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•	ability of SCE to recover its costs through regulated rates, including costs related to uninsured wildfire-related and mudslide-related liabilities and capital spending incurred prior to formal regulatory approval;

•	ability to obtain sufficient insurance at a reasonable cost, including insurance relating to SCE's nuclear facilities and wildfire-related claims, and to recover the costs of such insurance or, in the event liabilities exceed insured amounts, the ability to recover uninsured losses from customers or other parties;

•	decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities, including determinations of authorized rates of return or return on equity, the 2018 GRC, the GS&RP application, the recoverability of wildfire-related and mudslide- related costs, and delays in regulatory actions;

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

•	actions by credit rating agencies to downgrade Edison International or SCE's credit ratings or to place those ratings on negative watch or outlook;

•	risks associated with the decommissioning of San Onofre, including those related to public opposition, permitting, governmental approvals, on-site storage of spent nuclear fuel, delays, contractual disputes, and cost overruns;

•	extreme weather-related incidents and other natural disasters (including earthquakes and events caused, or exacerbated, by climate change, such as wildfires), which could cause, among other things, public safety issues, property damage and operational issues;

•	risks associated with cost allocation resulting in higher rates for utility bundled service customers because of possible customer bypass or departure for other electricity providers such as CCAs and Electric Service Providers;

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risks inherent in SCE's transmission and distribution infrastructure investment program, 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 acceptance of power delivery), changes in the CAISO's transmission plans, and governmental approvals;

•	risks associated with the operation of transmission and distribution assets and power generating facilities, including public and employee safety issues, the risk of utility assets causing or contributing to wildfires, failure, availability, efficiency, and output of equipment and facilities, and availability and cost of spare parts;

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

•	ability of Edison International to develop competitive businesses, manage new business risks, and recover and earn a return on its investment in newly developed or acquired businesses;

•	changes in tax laws and regulations, at both the state and federal levels, or changes in the application of those laws, that could affect recorded deferred tax assets and liabilities and effective tax rate;

•	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);

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•	governmental, statutory, regulatory, or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market adopted by the NERC, CAISO, Western Electricity Council, and similar regulatory bodies in 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;

•	potential for penalties or disallowance for non-compliance with applicable laws and regulations; and

•	cost of fuel for generating facilities and related transportation, which could be impacted by, among other things, disruption of natural gas storage facilities, to the extent not recovered through regulated rate cost escalation provisions or balancing accounts.

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•	Charge of $2.5 billion ($1.8 billion after-tax) in 2018 for SCE's wildfire-related claims, net of expected recoveries from insurance and FERC customers.

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Loss of $56 million ($46 million after-tax) in 2018 for Edison International Parent and Other primarily related to sale of SoCore Energy in April 2018 and income of $21 million ($13 million after-tax) in 2017 related to losses (net of distributions) allocated to tax equity investors under the HLBV accounting method. For further information on HLBV, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."

•	Income of $12 million ($9 million after-tax) in 2018 and charge of $716 million ($448 million after-tax) in 2017 for SCE related to the Revised San Onofre Settlement Agreement. For further information, see "—Permanent Retirement of San Onofre" below.

•	Income tax expense of $12 million, an income tax benefit of $66 million and an income tax benefit of $34 million in 2018 for Edison International Parent and Other, SCE and discontinued operations, respectively, related to the settlement of the 1994 – 2006 California tax audits discussed above.

•	Charges of $433 million in 2017 for Edison International Parent and Other and $33 million for SCE from the re-measurement of deferred taxes as a result of the Tax Cuts and Jobs Act ("Tax Reform"). For further information, see "— Tax Reform" below.

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1	Includes 2018 – 2019 capital expenditures for GS&RP and 2019 WMP (see "—Grid Development" below).

2	2018 and 2019 capital expenditures related to grid modernization are included in traditional capital expenditures.

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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 earnings activities are revenue or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances.

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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. 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) and certain operation and maintenance expenses. SCE earns no return on these activities.

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1	Expenses for the years ended December 31, 2017 and 2016, respectively, were updated to reflect the implementation of the accounting standard update for net periodic benefit costs related to the defined benefit pension and other postretirement plans. For further information, see Note 1 in the "Notes to Consolidated Financial Statements."

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

•	Lower operating revenue of $51 million is primarily due to:

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A decrease of $164 million in CPUC revenue primarily from recognizing 2018 revenue based on the 2017 authorized revenue requirement, adjusted for the July 2017 cost of capital decision and the impact of Tax Reform, partially offset by the receipt of a $17 million reimbursement related to spent nuclear fuel storage costs recorded in 2018 and a $15 million refund to customers for prior overcollections of revenue recorded in 2017. See "Management Overview—

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•	An increase in FERC revenue of $44 million primarily due to $135 million of expected recoveries from customers for the FERC portion of wildfire-related claims, partially offset by a decrease in revenue due to the reduction in the federal corporate income tax rate resulting from Tax Reform.

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A decrease in revenue related to San Onofre of $223 million primarily related to the recovery of amortization of the San Onofre regulatory asset in 2017 (offset in depreciation and amortization) and authorized return as provided by the Prior San Onofre Settlement Agreement. As a result of the Revised San Onofre Settlement Agreement, there was no revenue recorded in 2018 for San Onofre other than the previously disallowed costs. See "Management Overview—Permanent Retirement of San Onofre" for further information.

•	An increase in revenue of $338 million related to tax balancing account activities (offset in income taxes below), consisting of $216 million of lower customer refunds for incremental tax repair benefits and $122 million for tax benefits related to 2017 tax accounting method changes.

•	A decrease of $75 million resulting from the amortization of excess deferred tax assets as a result of Tax Reform.

•	Higher operation and maintenance expense of $74 million primarily due to higher wildfire insurance premiums and vegetation management costs (see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides—Current Wildfire Insurance Coverage" for further information).

•	Charge of $2.7 billion recorded in 2018 for wildfire-related claims, net of expected insurance recoveries.

•	Lower depreciation and amortization expense of $165 million primarily related to the amortization of the San Onofre regulatory asset in 2017 (offset in revenue above).

•	Higher property and other taxes of $20 million primarily due to higher property assessed values in 2018.

•	Lower impairment and other of $728 million primarily related to charges recorded in 2017 due to the Revised San Onofre Settlement Agreement. See "Management Overview—Permanent Retirement of San Onofre" for further information.

•	Higher interest expense of $83 million primarily due to increased borrowings and higher interest on balancing account overcollections in 2018.

•	Higher other income and expenses of $14 million primarily due to higher AFUDC equity income. See "Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses" for further information.

•	Lower income taxes of $666 million primarily due to the following:

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Higher non-core income tax benefits of $540 million due to 2018 tax benefits of $709 million related to the charge for wildfire-related claims, $66 million related to the settlement of the 1994 – 2006 California tax audits and $33 million of 2017 tax expense related to the re-measurement of deferred taxes resulting from the implementation of Tax Reform, partially offset by tax benefits of $268 million recorded in 2017 due to charges related to the Revised San Onofre Settlement Agreement.

•	The impact of a lower federal income tax rate on pre-tax income and a true-up related to the filing of the federal income tax return of $208 million, partially offset by lower income tax benefits of $184 million due to the tax balancing account activities referred to above and the impact of Tax Reform on those activities.

•	Lower pre-tax income in 2018, excluding non-core items discussed above.

•	Higher operating revenue of $107 million is primarily due to:

•	An increase in revenue of approximately $241 million related to the increase in authorized revenue from the escalation mechanism set forth in the 2015 GRC decision and $32 million of higher operating costs subject to balancing account treatment (primarily offset in depreciation expense below). These increases were partially offset by $33 million of

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•	Energy efficiency incentive awards recognized in 2017 were $17 million compared to $5 million in 2016. During 2016, the CPUC approved a settlement agreement in which SCE agreed to refund $13 million related to incentive awards SCE received for savings achieved by its 2006 – 2008 energy efficiency programs.

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A decrease in revenue of $118 million related to tax benefits refunded to customers (offset in income taxes below). The decrease in revenue resulted from $116 million of higher year-over-year incremental tax repair benefits recognized and $135 million of benefits recognized for tax accounting method changes. These decreases were partially offset by a 2016 revenue refund to customers of $133 million related to 2012 – 2014 incremental tax repair deductions.

•	A decrease in FERC-related revenue of $39 million primarily related to higher operating costs in 2016 including amortization of the regulatory asset associated with the Coolwater-Lugo transmission project and a $8 million reduction to FERC revenue due to a change in estimate under the FERC formula rate mechanism.

•	An increase of $20 million for other operating revenue resulting from refunds to customers recorded in 2016 due to the retroactive extension of bonus depreciation in the PATH Act of 2015.

•	Lower operation and maintenance expense of $36 million primarily due to the impact of SCE's operational and service excellence initiatives and lower legal costs, partially offset by higher transmission and distribution costs for line clearing and maintenance and information technology costs.

•	Higher depreciation and amortization expense of $34 million primarily related to depreciation and amortization on transmission and distribution investments, partially offset by amortization of the regulatory asset related to Coolwater-Lugo plant recorded in 2016.

•	Higher property and other taxes of $21 million primarily due to higher property assessed values in 2017.

•	Impairment charge of $716 million in 2017 due to the Revised San Onofre Settlement Agreement (see "Management Overview—Highlights of Operating Results" for further information).

•	Higher other operating income of $8 million due to the sale of utility property.

•	Higher interest expense of $48 million primarily due to increased borrowings and higher interest on balancing account overcollections in 2017.

•	Higher other income and expenses of $19 million primarily due to higher AFUDC equity income. See "Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses" for further information.

•	Lower income taxes of $286 million primarily due to the following:

•	Higher non-core income tax benefits in 2017 of $235 million due to the impairment and other charges related to the Revised San Onofre Settlement Agreement, partially offset by $33 million income tax expense related to the re-measurement of deferred taxes resulting from the implementation of Tax Reform.

•	Higher income tax benefits in 2017 of $70 million due to $149 million related to flow through of incremental tax repair benefits and for tax accounting method changes (offset in revenue above), partially offset by $79 million flow-through of 2012 – 2014 incremental income tax benefits in 2016.

•	Higher pre-tax income in 2017, excluding non-core items discussed above.

•	Higher purchased power and fuel costs of $533 million primarily driven by higher power and gas prices and volume experienced in 2018 relative to 2017, partially offset by higher congestion revenue right credits, lower capacity costs, proceeds from contract amendments and the receipt of funds in 2018 from counterparties related to the California energy crisis.

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•	Lower operation and maintenance expense subject to balancing accounts of $94 million primarily driven by reduced spending on energy efficiency programs and the timing of revenue recognition associated with costs tracked through memorandum accounts, partially offset by higher transmission access charges.

•	Higher other income and expenses of $32 million primarily driven by higher net periodic benefit income related to the non-service cost components in 2018 relative to 2017. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for further information.

•	Higher purchased power and fuel costs of $346 million primarily driven by higher power and gas prices experienced in 2017 relative to 2016, partially offset by lower realized losses on hedging activities ($14 million in 2017 compared to $59 million in 2016) and lower capacity costs.

•	Lower operation and maintenance expense of $14 million primarily driven by lower employee benefit and other labor costs and lower spending on various public purpose programs, partially offset by an increase in transmission and distribution costs for line clearing and maintenance activities.

•	Higher other income and expenses of $15 million primarily driven by higher net periodic benefit income related to the non-service cost components in 2017 relative to 2016. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for further information.

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Lower income tax expense in 2018 primarily due to $433 million of tax expense recorded in 2017 related to the re-measurement of deferred taxes that resulted from Tax Reform, partially offset by income tax benefits of $44 million recorded in 2017 related to stock option exercises, $17 million of tax benefits recorded in 2017 related to net loss carrybacks from the filing of the 2016 tax returns, $6 million of tax benefits recorded in 2017 related to the settlement of 2007 – 2012 federal income tax audits and the impact of Tax Reform on pre-tax losses. In addition, income tax expense of $12 million of tax expense was recorded in 2018 related to the settlement of the 1994 – 2006 California tax audits, offset by a reduction in uncertain tax positions that resulted from this settlement.

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Increase in losses of $44 million due to the impact from the April 2018 sale of SoCore Energy, partially offset by a goodwill impairment recorded in 2017 on the SoCore Energy reporting unit. The higher losses included lower HLBV income, partially offset by a reduction in losses due to the exit of this business activity in 2018. In addition, Edison Energy Group's 2018 results included a $13 million after-tax goodwill impairment charge on the Edison Energy reporting unit.

•	Income tax expense of $433 million in 2017 from the re-measurement of deferred taxes as a result of Tax Reform.

•	Higher income tax benefits related to stock option exercises of $30 million for the year ended December 31, 2017, $17 million of tax benefits recorded in 2017 from net operating loss carrybacks that resulted from the filing of the 2016 tax returns and $6 million of tax benefits recorded in 2017 related to settlement with the IRS for taxable years 2007 – 2012.

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Edison Energy Group's 2017 results included HLBV income of $13 million, a $10 million after-tax goodwill impairment charge on the SoCore Energy reporting unit and net tax expense of $5 million from a change in tax law partially offset by tax benefits primarily related to stock option exercises. Edison Energy Group's 2016 results included HLBV income of $5 million, $13 million after-tax charge in 2016 from a buy-out of an earn-out provision contained in one of the 2015 acquisitions and net tax benefits of $5 million primarily related to stock option exercises. Excluding these items, Edison Energy Group net losses were $24 million in 2017 and $35 million in 2016. The reduction in these losses was due to lower expenses related to new business activities. Revenue for the Edison Energy Group was $69 million and $42 million for the years ended December 31, 2017 and 2016, respectively. The increase in revenue was primarily due to higher build transfer projects from SoCore Energy in 2017.

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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 forecast discussed in "Management Overview—Capital Program."

2	SCE is unable to predict the timing of a final CPUC decision, and the corresponding in-service date, in connection with the Alberhill System Project.

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1	Net collateral provided to counterparties and other brokers consisted $191 million in letters of credit and surety bonds and $7 million of cash which was offset against net derivative liabilities on the consolidated balance sheets.

2	If SCE's credit ratings were to fall below investment grade as of December 31, 2018, SCE may also be required to post up to $50 million in collateral by April 30, 2019 related to environmental remediation obligations.

3	Incremental collateral requirements were based on potential changes in SCE's forward positions as of December 31, 2018 due to adverse market price movements over the remaining lives of the existing power contracts using a 95% confidence level.

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1	Net cash for the years ended December 31, 2017 and 2016 was updated to reflect the implementation of the accounting standards updates for cash flows related to cash receipts and restricted cash. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."

1	Non-cash items include depreciation and amortization, allowance for equity during construction, impairment and other, deferred income taxes and investment tax credits and other.

2	Changes in working capital items include receivables, inventory, amortization of prepaid expenses, accounts payable, tax receivables and payables, and other current assets and liabilities.

3	Includes an increase of $4.7 billion in liabilities for wildfire-related claims and an increase of $2.0 billion in insurance receivables in 2018 (offset in net loss above), and nuclear decommissioning trusts. See "Nuclear Decommissioning Activities" below for further information.

4	Cash flow for the years ended December 31, 2017 and 2016 was updated to reflect the implementation of the accounting standards updates for cash flows related to cash receipts and restricted cash. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."

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•	BRRBA overcollections increased by $428 million primarily due to a $263 million reclassification of 2017 incremental tax benefits from TAMA to BRRBA (to be refunded in 2019) and higher sales than forecasted in rates, partially offset by a refund of 2016 incremental tax benefits.

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Higher cash from increased regulatory liabilities of approximately $365 million primarily due to the delay in the 2018 GRC decision. During 2018, the amounts billed to customers were largely based on the 2017 authorized GRC revenue requirement, however, the amount of revenue recognized has been adjusted mainly for the July 2017 cost of capital decision and Tax Reform pending the outcome of the 2018 GRC and therefore, a regulatory liability has been established to record any associated adjustments.

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Net undercollections for ERRA and the new system generation program were $741 million and $267 million at December 31, 2018 and 2017, respectively. Net undercollections increased $474 million during 2018 primarily due to an increase in costs due to higher than forecasted power and gas prices experienced in 2018 and higher load requirements than forecasted in rates, partially offset by an increase in cash due to recovery of prior year undercollections.

•	TAMA overcollections decreased by $287 million primarily due to a $263 million reclassification from TAMA to BRRBA to refund customers as discussed above.

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Undercollections of $128 million related to the establishment, in the fourth quarter of 2018, of a wildfire expense memorandum account ("WEMA") to track wildfire related costs including insurance premiums in excess of the amounts that will be ultimately approved in the 2018 GRC decision. For further information, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides."

•	TAMA overcollections increased by $117 million during 2017 primarily due to higher tax repair deductions than forecasted in rates and $135 million of higher benefits recognized for tax accounting method changes, partially offset by a $226 million reclassification from TAMA to BRRBA to refund customers.

•	Higher cash due to $153 million of overcollections for the public purpose and energy efficiency programs. The increase in cash was due to lower spending than billed to customers and recovery of prior year undercollections.

•	Higher cash due to $136 million of overcollections related to FERC balancing accounts. The increase in cash was due to recovery of prior FERC undercollections and lower costs than previously forecasted.

•	Higher cash due to proceeds of approximately $34 million from the Department of Energy related to spent nuclear fuel. For further information on the spent nuclear fuel, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Spent Nuclear Fuel."

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BRRBA overcollections decreased by $226 million during 2017 primarily due to the refunds of 2015 TAMA overcollections, a revenue refund to customers of $133 million for 2012 – 2014 incremental tax benefits related to repair deductions, and 2015 overcollections resulting from the implementation of the 2015 GRC decision, which was authorized to be refunded to customers over a two year period, partially offset by a $226 million reclassification from TAMA to BRRBA to refund customers in January 2018 as discussed above.

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Net undercollections for ERRA and the new system generation program were $267 million at December 31, 2017 compared to net overcollections of $26 million at December 31, 2016. Lower cash due to $293 million of net undercollections in 2017 primarily due to a refund of prior year overcollections and an increase in costs due to higher than forecasted power and gas prices experienced in 2017 and higher load requirements than forecasted in rates.

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•	Lower cash due to a decrease in ERRA overcollections for fuel and purchased power of $419 million in 2016 primarily due to the implementation of the 2016 ERRA rate decrease in January 2016, partially offset by lower than forecasted power and gas prices experienced in 2016.

•	The public purpose and energy efficiency programs track differences between amounts authorized by the CPUC and amounts incurred to fund programs established by the CPUC. Overcollections increased by $309 million in 2016 due to higher funding and lower spending for these programs.

•	SCE had a decrease in cash of approximately $182 million primarily due to a 2016 refund of 2015 overcollections resulting from the implementation of the 2015 GRC decision which was authorized to be refunded to customers over a two year period.

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1	Net cash for the years ended 2017 and 2016 was updated to reflect the implementation of the accounting standards updates for cash flows related to cash receipts and restricted cash. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."

•	$92 million, $138 million and $32 million cash outflow from operating activities in 2018, 2017 and 2016, respectively, due to payments and receipts relating to interest and operating costs. In addition, the cash outflow in 2017 included higher pension payments related to executive retirement plans.

•	$78 million inflow in 2018 primarily related to federal income tax refunds.

•	$214 million of cash payments made to the Reorganization Trust in September 2016 related to the EME Settlement Agreement.

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1	For additional details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Amount includes interest payments totaling $10.4 billion and $305 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. For further discussion, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."

3	At December 31, 2018, SCE's minimum other operating lease payments were primarily related to vehicles, office space and other equipment. For further discussion, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."

4	For additional details, see "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies." At December 31, 2018, other commitments were primarily related to maintaining reliability and expanding SCE's transmission and distribution system and nuclear fuel supply contracts.

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At December 31, 2018, Edison International Parent and Other and SCE had estimated contributions to the pension and PBOP plans. SCE estimated contributions are $80 million, $76 million, $76 million, $88 million and $169 million in 2019, 2020, 2021, 2022 and 2023, respectively, which are excluded from the table above. Edison International Parent and Other estimated contributions are $27 million, $20 million, $26 million, $26 million and $23 million for the same respective periods and are excluded from the table above. These amounts represent estimates that are based on assumptions that are subject to change. See "Notes to Consolidated Financial Statements—Note 9. Compensation and Benefit Plans" for further information.

6	At December 31, 2018, Edison International and SCE had a total net liability recorded for uncertain tax positions of $338 million and $249 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 tax authorities.

7	The contractual obligations table does not include derivative obligations and asset retirement obligations, which are discussed in "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments," and "—Note 1. Summary of Significant Accounting Policies", respectively.

8	At December 31, 2018, SCE is required to make early termination payments for two amended power purchase agreements. SCE's termination payments are $100 million, $77 million and $29 million in 2019, 2020, and 2021, respectively, which are excluded from the table above. See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies" for further information.

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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 credit ratings from S&P or Moody's. The 2017 credit rating reflects the lower of the ratings from the three major credit rating agencies (S&P, Moody's and Fitch).

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.

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Decommissioning Costs. The estimated costs for labor, "material, equipment and other," and low-level radioactive waste costs are included in each of the NRC decommissioning stages; license termination, site restoration, and spent fuel storage. The liability to decommission SCE's nuclear power facilities is based on a 2017 decommissioning study that was filed as part of the 2018 NDTCP for San Onofre Units 1, 2, and 3, with revisions to the cost estimate in 2018 for San Onofre Units 2 and 3 and a 2016 decommissioning study for Palo Verde, with revisions to the cost estimate in 2017. SCE revised the ARO for San Onofre Units 2 and 3 due to increases in decommissioning cost estimates in 2018, related to the impact of operational uncertainties, and in 2017, related to changes to onboarding the general contractor at San Onofre.

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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, and low-level radioactive waste burial costs. SCE's current estimates are based upon SCE's decommissioning cost methodology used for ratemaking purposes. Average escalation rates range from 2.2% to 7.5% (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. Initial decommissioning activities at San Onofre Unit 1 started in 1999 and at Units 2 and 3 in 2013. Cost estimates for San Onofre Units are currently based on completion of decommissioning activities by 2051.

•	Spent Fuel Dry Storage Costs. Cost estimates are based on an assumption that the DOE will begin to take spent fuel from the nuclear industry in 2028, and will remove the last spent fuel from the San Onofre and Palo Verde sites by 2049 and 2078, 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.

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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 5.3% rate of return on plan assets above is determined on an after-tax basis. Actual time-weighted, annualized (losses) returns on the pension plan assets were (2.4)%, 5.9% and 10.1% for the one-year, five-year and ten-year periods ended December 31, 2018, respectively. Actual time-weighted, annualized (losses) returns on the PBOP plan assets were (4.78)%, 4.86% and 9.2% 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 2029 and beyond.

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1	Reflected in "Other current assets" on Edison International's and SCE's consolidated balance sheets.

2	Reflected in "Other long-term assets" on Edison International's consolidated balance sheets.

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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	Due to the loss reported for the year ended December 31, 2018, incremental shares were not included as the effect would be antidilutive.

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1	Represents the netting of assets and liabilities under master netting agreements and cash collateral.

2	Approximately 71% and 69% of SCE's equity investments were located in the United States at December 31, 2018 and 2017, respectively.

3	Includes corporate bonds, which were diversified and included collateralized mortgage obligations and other asset backed securities of $67 million and $102 million at December 31, 2018 and 2017, respectively.

4	Excludes net payables of $143 million and $59 million at December 31, 2018 and 2017, respectively, which consist of interest and dividend receivables as well as receivables and payables related to SCE's pending securities sales and purchases.

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

3	During the third quarter of 2017, SCE designated certain derivative contracts as normal purchase and normal sale contracts, which resulted in a reclassification of $914 million from derivative liabilities to other liabilities. These liabilities are amortized over the remaining contract terms.

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1	Carrying value is net of debt issuance costs.

2	The fair value of Edison International's and SCE's short-term and long-term debt is classified as Level 2.

1	Includes $29 million of long-term debt as of December 31, 2017 for SoCore Energy, which was sold in April 2018. See Note 1 for further details on the sale of SoCore Energy.

2	Balance as of December 31, 2017 excludes outstanding bonds due in 2031 that may be remarketed to investors in the future. These bonds were retired in April 2018.

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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 earnings activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances.

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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. 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), and certain operation and maintenance expenses. SCE earns no return on these activities.

1	During the year ended December 31, 2018, SCE recorded CPUC revenue based on the 2017 authorized revenue requirements adjusted for the July 2017 cost of capital decision and Tax Reform pending the outcome of the 2018 GRC. These revenue adjustments are included in "Revenues from contracts with customers." For further information, see Note 1.

2	At December 31, 2018 and 2017, SCE's receivables related to contracts from customers were $1.1 billion and $825 million, respectively, which include accrued unbilled revenue of $482 million and $212 million, respectively.

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1	In the fourth quarter of 2018, Edison International and SCE recognized tax benefits related to a settlement with the California Franchise Tax Board for tax years 1994 – 2006. See further discussion in Tax Disputes below.

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1	Relates to a charge recorded for wildfire-related claims, net of expected recoveries from insurance and FERC customers. For further information, see Note 12.

2	As of December 31, 2018, deferred tax assets for net operating loss and tax credit carryforwards are reduced by unrecognized tax benefits of $178 million and $97 million for Edison International and SCE, respectively.

4	As of December 31, 2018 Edison International has recorded a valuation allowance of $32 million for non-California state net operating loss carryforwards and $4 million for California capital loss generated from sale of SoCore Energy in 2018, which are estimated to expire before being utilized.

5	Included in deferred income taxes and credits on the consolidated balance sheets.

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4	Includes state taxes of $(11) million and $(4) million for Edison International and $(2) million and $(1) million for SCE for the years ended December 31, 2017 and 2016, respectively.

5	In 2017, Edison International and SCE recorded a charge to earnings related to the re-measurement of deferred taxes resulting from Tax Reform. See further discussion above.

1

Decrease in 2018 was related to re-measurement as a result of a settlement with the California Franchise Tax Board for tax years 1994 – 2006. Decrease in 2016 was related to state tax receivables on various claims. Due to the tax risks associated with these claims, the tax benefits were fully reserved at the time the asset was recorded. During 2016, the Company determined that it will not recognize these assets, so the tax benefit and related tax reserve were written off.

2	In 2018, Edison International reached a settlement with the California Franchise Tax Board for tax years 1994 – 2006. In 2017, Edison International settled all open tax positions with the IRS for taxable years 2007 – 2012. See Tax Disputes below for further details.

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1

The SCE liability excludes a long-term payable due to Edison International Parent of $117 million and $114 million at December 31, 2018 and 2017, respectively, related to certain SCE postretirement benefit obligations transferred to Edison International Parent. SCE's accumulated other comprehensive loss of $17 million and $21 million at December 31, 2018 and 2017, respectively, excludes net loss of $21 million and $19 million related to these benefits.

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1

Under GAAP, a settlement is recorded when lump-sum payments exceed estimated annual service and interest costs. Lump sum payments made in 2017 to Edison International executives retiring in 2016 from the Executive Retirement Plan exceeded the estimated service and interest costs, resulting in a partial settlement of that plan. A settlement loss of approximately $6.4 million ($3.8 million after-tax) was recorded at Edison International for the year ended December 31, 2017.

2	Includes the amount of net loss reclassified from accumulated other comprehensive loss. The amount reclassified for Edison International was $9 million, $10 million and $10 million for the years ended December 31, 2018, 2017 and 2016, respectively. The amount reclassified for SCE was $6 million for all the years ended December 31, 2018, 2017 and 2016.

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1	The amount of net loss expected to be reclassified from accumulated other comprehensive loss for Edison International and SCE is $8 million and $6 million, respectively.

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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.

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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.

•	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	These investments are measured at fair value using the net asset value per share practical expedient and have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the net plan assets available for benefits.

2	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.

3	Corporate stocks are diversified. At December 31, 2018 and 2017, respectively, performance for actively managed separate accounts is primarily benchmarked against the Russell Indexes (43%) and (54%) and Morgan Stanley Capital International (MSCI) index (57%) and (46%).

4	Corporate bonds are diversified. At December 31, 2018 and 2017, respectively, this category includes $60 million and $65 million for collateralized mortgage obligations and other asset backed securities.

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5

At December 31, 2018 and 2017, respectively, the common/collective assets were invested in equity index funds that seek to track performance of the Standard and Poor's 500 Index (43% and 41%) and Russell 1000 indexes (14% and 15%). In addition, at December 31, 2018 and 2017, respectively, 21% and 15% of the assets in this category are in index funds which seek to track performance in the MSCI All Country World Index exUS and 15% and 25% of this category are in non-index U.S. equity fund, which is actively managed.

6	At December 31, 2018 and 2017, respectively, 50% and 55% are invested in private equity funds with investment strategies that include branded consumer products, clean technology and California geographic focus companies, 30% and 20% are invested in a broad range of financial assets in all global markets, and 16% and 23% are invested in publicly traded fixed income securities.

7	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.

8	Level 1 registered investment companies primarily consisted of a global equity mutual fund which seeks to outperform the MSCI World Total Return Index.

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1	These investments are measured at fair value using the net asset value per share practical expedient and have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the net plan assets available for benefits.

2	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.

3	Corporate stock performance for actively managed separate accounts is primarily benchmarked against the Russell Indexes (67% and 64%) and the MSCI All Country World Index (33% and 36%) for 2018 and 2017, respectively.

4	Corporate notes and bonds are diversified and include approximately $59 million and $36 million for commercial collateralized mortgage obligations and other asset backed securities at December 31, 2018 and 2017, respectively.

5	At December 31, 2018 and 2017, respectively, 74% and 75% of the common/collective assets are invested in index funds which seek to track performance in the MSCI All Country World Index Investable Market Index and 19% and 17% are invested in a non-index U.S. equity fund which is actively managed. The remaining assets in this category are primarily invested in emerging market fund.

6

At December 31, 2018 and 2017, respectively, 48% and 56% of the partnerships are invested in private equity and venture capital funds. Investment strategies for these funds include branded consumer products, clean and information technology and healthcare. 34% and 33% are invested in a broad range of financial assets in all global markets. 17% and 9% of the remaining partnerships category are invested in asset backed securities including distressed mortgages, distressed companies and commercial and residential loans and debt and equity of banks.

7	At both December 31, 2018 and 2017, registered investment companies were primarily invested in (1) a money market fund, (2) exchange rate trade funds which seek to track performance of MSCI Emerging Market Index, Russell 2000 Index, and international small cap equities.

8	Other includes $58 million and $60 million of municipal securities at December 31, 2018 and 2017, 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 2019 as performance targets were met at December 31, 2018.

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1	Short-term investments include $71 million and $29 million of repurchase agreements payable by financial institutions which earn interest, are fully secured by U.S. Treasury securities and mature by January 2, 2019 and January 2, 2018 as of December 31, 2018 and 2017, respectively.

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1	In 2018, SCE amended the termination date of two power purchase agreements. As a result of this amendment, SCE is required to make early termination payments of $100 million in 2019, $77 million in 2020 and $29 million in 2021, which were reflected as a regulatory asset in the consolidated balance sheets as of December 31, 2018.

2	Relates to a regulatory asset that earns a rate of return. See below for further information.

3

In accordance with the Revised San Onofre Settlement Agreement, SCE wrote down the San Onofre regulatory asset in 2017 and applied $72 million of the U.S. Department of Energy ("DOE") proceeds, previously reflected as a regulatory liability in the DOE litigation memorandum account, against the remaining San Onofre regulatory asset during the third quarter of 2018. See Note 12 for further information.

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1

During 2018, SCE recorded CPUC revenue based on the 2017 authorized revenue requirement adjusted for the July 2017 cost of capital decision and Tax Reform pending the outcome of the 2018 GRC. SCE recorded regulatory liabilities primarily associated with these adjustments. The CPUC has authorized the establishment of a GRC memorandum account, which will make the 2018 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2018. For further information, see Note 1.

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1

Energy resource recovery account ("ERRA") balancing account is subject to a trigger mechanism that allows SCE to request an expeditious rate change if the ERRA balancing account overcollection or undercollection either exceeds 5% of SCE's prior year generation rate revenue or exceeds 4% of SCE's prior year generation rate revenue and SCE does not expect the overcollection or undercollection to fall below 4% within 120 days. For 2019, the 4% and 5% trigger amounts are approximately $213 million and $266 million, respectively. SCE anticipates to recover the ERRA undercollection from customer in rates beginning in April 2019. For further information of ERRA trigger mechanism, see "Business—SCE—Overview of Ratemaking Process."

2	During 2018, $263 million of 2017 incremental tax benefits were reclassified from the tax accounting memorandum account to the base revenue requirement balancing account (to be refunded to customers in 2019).

3	During 2018, the CPUC established a wildfire expense memorandum account ("WEMA") to track wildfire-related costs including insurance premiums in excess of amounts that ultimately will be approved in the 2018 GRC decision. See Note 12 for further information.

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1	These items are included in the computation of net periodic pension and PBOP expenses. See Note 9 for additional information.

2	Edison International and SCE recognized cumulative effect adjustments to the opening balance of retained earnings and accumulated other comprehensive loss on January 1, 2018 related to the adoption of the accounting standards update on the measurement of financial instruments. See Note 1 for further information.

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1	In the fourth quarter of 2018, SCE recorded a charge of $2.5 billion for wildfire-related claims, net of expected recoveries from insurance and FERC customers.

1	Expenses were updated to reflect the implementation of the accounting standard update for net periodic benefit costs related to the defined benefit pension and other postretirement plans. See Note 1 for further information.

2	In the fourth quarter of 2017, Edison International Parent and Other recorded a charge of $433 million related to the re-measurement of deferred taxes as a result of Tax Reform.

3	In the fourth quarter of 2017, SCE recorded an impairment charge of $716 million ($448 million after-tax) related to the Revised San Onofre Settlement Agreement.

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1	In the fourth quarter of 2018, SCE recorded a charge of $2.5 billion for wildfire-related claims, net of expected recoveries from insurance and FERC customers.

1	Expenses were updated to reflect the implementation of the accounting standard update for net periodic benefit costs related to the defined benefit pension and other postretirement plans. See Note 1 for further information.

2	In the fourth quarter of 2017, SCE recorded an impairment charge of $716 million ($448 million after-tax) related to the Revised San Onofre Settlement Agreement.

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1	Effective January 1, 2018, Edison International and SCE adopted an accounting standards update on revenue recognition, using the modified retrospective method. As a result, prior period amounts were not adjusted to reflect the adoption of this standard. For further information, see Note 1 in the "Notes to Consolidated Financial Statements."

2	Expenses for the years ended December 31, 2017, 2016, 2015 and 2014 were updated to reflect the implementation of the accounting standard update for net periodic benefit costs related to the defined benefit pension and other postretirement plans. For further information, see Note 1 in the "Notes to Consolidated Financial Statements."

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4	Effective December 31, 2015, Edison International and SCE adopted an accounting standard, retrospectively, that requires all deferred income tax assets and liabilities be presented as noncurrent in the consolidated balance sheet.

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1	In addition to the 33 hydroelectric plants, includes 2 small generators representing an aggregate capacity of 1 MW.

2	Pebbly Beach Generating Station consists of 11 MW of diesel generators and liquid petroleum gas micro-turbines and a 1 MW of battery system.

3	Each enhanced peaker plant consists of one 49.9 MW gas turbine supported by a 10 MW battery storage system.

4	Arizona Public Service, an investor-owned electric utility.

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1	EME Reorg Trust was an entity formed as part of the EME bankruptcy to hold creditors' interests after the sale of EME's assets to NRG and is not a parent, affiliate or subsidiary of SCE.

2	EME is a wholly-owned subsidiary of Edison International and an affiliate of SCE. EME filed for bankruptcy on December 17, 2012.

3	Akin Gump Strauss Hauer & Feld is a global law firm and is not a parent, affiliate or subsidiary of Edison International.

4	Macquarie Infrastructure and Real Assets is a global infrastructure management company and is not a parent, affiliate or subsidiary of Edison International.

5	Los Angeles Department of Water and Power is a municipal water and power utility company and is not a parent, affiliate or subsidiary of Edison International.

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1	Los Angeles Department of Water and Power is a municipal water and power utility company and is not a parent, affiliate or subsidiary of SCE.

2	EME is a wholly-owned subsidiary of Edison International and an affiliate of SCE. EME filed for bankruptcy on December 17, 2012.

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1

This amount includes 8,833,610 shares covered by outstanding stock options, 311,384 shares covered by outstanding restricted stock unit awards, and 163,324 shares covered by outstanding deferred stock unit awards, with the outstanding shares covered by outstanding restricted stock unit and deferred stock unit awards including the crediting of dividend equivalents through December 31, 2018. The weighted-average exercise price of awards outstanding under equity compensation plans 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 awards outstanding have no exercise price. Awards payable solely in cash are not reflected in this table.

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, 2018. The maximum number of shares of Edison International Common Stock that may be issued or transferred pursuant to awards under the Edison International 2007 Performance Incentive Plan is 71,031,524. 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.

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

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

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a	Accounts written off, net.

b	In 2016, Edison International determined that $8 million of the assets subject to a valuation allowance had no expectation of recovery and were written off.

c	During 2018, Edison International recorded an additional valuation allowance of $4 million for non-California state net operating loss carryforwards and $4 million for California capital loss generated from the April 2018 sale of SoCore Energy, which are estimated to expire before being utilized. The additional valuation allowance in 2017 was a result of Tax Reform.

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a	Accounts written off, net.

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