferred pursuant to awards under the Edison International 2007 Performance Incentive Plan is 49,500,000 shares, plus the number of any shares subject to awards issued under the Prior Plans and outstanding as of April 26, 2007 that expire, cancel or terminate without being exercised or shares being issued. Shares available under the Edison International 2007 Performance Incentive Plan may
generally, subject to certain limits set forth in the plan, be used for any type of award authorized under that plan, including stock options, restricted stock, performance shares, restricted or deferred units, and stock bonuses.
The Edison International 2000 Equity Plan is a broad-based stock option plan that did not require shareholder approval. It was adopted in May 2000 by Edison International with an original authorization of 10,000,000 shares. The Edison International Compensation and Executive Personnel Committee is the plan administrator. Edison International nonqualified stock options were granted to employees of the Edison International companies under this plan, but the granting authority expired on April 26, 2007. Any outstanding shares as of that date that expire, cancel or terminate without being exercised or shares being issued increase the maximum shares that may be delivered under the Edison International 2007 Performance Incentive Plan as described in footnote (2) above. The exercise price was not less than the fair market value of a share of Edison International Common Stock on the date of grant and the stock options cannot be exercised more than 10 years after the date of grant.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information responding to Item 13 will appear in the Joint Proxy Statement under the headings "Certain Relationships and Related Transactions," and "Information About Our Corporate Governance-Q: Is SCE subject to the same corporate governance stock exchange rules as EIX?", "-Q: How does the Board determine which directors are considered independent?", "-Q: Which directors has the Board determined are independent to serve on the Board?" and "Where can I find the Company's corporate governance documents?" and is incorporated herein by this reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information responding to Item 14 will appear in the Joint Proxy Statement under the heading "Independent Registered Public Accounting Firm Fees," and is incorporated herein by this reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
See Consolidated Financial Statements listed in the Table of Contents of this report.
(a)(2) Report of Independent Registered Public Accounting Firm and Schedules Supplementing Financial Statements
The following documents may be found in this report at the indicated page numbers on the Table of Contents of this report.
Reports of Independent Registered Public Accounting Firm
Schedule I - Condensed Financial Information of Edison International Parent
Schedule II - Valuation and Qualifying Accounts of Edison International and SCE
Schedules I for SCE and Schedules III through V, inclusive, for both Edison International and SCE are omitted as not required or not applicable.
(a)(3) Exhibits
See "Exhibit Index" in this report.
Edison International and SCE will furnish a copy of any exhibit listed in the accompanying Exhibit Index upon written request and upon payment to Edison International or SCE of their reasonable expenses of furnishing such exhibit, which shall be limited to photocopying charges and, if mailed to the requesting party, the cost of first-class postage.
EDISON INTERNATIONAL
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
EDISON INTERNATIONAL
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2013, 2012 and 2011
EDISON INTERNATIONAL
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
Note 1. Basis of Presentation
The accompanying condensed financial statements of Edison International Parent should be read in conjunction with the consolidated financial statements and notes thereto of Edison International and subsidiaries ("Registrant") included in Part II, Item 8 of this Form 10-K. Edison International's Parent significant accounting policies are consistent with those of the Registrant, SCE and other wholly owned and controlled subsidiaries.
Dividends Received
Edison International Parent received cash dividends from SCE of $486 million, $469 million and $461 million in 2013, 2012 and 2011, respectively.
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 SCE's net assets of $11.9 billion.
Note 2. Debt and Credit Agreements
Long-Term Debt
At December 31, 2013 and 2012, Edison International Parent had 3.75% senior notes outstanding of $400 million, which matures in 2017.
Credit Agreements and Short-Term Debt
In 2013, Edison International Parent amended its $1.25 billion credit facility to extend the maturity date to July 2018. At December 31, 2013, the outstanding commercial paper was $34 million at a weighted-average interest rate of 0.55%. This short-term debt was supported by the $1.25 billion multi-year revolving credit facility. At December 31, 2012, Edison International Parent had no outstanding short-term debt.
The following table summarizes the status of the credit facility at December 31, 2013:
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 excludes 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.
Note 3. Related-Party Transactions
Edison International's Parent expenses from services provided by SCE were $3 million, $4 million and $3 million for the years ended December 31, 2013, 2012 and 2011, respectively. Edison International Parent had current related-party receivables of $34 million and $23 million and current related-party payables of $69 million and $146 million at December 31, 2013 and 2012, respectively. Edison International Parent had long-term related-party receivables of $486 million and $322 million at December 31, 2013 and 2012, respectively, and long-term related-party payables of $135 million and $112 million at December 31, 2013 and 2012, respectively.
Note 4. EME Chapter 11 Bankruptcy Filing
Edison International Parent recorded an income tax benefit of $36 million and an after-tax charge of $1.3 billion for the year ended December 31, 2013 and 2012, respectively, related to the deconsolidation of EME. See "Item 8. Notes to Consolidated Financial Statements-Note 7. Income Taxes," "-Note 12. Commitments and Contingencies" and "-Note 16. Discontinued Operations" for further information related to these bankruptcy proceedings.
Note 5. Contingencies
For a discussion of material contingencies see "Item 8. Notes to Consolidated Financial Statements-Note 7. Income Taxes," "-Note 12. Commitments and Contingencies" and "-Note 16. Discontinued Operations."
EDISON INTERNATIONAL
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
a
Accounts written off, net.
b
Edison International recorded deferred tax assets of $2.2 billion related to net operating losses and tax carryforwards that pertain to Edison International's consolidated or combined federal and state tax returns, including approximately $1.6 billion related to EME. Edison International continues to consolidate EME for federal and certain combined state tax returns. EME’s Plan of Reorganization, filed in December 2013 ("December Plan of Reorganization"), provides for the transfer of EIX’s ownership interest to the creditors, which would result in a tax deconsolidation of EME. Under federal and state tax regulations, the tax deconsolidation of EME will reduce the amounts net operating loss and tax credits carryforwards that Edison International would be eligible to use in future periods. As a result of the EME’s December Plan of Reorganization, that would result in a tax deconsolidation of EME, Edison International has recorded a $1.380 billion valuation allowance based on the estimated amount of such benefits as calculated under the applicable federal and state tax regulations as of December 31, 2013. The deferred income tax benefits recognized by Edison International less the valuation allowance for amounts that would no longer be available upon tax deconsolidation of EME was approximately $220 million.
c
In 2010, SCE recorded a $23 million reserve against an uncollectible receivable related to contract termination negotiations, which was written off during 2011.
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
a
Accounts written off, net.
b
In 2010, SCE recorded a $23 million reserve against an uncollectible receivable related to contract termination negotiations, which was written off during 2011.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.
EDISON INTERNATIONAL
SOUTHERN CALIFORNIA EDISON COMPANY
By:
/s/ Mark C. Clarke
By:
/s/ Mark C. Clarke
Mark C. Clarke
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)
Mark C. Clarke
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)
Date:
February 25, 2014
Date:
February 25, 2014
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the date indicated.
Signature
Title
A. Principal Executive Officers
Theodore F. Craver, Jr.*
Chairman of the Board, President,
Chief Executive Officer and Director
(Edison International)
Ronald L. Litzinger*
President and Director
(Southern California Edison Company)
B. Principal Financial Officers
W. James Scilacci*
Executive Vice President,
Chief Financial Officer and Treasurer
(Edison International)
Linda G. Sullivan*
Senior Vice President and Chief Financial Officer
(Southern California Edison Company)
C. Principal Accounting Officers
Mark C. Clarke*
Vice President and Controller
(Edison International and Southern California Edison Company)
D. Directors (Edison International and Southern California Edison Company, unless otherwise noted)
Jagjeet S. Bindra*
Director
Vanessa C.L. Chang*
Director
France A. Córdova*
Director
Theodore F. Craver, Jr.*
Director
Bradford M. Freeman*
Director
Ronald L. Litzinger (SCE only)*
Director
Luis G. Nogales*
Director
Ronald L. Olson*
Director
Richard T. Schlosberg, III*
Director
Thomas C. Sutton*
Director
Ellen O. Tauscher*
Director
Peter J. Taylor*
Director
Brett White*
Director
EXHIBIT INDEX
________________________________________
*
Incorporated by reference pursuant to Rule 12b-32.
**
Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)3.