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•	ability of SCE to recover its costs in a timely manner from its customers through regulated rates, including regulatory assets related to San Onofre and under-collection of fuel and purchased power costs;

•	decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities and delays in regulatory actions;

•	ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms;

•	possible customer bypass or departure due to technological advancements or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable;

•

risks inherent in the construction of transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable the acceptance of power delivery), and governmental approvals;

•	risks associated with the operation of transmission and distribution assets and power generating facilities including: public safety issues, failure, availability, efficiency, and output of equipment and availability and cost of spare parts;

•	risks associated with the retirement and decommissioning of nuclear generating facilities;

•	physical security of SCE's critical assets and personnel and the cyber security of SCE's critical information technology systems for grid control, and business and customer data;

•	cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs to replace power and voltage support that was previously provided by San Onofre or in the event of power plant outages or significant counterparty defaults under power-purchase agreements;

•	environmental laws and regulations, at both the state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business;

•	risk that the costs incurred in connection with San Onofre may not be recoverable from SCE's supplier or insurance coverage;

•	approval of the Amended Plan of Reorganization, including the Settlement Agreement, in connection with the EME bankruptcy and proceedings related to it;

•	changes in the fair value of investments and other assets;

•	changes in interest rates and rates of inflation, including escalation rates, which may be adjusted by public utility regulators;

•	governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by the California Independent System Operator, Regional Transmission Organizations, and adjoining regions;

•	availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;

•	cost and availability of labor, equipment and materials;

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•	ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance or in the absence of insurance the ability to recover uninsured losses;

•	effects of legal proceedings, changes in or interpretations of tax laws, rates or policies;

•	potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;

•	cost and availability of fuel for generating facilities and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;

•	extent of technological change in the generation, storage, transmission, distribution and use of electricity;

•	cost and availability of emission credits or allowances for emission credits;

•	risk that competing transmission systems will be built by merchant transmission providers in SCE's service area; and

•	weather conditions and natural disasters.

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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;

•	prioritization by public policymakers of initiatives to reduce carbon emissions and advance competition;

•	increased need for infrastructure replacement and development to accommodate new technologies; and

•	technological and financing innovation that facilitates conservation and self-generation and changes in electricity generation, transmission and distribution.

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1	Think Cure is a community-based nonprofit organization that raises funds to accelerate collaborative research to cure cancer and is not a parent, affiliate or subsidiary of Edison International.

2	Puget Sound Energy is a regulated energy utility in Washington State and is not a parent, affiliate or subsidiary of Edison International.

3	Annenberg Foundation Trust at Sunnylands is an independent nonprofit 501(c)(3) entity that provides a location where national and international leaders may meet in order to facilitate international agreement and supports education programs on the U.S. Constitution. It is not a parent, affiliate or subsidiary of Edison International.

4	EMG is the holding company for EME, an independent power producer and is a wholly-owned subsidiary of Edison International and an affiliate of SCE.

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1	See footnote 4 under Executive Officers of Edison International above.

2	See footnote 1 under Executive Officers of Edison International above.

3	Entergy Nuclear Operations, Inc. is a subsidiary of Entergy Corporation, an integrated energy company and is not a parent, affiliate or subsidiary of SCE.

4	See footnote 3 under Executive Officers of Edison International above.

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1

The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's: (i) 401(k) Savings Plan; (ii) Dividend Reinvestment and Direct Stock Purchase Plan; and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions.

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2	Total assets includes assets from continuing and discontinued operations.

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•	An impairment charge of $575 million ($365 million after tax) in 2013 related to the permanent retirement of San Onofre Units 2 and 3.

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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.

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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.

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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.

•	At May 31, 2013, SCE's net investment associated with San Onofre is set forth in the following table:

1	Includes net book value of the replacement steam generators of $542 million.

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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.

•

As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre were purchased in the market by SCE. These market power costs will be reviewed as part of the CPUC's OII proceeding. Estimated market power costs calculated in accordance with the OII methodology were approximately $680 million as of June 6, 2013, excluding avoided nuclear fuel costs which are no longer included as a reduction due to SCE's decision to permanently retire Units 2 and 3. Such amount includes costs of approximately $65 million associated with planned outage periods. SCE believes that such costs should be excluded as they would have been incurred even had the replacement steam generators performed as expected. Estimated market power costs calculated in accordance with the OII methodology from June 7, 2013 through December 31, 2013 were approximately $333 million.

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•	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.

•

Reclassified $1,521 million of its total investment in San Onofre at May 31, 2013 as described above to a regulatory asset (“San Onofre Regulatory Asset”). Included in the San Onofre Regulatory Asset is approximately $404 million of property, plant and equipment, including construction work in progress, which is expected to support ongoing activities at the site. In addition, to the extent the San Onofre Regulatory Asset includes excess nuclear fuel and material and supplies, SCE will, if possible, sell such excess amounts to third parties and reduce the amount of the regulatory asset by such proceeds.

•	Recorded an impairment charge of $575 million ($365 million after tax) in the second quarter of 2013.

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•	Maintaining reliability and expanding the capability of SCE's transmission and distribution system through infrastructure replacements and improvements.

•	Upgrading and constructing new transmission lines and substations for system reliability and increased access to renewable energy, including the Tehachapi, Coolwater-Lugo and West of Devers transmission and substation projects.

•	Maintaining performance of SCE's natural gas, and hydro-electric generating plants.

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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.

1	See use of non-GAAP financial measures in "Management Overview—Highlights of Operating Results."

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•	Lower operating revenue of $80 million was primarily due to the following:

•	A decrease in San Onofre-related estimated revenue of $303 million, as discussed below.

•	An increase in CPUC-related revenue of $60 million primarily related to the increase in authorized revenue to support rate base growth and operating expenses which was partially offset by the lower CPUC-adopted 2013 return on common equity and Edison SmartConnect® revenue, resulting from the full deployment of the program in 2012.

•	An increase in FERC-related revenue of $170 million primarily related to rate base growth and higher operating costs.

•	Lower operation and maintenance expense of $170 million was primarily due to the following:

•	$170 million decrease in San Onofre-related expense, as discussed below.

•	$95 million decrease in expense in 2013 due to the full deployment of the Edison SmartConnect® program in 2012.

•	$40 million decrease in severance costs due to the reductions in workforce (excluding San Onofre) that commenced in 2012.

•	$85 million of higher operating costs primarily related to information technology, safety, legal and insurance costs.

•	$45 million of planned outage costs at Mountainview, repair costs at Four Corners, and higher operating costs on CPUC- and FERC-related projects.

•	Higher depreciation, decommissioning and amortization expense of $60 million was primarily related to increased transmission and distribution investments, including capitalized software costs, offset by the impact from ceasing depreciation on the San Onofre assets, beginning in June 2013.

•	$575 million impairment charge ($365 million after tax) in 2013 related to the permanent retirement of San Onofre Units 2 and 3.

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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."

•	Higher interest expense of $25 million primarily due to higher balances on long-term debt to support rate base growth and lower AFUDC debt due to lower rates and construction work in progress balances in 2013.

•	Higher income taxes of $65 million primarily due to lower income tax benefits, including lower repair deductions (as determined for income tax purposes). See "—Income Taxes" below for more information.

•	Decrease in revenue of $303 million in 2013 related to lower operating costs (as discussed below), no longer recognizing the return on San Onofre rate base and ceasing depreciation, beginning in June 2013, pending regulatory treatment in the San Onofre OII and the scheduled refueling outage in 2012.

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Decrease in operation and maintenance expense of $170 million primarily due to lower operating costs of $109 million resulting from the early retirement of Units 2 and 3 in June 2013 and $35 million in 2012 related to the scheduled outage at Unit 2. In addition, SCE had lower incremental inspection and repair costs of $53 million (net of SCE's share of payments received from MHI in 2012), which were not offset in revenue above, pending regulatory treatment in the San Onofre OII. These factors were partially offset by additional severance costs of $27 million ($63 million and $36 million in 2013 and 2012, respectively).

•	Decrease in depreciation of $67 million from ceasing depreciation on San Onofre beginning in June 2013.

•	Higher operating revenue was primarily due to the following:

•	$375 million increase in revenue related to the implementation of the 2012 GRC decision. The decision authorized a revenue requirement increase of approximately $470 million over the 2011 authorized revenue, excluding nuclear refueling outages ($95 million of which is reflected in utility cost-recovery activities primarily related to employee benefits); and

•	$60 million increase in revenue related to authorized CPUC projects not included in SCE's GRC authorized revenue, including the Edison SmartConnect® project and the Solar Photovoltaic project.

•	Higher operation and maintenance expense due to the following:

•	$112 million in accrued severance costs from current and approved reductions in staffing;

•	$66 million in incremental inspection and repair costs related to the outages at San Onofre, net of SCE's share of payments received from MHI; and

•	$85 million of lower costs related to information technology, transmission and distribution expenses, San Onofre and benefits realized from Edison SmartConnect®.

•	Higher depreciation, decommissioning and amortization expense of $136 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs.

•	$32 million charge due to the 2012 GRC decision disallowing capitalized costs incurred as part of SCE's implementation of SAP's Enterprise Resource Planning system.

•	Higher interest expense of $31 million was primarily due to higher outstanding balances on long-term debt due to new issuances.

•	Lower income taxes primarily due to an earnings benefit resulting from the regulatory treatment adopted in the 2012 GRC for tax repair deductions for income tax purposes. See "—Income Taxes" below for more information.

•	Higher preferred and preference stock dividends of $32 million related to new issuances in 2012.

•	Higher fuel and purchased power expense of $752 million was primarily driven by higher power and gas prices in 2013, partially offset by lower realized losses on economic hedging activities ($56 million in 2013 compared to $227 million in 2012) and by a $43 million credit received from the ISO for SCE’s share of a settlement between the FERC and an ISO participant.

•	Higher operation and maintenance expense of $42 million primarily due to costs for the GHG cap-and-trade program related to utility owned generation, higher costs related to transmission and distribution expenses, higher pension expenses, partially offset by lower spending on various public purpose programs.

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Higher fuel and purchased power expense of $783 million was primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below) and $300 million of market costs net of lower nuclear fuel costs related to the San Onofre outages in 2012 (see "Management Overview—Permanent Retirement of San Onofre" for further information).

•	Higher operation and maintenance expense of $62 million was primarily due to an increase in pension and postretirement benefit contributions.

•	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.

•	A sales volume increase of $1.4 billion, primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011, partially offset by

•	A rate decrease of $344 million, resulting from rate adjustments in June 2011 and August 2012, primarily reflecting lower natural gas prices and refunds to customers of over-collected fuel and power procurement-related costs.

•	A rate decrease of $408 million resulting from a rate adjustment beginning on June 1, 2011, primarily reflecting the refund of over collected fuel and power procurement-related costs, offset by

•	A sales volume increase of $393 million primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011, see below.

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1	Included in SCE's capital expenditures plan are projected environmental capital expenditures of approximately 15% for each year presented. The projected environmental capital expenditures are to comply with laws, regulations, and other nondiscretionary requirements.

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1	Direct expenditures include direct labor, land and contract costs incurred for the respective projects and exclude overhead costs that are included in the capital expenditures forecasted for 2014 – 2017.

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1	Collateral provided to counterparties and other brokers consisted of $10 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $19 million of cash reflected in "Other current assets" on the consolidated balance sheets and $118 million in letters of credit and surety bonds.

2	There would be no significant increase to SCE's total posted and potential collateral requirements based on SCE's forward positions as of December 31, 2013 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level.

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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.

•	$205 million decrease from balancing accounts primarily composed of:

•	$885 million decrease resulting from higher ERRA balancing account under-collections for fuel and power procurement-related costs in 2013 compared to 2012. The change in the ERRA balancing account decreased operating cash flows by $1.1 billion in 2013 compared to a decrease in operating cash flows by $257 million in 2012.

•	$210 million decrease primarily due to increased spending and lower funding of public purpose and energy efficiency programs.

•	$725 million increase primarily due to the implementation of the 2012 GRC decision which resulted in a rate increase in January 2013 to collect both the 2012 and 2013 rate changes.

•	$165 million increase resulting from an increase in GHG allowance proceeds in 2013.

•	$151 million cash outflow related to workforce reduction severance costs in 2013.

•	timing of cash receipts and disbursements related to working capital items.

•	$265 million increase from balancing accounts composed of:

•	$375 million increase resulting from actual electricity sales exceeding forecasted electricity sales primarily related to warmer weather during the summer months;

•	$150 million increase primarily due to the funding of public purpose and energy efficiency programs;

•	$110 million increase resulting from greenhouse gas emission auction proceeds; and

•	$370 million decrease resulting from lower balancing account overcollections for fuel and power procurement-related costs in 2012 when compared to 2011. The 2012 decrease in overcollections was due to lower realized power and natural gas prices compared to the amounts forecasted in rates.

•	$193 million increase resulting from a tax refund relating to the 2011 net operating loss carryback;

•	$68 million cash inflow resulting from proceeds of U.S. Treasury Grants relating to solar photovoltaic projects and other specific energy-related projects made available as a result of the American Recovery and Reinvestment Act of 2009;

•	$60 million cash inflow resulting from a security deposit received related to transmission and distribution construction; and

•	timing of cash receipts and disbursements related to working capital items.

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1	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.

2

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."

3	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."

4	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.

5

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.

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6	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.

7	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.

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1	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.

2	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.

3	The exposure in this category relates to long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment.

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•	Decommissioning Costs. The estimated costs for labor, dismantling and disposal costs, depth of site remediation, energy and miscellaneous costs.

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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.

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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.

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*	Not applicable to pension plans.

1

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.

2

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.

3	The health care cost trend rate gradually declines to 5.0% for 2020 and beyond.

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1	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.

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1	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.

2	Approximately 70% and 66% of SCE's equity investments were located in the United States at December 31, 2013 and 2012, respectively.

3	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.

4	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.

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1	Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

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1	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.

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1	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.

2	Includes incremental repair benefit recorded in 2013 and 2012. See discussion of repair deductions below.

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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.

•	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.

•	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.

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1	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.

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1	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.

2	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.

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1	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.

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1

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

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1	Due to the reduction in workforce, SCE has incurred costs for extended retiree health care coverage.

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•	United States Equities: Common and preferred stocks of large, medium, and small companies which are predominantly United States-based.

•	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.

•	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: Investments in short to intermediate term market opportunities. Investments may have fixed income and/or equity characteristics and may be either liquid or illiquid.

•	Alternative: Limited partnerships that invest in non-publicly traded entities.

•	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.

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1	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.

2	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%).

3	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.

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4

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.

5

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.

6	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.

7	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.

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1

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.

2	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.

3	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.

4	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.

5	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.

6	Level 1 registered investment companies consist of an investment grade corporate bond mutual fund and a money market fund.

7	Other includes $76 million and $73 million of municipal securities at December 31, 2013 and 2012, respectively.

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1	Reflected in "Operation and maintenance" on Edison International's and SCE's consolidated statements of income.

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1	Relates to performance shares that will be paid in 2014 as performance targets were met at December 31, 2013.

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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.

•	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.

•

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.

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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.

•	Recorded an impairment charge of $575 million ($365 million after tax) in the second quarter of 2013.

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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.

•

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.

•

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.

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1	Excludes the amount of unrealized losses from cash flow hedges and prior service costs arising from pension and PBOP.

2	These items are included in the computation of net periodic pension and PBOP expense.

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1	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.

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1	During the fourth quarter of 2012, SCE implemented the 2012 GRC Decision which resulted in an earnings impact of approximately $500 million.

2	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.

3	During the fourth quarter of 2012, Edison International recorded a full impairment of its investment in EME. See Note 16 for further information.

1	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.

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1	During the fourth quarter of 2012, SCE implemented the 2012 GRC Decision which resulted in an earnings impact of approximately $500 million.

2	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.

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1

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.

2

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

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3

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.

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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.

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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.

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*	Incorporated by reference pursuant to Rule 12b-32.

**	Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)3.