Edison International (EIX) 10-K2019 FY Annual report

This is a combined Form 10-K separately filed by Edison International and Southern California Edison Company. Information contained herein relating to an individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.

Edison International's earnings are prepared in accordance with GAAP. Management uses core earnings (losses) internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the company's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as earnings attributable to Edison International shareholders less non-core

items. Non-core items include income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as write downs, asset impairments and other income and expense related to changes in law, outcomes in tax, regulatory or legal proceedings, and exit activities, including sale of certain assets and other activities that are no longer continuing.

Edison International's 2019 earnings increased $1,707 million, driven by an increase in SCE's earnings of $1,719 million and a decrease in Edison International Parent and Other losses of $22 million, partially offset by $34 million of income from discontinued operations in 2018. SCE's higher net income consisted of $1,457 million of lower non-core losses and $262 million of higher core earnings.

The increase in core earnings was due to the adoption of the 2018 GRC final decision in 2019, higher FERC revenue due to the settlement of SCE's 2018 Formula Rate proceeding and rate base growth, and the timing of regulatory deferral and cost recovery of incremental wildfire insurance expenses. These increases were partially offset by higher inspection, preventive maintenance and vegetation management costs that were not deferred as regulatory assets.

Edison International Parent and Other losses from continuing operations for 2019 consisted of $18 million of higher core losses and $40 million of lower non-core losses. The increase in core losses in 2019 was primarily due to higher interest expense and lower income tax benefits, partially offset by lower losses from the competitive businesses under Edison Energy Group.

See "Results of Operations" for discussion of SCE and Edison International Parent and Other results of operations.

In September 2018, SCE filed an application with the CPUC requesting approval of a GS&RP to implement additional wildfire safety measures, including measures to further harden SCE's infrastructure to significantly reduce potential fire ignition sources, bolster SCE's situational awareness capabilities to more fully assess and respond to potential wildfire conditions, and enhance SCE's operational practices to further strengthen fire safety measures and system resiliency. In its GS&RP application, SCE proposed to spend approximately $582 million ($407 million capital) in 2018 dollars between 2018 and 2020 in excess of amounts authorized in SCE's 2018 GRC and requested a balancing account to recover the incremental costs of implementing the program. In January 2019, the CPUC approved the establishment of an interim memorandum account to track GS&RP costs while the CPUC considers SCE's application. There is no assurance that SCE will be allowed to ultimately recover these costs.

Under AB 1054, SCE is required to submit a wildfire mitigation plan to the CPUC annually for review and approval. SCE's WMPs describe strategies, programs and activities that are in place, being implemented or are under development by SCE, including associated cost estimates, to proactively address and mitigate the threat of electrical infrastructure-associated ignitions that could lead to wildfires. Beginning in 2020, each WMP is required to cover at least a three-year period.

In May 2019, the CPUC approved SCE's 2019 WMP, however, such approval does not authorize the associated spending. The CPUC decision required SCE to meet certain reporting requirements, capture data, and improve its metrics for evaluating performance. During 2019 SCE recorded $307 million of expenses in the WMP memorandum account. During 2019, WMP capital expenditures not authorized in the 2018 GRC or contemplated in the GS&RP proceedings were $335 million. Forecasted 2020 WMP direct costs not authorized in the 2018 GRC or contemplated in the GS&RP proceedings are $557 million, of which $244 million is capital.

The WMP memorandum account will be subject to a subsequent reasonableness review through separate tracks of the 2021 GRC.

The FHPMA was established to record the costs incurred related to fire hazard prevention in compliance with decisions from the CPUC. SCE has used the FHPMA to track incremental vegetation management activities to reduce the risk of fires. As of December 31, 2019, operation and maintenance expenses of $198 million have been recorded to the FHPMA.

The FHPMA is expected to be subject to a subsequent reasonableness review through separate tracks of the 2021 GRC.

SCE tracks insurance premium costs related to wildfire liability insurance policies as well as other wildfire-related costs in its WEMA. In July 2019, SCE filed a WEMA application with the CPUC to seek recovery of $478 million in wildfire insurance premium costs incurred in excess of premiums approved in the 2018 GRC. As of December 31, 2019, SCE has recognized $341 million of regulatory assets in the WEMA related to incremental wildfire insurance costs.

In May 2019, the CPUC approved a final decision in SCE's 2018 GRC. The final decision authorized a revenue requirement of $5.1 billion for 2018 and identified changes to certain balancing accounts, including the expansion of the TAMA to include the impacts of all differences between forecast and recorded tax expense. The final decision also disallowed certain historical spending, largely related to specific pole replacements the CPUC determined were performed prematurely.

The final decision allows a post-test year rate making mechanism that escalates capital additions by 2.49% for both 2019 and 2020. It also allows operation and maintenance expenses to be escalated for 2019 and 2020 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology set forth in the final decision results in a revenue requirement of $5.5 billion in 2019 and $5.9 billion in 2020.

The revenue requirements in the 2018 GRC final decision are retroactive to January 1, 2018. SCE recorded the prior period impact of the 2018 GRC final decision in 2019, including an increase to core earnings of $131 million from the application of the decision to revenue, depreciation expense and income tax expense and a non-core impairment of utility property, plant and equipment of $170 million ($123 million after-tax) related to disallowed historical capital expenditures. See "Results of Operations—SCE" and "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies" for further information.

In December 2019, the FERC approved a settlement on SCE's formula rates for the 2018 Formula Rate case that established SCE's FERC transmission revenue requirement for the FERC 2018 Settlement Period. The settlement provides for a weighted average ROE of 11.2%, which includes a previously authorized 50 basis point incentive for CAISO participation and individual and previously authorized project incentives. Under the settlement, if the FERC issues a final, unappealable ruling that finds SCE is not eligible for the 50 basis point incentive for CAISO participation, then the ROE for the FERC 2018 Settlement Period will be reduced to 10.7%. Prior to the settlement, SCE had been recognizing revenue during the FERC 2018 Settlement Period based on its expectations of the outcome of the 2018 Formula Rate case. Regulatory assets and liabilities were adjusted based on the settlement of the 2018 Formula Rate case, which resulted in an increase in net income of $29 million related to 2018, being recorded in 2019. The transmission revenue requirement and rates that have been billed to customers for the FERC 2018 Settlement Period were based on a total FERC weighted average ROE of 11.58%, and SCE expects to refund excess amounts billed to customers during 2020. In the 2019 Formula Rate case, SCE's requested base

return on equity, as modified by a partial settlement approved by the FERC, is 11.97% ("FERC Base ROE"). This ROE request reflects a conventional ROE of 11.12% and an additional ROE of 0.85% to compensate investors for current wildfire risk. As with SCE's requested ROE in its 2020 CPUC Cost of Capital proceeding, this request reflects the anticipated impact of AB 1054 on SCE's requested ROE. SCE's total ROE request, inclusive of project incentives and a 0.5% incentive for CAISO participation, would be approximately 13.25%. The 2019 Formula Rate was implemented in rates in November 2019 and remains subject to hearing and settlement procedures. Amounts billed to customers under the 2019 Formula Rate will be subject to refund until the 2019 Formula Rate proceeding is ultimately resolved.

Multiple factors have contributed to increased wildfire activity, and faster progression of and increased damage from wildfires across SCE's service territory and throughout California. These include the buildup of dry vegetation in areas severely impacted by years of historic drought, lack of adequate clearing of hazardous fuels by responsible parties, higher temperatures, lower humidity, and strong Santa Ana winds. At the same time that wildfire risk has been increasing in Southern California, residential and commercial development has occurred and is occurring in some of the highest-risk areas. Such factors can increase the likelihood and extent of wildfires. SCE has determined that approximately 27% of its service territory is in areas identified as high fire risk.

Edison International and SCE recorded a charge of $255 million as of December 31, 2019 for wildfire-related claims, net of expected insurance recoveries. The 2019 charge consists of an increase in estimated losses for claims related to the 2017/2018 Wildfire/Mudslide Events of $232 million, against which SCE has recorded expected recoveries through FERC electric rates of $14 million. The resulting charge was $218 million ($157 million after-tax). The fourth quarter 2019 charge also includes $23 million ($17 million after-tax) of expenses primarily associated with self-insured retention for fires that occurred in Southern California in 2019.

The investigating government agencies, the VCFD and CAL FIRE, have determined that the largest of the 2017 fires originated on December 4, 2017, in the Anlauf Canyon area of Ventura County (the investigating agencies refer to this fire as the "Thomas Fire"), followed shortly thereafter by the Koenigstein Fire. While the progression of these two fires remains under review, the December 4, 2017 fires eventually burned substantial acreage in both Ventura and Santa Barbara Counties. The largest of the November 2018 fires, known as the Woolsey Fire, originated in Ventura County and burned acreage in both Ventura and Los Angeles Counties.

In March 2019, the VCFD and CAL FIRE jointly issued separate reports finding that the Thomas Fire and the Koenigstein Fire were each caused by SCE equipment. At this time, based on available information, SCE has not determined whether its equipment caused the Thomas Fire. Based on publicly available radar data showing a smoke plume in the Anlauf Canyon area emerging in advance of the start time of the Thomas Fire indicated in the Thomas Fire report, SCE believes that the Thomas Fire started at least 12 minutes prior to any issue involving SCE's system and at least 15 minutes prior to the start time indicated in the report. SCE has previously disclosed that SCE believed its equipment was associated with the ignition

of the Koenigstein Fire. SCE is continuing to assess the progression of the Thomas and Koenigstein Fires and the extent of damages that may be attributable to each fire.

SCE has received a non-final redacted draft of a report from the VCFD subject to a protective order in the litigation related to the Woolsey fire and, other than the information disclosed in this Form 10-K, is not authorized to release the report or its contents to the public at this time. The draft report states that the VCFD investigation team determined that electrical equipment owned and operated by SCE was the cause of the Woolsey Fire. Absent additional evidence, SCE believes that it is likely that its equipment was associated with the ignition of the Woolsey Fire.

Multiple lawsuits related to the Thomas and Koenigstein Fires and the Woolsey Fire have been initiated against SCE and Edison International. Some of the Thomas and Koenigstein Fires lawsuits claim that SCE and Edison International have responsibility for the damages caused by the Montecito Mudslides based on a theory alleging that SCE has responsibility for the Thomas and/or Koenigstein Fires and that the Thomas and/or Koenigstein Fires proximately caused the Montecito Mudslides.

Edison International and SCE will seek to offset any actual losses realized in connection with the 2017/2018 Wildfire/Mudslide Events with recoveries from insurance policies in place at the time of the events and, to the extent actual losses exceed insurance, through electric rates. As of December 31, 2019, Edison International and SCE have remaining expected recoveries from insurance of $1.7 billion and expected recoveries through FERC electric rates of $149 million on their consolidated balance sheets related to the 2017/2018 Wildfire/Mudslide Events. SCE believes that, in light of the CPUC's decision in a cost recovery proceeding involving SDG&E arising from several 2007 wildfires in SDG&E's service area, there is substantial uncertainty regarding how the CPUC will interpret and apply its prudency standard to an investor-owned utility in future wildfire cost-recovery proceedings for fires ignited prior to July 12, 2019. Accordingly, while the CPUC has not made a determination regarding SCE's prudency relative to any of the 2017/2018 Wildfire/Mudslide Events, SCE is unable to conclude, at this time, that uninsured CPUC-jurisdictional wildfire-related costs are probable of recovery through electric rates.

In July 2019, AB 1054 was signed by the Governor of California and became effective immediately. The summary of the wildfire legislation in this report is based on SCE's interpretation of the legislation and is qualified in its entirety by, and should be read together with, AB 1054 and companion Assembly Bill 111.

AB 1054 provided for the Wildfire Insurance Fund to reimburse utilities for payment of third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1.0 billion or the utility's insurance coverage. The Wildfire Insurance Fund was established in September 2019 when both SCE and SDG&E made their initial contributions to the fund. The Wildfire Insurance Fund is available for claims related to wildfires ignited after July 12, 2019 that are determined to have been caused by a utility by the responsible government investigatory agency.

SCE and SDG&E have collectively made their initial contributions totaling approximately $2.7 billion to the Wildfire Insurance Fund. While PG&E has committed to make an initial contribution of approximately $4.8 billion to the Wildfire Insurance Fund upon emergence from bankruptcy, its participation in, and contributions to the fund are subject to it resolving its bankruptcy proceeding and meeting certain other conditions prior to June 30, 2020. SCE, SDG&E and PG&E are also collectively expected to make aggregate contributions of $3.0 billion to the Wildfire Insurance Fund through annual contributions to the fund over a 10-year period, of which SCE and SDG&E have made their initial annual contributions totaling approximately $107 million. If PG&E is unable to participate in the Wildfire Insurance Fund, then SCE and SDG&E are collectively expected to make aggregate contributions of approximately $1.0 billion to the fund through annual contributions over the 10-year period. In addition to PG&E's, SCE's and SDG&E's contributions to the Wildfire Insurance Fund, $13.5 billion is expected to be collected over a 15-year period from their ratepayers through a dedicated rate component. The amount collected from ratepayers may be directly contributed to the Wildfire Insurance Fund or used to support the issuance of up to $10.5 billion in bonds by the California Department of Water Resources, the proceeds of which would be contributed to the fund. In addition to funding contributions to the Wildfire Insurance Fund, the amount collected from utility ratepayers will pay for, among other things, any interest and financing costs related to any bonds that are issued by the California Department of Water Resources to support the contributions to the Wildfire Insurance Fund. Based on a decision adopted by the CPUC in October 2019 in the Order Instituting Rulemaking to Consider Authorization of a Non-Bypassable Charge to Support the Wildfire Insurance Fund, PG&E's ratepayers will not be required to contribute to the fund if PG&E does not participate in the Wildfire Insurance Fund. In that case, $7.5 billion will be collected from SCE's and SDG&E's ratepayers through the dedicated rate component to support a contribution to the Wildfire Insurance Fund.

SCE made an initial contribution of approximately $2.4 billion to the Wildfire Insurance Fund in September 2019 and has committed to make ten annual contributions of approximately $95 million per year to the fund, by no later than January 1 of each year. SCE made its first annual contribution to the Wildfire Insurance Fund in December 2019. Edison International supported SCE's initial contribution to the Wildfire Insurance Fund by raising $1.2 billion from the issuance of Edison International equity. SCE raised the remaining $1.2 billion from the issuance of long-term debt. SCE's contributions to the Wildfire Insurance Fund will not be recoverable through electric rates and will be excluded from the measurement of SCE's CPUC-jurisdictional authorized capital structure. SCE will also not be entitled to cost recovery for any borrowing costs incurred in connection with its contributions to the Wildfire Insurance Fund.

Participating investor-owned utilities will be reimbursed from the Wildfire Insurance Fund for eligible claims, subject to the fund administrator's review, and will be required to reimburse the fund for withdrawn amounts that the CPUC disallows subject, in some instances, to the AB 1054 Liability Cap. A utility will not be eligible for the AB 1054 Liability Cap if it does not maintain a valid safety certification or its actions or inactions that resulted in the wildfire are found to constitute conscious or willful disregard of the rights and safety of others. On July 25, 2019, SCE obtained its initial safety certification that will be valid for twelve months. Based on SCE's 2020 rate base and assuming the equity portion of SCE's capital structure is 52% (SCE's CPUC authorized capital structure), SCE's requirement to reimburse the Wildfire Insurance Fund for eligible claims disallowed in 2020 would be capped at approximately $3.0 billion. SCE will not be allowed to recover borrowing costs incurred to reimburse the fund for amounts that the CPUC disallows. The Wildfire Insurance Fund and, consequently, the AB 1054 Liability Cap will terminate when the administrator determines that the fund has been exhausted.

As a result of the establishment of the Wildfire Insurance Fund, AB 1054 created a new standard that the CPUC must apply when assessing the prudency of a utility in connection with a request for recovery of wildfire costs for wildfires ignited after July 12, 2019. Under AB 1054, the CPUC is required to find a utility to be prudent if the utility's conduct related to the ignition was consistent with actions that a reasonable utility would have undertaken under similar circumstances, at the

relevant point in time, and based on the information available at that time. Utilities with a valid safety certification will be presumed to have acted prudently related to a wildfire ignition unless a party in the cost recovery proceeding creates serious doubt as to the reasonableness of the utility's conduct, at which time, the burden shifts back to the utility to prove its conduct was reasonable. If a utility does not have a valid safety certification, it will have the burden to prove, based on a preponderance of evidence, that its conduct was prudent. The new prudency standard will survive the termination of the Wildfire Insurance Fund.

Utilities participating in the Wildfire Insurance Fund that are found to be prudent are not required to reimburse the fund for amounts withdrawn from the fund and can recover wildfire costs through electric rates if the fund has been exhausted.

Under AB 1054, approximately $1.6 billion spent by SCE on wildfire risk mitigation capital expenditures made after August 1, 2019 cannot be included in the equity portion of SCE's rate base. SCE can apply for an irrevocable order from the CPUC to finance these capital expenditures, including through the issuance of securitized bonds, and can recover any prudently incurred financing costs. SCE expects to finance this capital requirement by issuing securitized bonds.

For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Initial and annual contributions to the wildfire insurance fund established pursuant to California Assembly Bill 1054," "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies—Contingencies—Southern California Wildfires and Mudslides" and "Legal Proceedings."

In August 2019, SCE filed its 2021 GRC application for the three-year period 2021-2023. Following amendments and other revisions to the application in November 2019 and February 2020, SCE’s 2021 revenue requirement is $7.6 billion. SCE's request excludes the revenue requirement associated with the approximately $1.6 billion in wildfire risk mitigation capital expenditures that SCE will exclude from the equity portion of rate base as required under AB 1054.

In the amendment of February 2020, SCE removed its CSRP implementation costs from the 2021 GRC. SCE will continue to track the cost of the CSRP program in a memorandum account previously approved in the 2018 GRC and review of the CSRP implementation costs will be deferred to a future application to the CPUC.

The 2021 revenue requirement represents an increase of $1.1 billion over the 2020 revenue requirement authorized in the 2018 GRC and updated for anticipated post test-year ratemaking changes. Including the impact of anticipated lower kilowatt-hour sales in 2021 and one-time memorandum account recoveries, this represents an 11.4% increase over 2020 rates. SCE's 2021 GRC request also includes proposed revenue requirement increases of $423 million in 2022 and $514 million in 2023. The updated revenue requirements were requested based on the ROE and capital structure authorized at the time of the initial filing. A new capital structure has since been authorized. See "—2020 Cost of Capital Application."

SCE's requested increase to its revenue requirement in the 2021 GRC application is largely due to SCE's efforts to reduce wildfire risk. Certain of SCE's key wildfire mitigation forecast expenditures are subject to significant potential volatility. As a result, SCE has proposed establishing two-way balancing accounts for wildfire mitigation-related enhanced vegetation management, inspection activities and grid hardening, as well as for insurance premiums.

The capital programs requested in SCE's 2021 GRC include the infrastructure and programs necessary to implement California's ambitious public policy goals, including wildfire mitigation, de-carbonization of the economy through electrification and integration of distributed energy resources across a rapidly modernizing grid. See "—Capital Program" for further details.

The schedule established in the proceeding includes CPUC issuance of a proposed decision in the fourth quarter of 2020, or during the first quarter of 2021. If the final decision is issued in 2021, SCE will, consistent with CPUC practice in prior GRCs, request the CPUC to issue an order directing that the authorized revenue requirement changes be effective January 1, 2021.

Changes in the electric power industry are impacting customers and jurisdictions outside California as well. Edison International believes that other states will also pursue climate change and GHG reduction objectives and large commercial and industrial customers will continue to pursue cost reduction and sustainability goals. Edison Energy provides energy services and managed portfolio solutions to commercial and industrial customers who may be impacted by these changes. Edison Energy seeks to provide advice in dealing with increasingly complex tariff and technology choices in order to support customers and their management of energy costs and risks.

To better engage in this broader transformation and provide a view of developments outside of SCE, Edison International has made several minority investments in emerging companies in areas related to the technology changes that are driving industry transformation and may make additional investments in the future. These investments are not financially material to Edison International.

SCE's authorized CPUC-jurisdictional rate base is determined through the GRC and other regulatory proceedings. Differences between actual and CPUC-authorized capital expenditures are addressed in subsequent GRC or other regulatory proceedings. FERC-jurisdictional rate base is generally determined based on actual capital expenditures.

Reflected below is SCE's weighted average annual rate base for 2019 – 2023 incorporating CPUC capital expenditures authorized in the 2018 GRC final decision, expected FERC capital expenditures and capital expenditures included in the 2021 GRC application. The table below does not reflect the $1.6 billion of wildfire risk mitigation capital expenditures to be excluded from the equity portion of SCE's rate base under AB 1054. The table below does not reflect rate base associated with non-GRC projects or programs that have not yet been approved by the CPUC, including CSRP, with the exception of GS&RP spend incurred before August 1, 2019. In addition, a third-party holds an option to invest up to $400 million in the West of Devers Transmission project at the estimated in-service date of 2021. The rate base in the table below is reduced to reflect this option.

The 2018 GRC final decision determines the amount of revenue that SCE is authorized to collect from customers to recover anticipated costs, including return on rate base. The 2018 GRC final decision approved an authorized revenue requirement of $5.1 billion for 2018, the first year ("Test Year") of the three-year GRC period, and authorized annual increases under a set escalation mechanism based on labor, non-labor and medical expenses.

After the application of escalation factors to the Test Year, the CPUC authorized SCE to collect $5.5 billion from customers in 2019. During the second quarter of 2019, SCE recorded a reduction of revenue of $265 million to reflect $289 million of lower authorized revenue related to 2018 and $24 million of higher authorized revenue in 2019. The 2018 GRC final decision is retroactive to January 1, 2018 and the reduction of revenue contributed to a refund to customers of $554 million, which SCE recorded as a regulatory liability. SCE expects to refund these amounts to customers through December 2020.

Earning activities were primarily affected by the following:

SCE's income tax provision decreased by $467 million in 2019 compared to 2018. The effective tax rates were (17.6)% and (78.6)% for 2019 and 2018, respectively. SCE's effective tax rate is below the federal statutory rate of 21% for 2019 and 2018 primarily due to the CPUC's ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences, which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense. The effective tax rate decrease in 2019 is primarily due to impact of higher pre-tax income and absence of the 2018 settlement of the 1994 – 2006 California tax audit in 2018, partially offset by higher tax benefits on property-related items recorded as a result of 2018 GRC final decision and the changes in the allocation of excess deferred tax re-measurement between customers and shareholders as a result of a CPUC resolution issued in February 2019.

See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for a reconciliation of the federal statutory rate to the effective income tax rates.

The loss from continuing operations of Edison International Parent and Other decreased $22 million in 2019 compared to 2018 primarily due to an after-tax loss of $50 million in 2018 related to the sale of SoCore Energy, partially offset by higher interest expense as a result of increased borrowings in 2019.

In the next 12 months, SCE expects to continue to fund its cash requirements through operating cash flows, bank and capital market financings, and equity contributions from Edison International Parent, as needed, while continuing to increase the equity portion of its capital structure. SCE also expects to repurchase or redeem preferred or preference stock to reduce the preferred equity component of the capital structure to 5% in line with the capital structure authorized in the 2020 Cost of Capital proceeding. See "Management Overview—2020 Cost of Capital Application." SCE also has availability under its credit facility to fund cash requirements.

Mesa Substation

The Mesa Substation Project consists of replacing the existing 220-kV Mesa Substation with a new 500/220-kV substation. The Mesa Substation Project would address reliability concerns by providing additional transmission import capability, allowing greater flexibility in the siting of new generation, and reducing the total amount of new generation required to meet local reliability needs in the Western Los Angeles Basin area. In February 2017, the CPUC issued a final decision approving the project largely consistent with SCE's proposal and rejected alternative project configurations proposed by CPUC staff. Construction on the initial phase of construction (a new 220- kV substation) commenced in October 2017. In October 2019, SCE achieved first energization of the new substation. The remaining phases of construction are anticipated to be put out for competitive bid and SCE expects that costs associated with the project may change as a result of the competitive bidding process. SCE anticipates project completion in the first quarter of 2022.

Alberhill System

The Alberhill System Project would consist of constructing a new 500-kV substation, two 500-kV transmission lines to connect the proposed substation to the existing Serrano-Valley 500-kV transmission line, telecommunication equipment and subtransmission lines in unincorporated and incorporated portions of western Riverside County. The project was designed to meet long-term forecasted electrical demand in the proposed Alberhill System Project area and to increase electrical system reliability and resiliency. In April 2018 and July 2018, the CPUC issued a proposed decision and an alternate proposed decision, both denying SCE's ability to construct the Alberhill System Project based on a perceived lack of need. SCE filed comments on both proposed decisions requesting that the CPUC grant the certificate of public convenience and necessity for the Alberhill System Project. In August 2018, the CPUC issued a decision that did not deny or approve the Alberhill System Project but directed SCE to submit supplemental information on the Alberhill System Project including but not limited to a load forecast and cost benefit analysis of several alternatives to the proposed project. Ongoing capital spending has been deferred as a result of the CPUC request for additional information. In January 2020, SCE submitted a supplemental analysis to the CPUC for the Alberhill System Project including several alternatives to the proposed project as well as an update to the original project cost. A final decision on the Alberhill System Project is pending based on the supplemental analysis. Given the uncertainty associated with the resolution of the permitting process, potential revisions to the project have not been reflected in total direct expenditures. SCE continues to believe a system solution is needed for the project area but is unable to predict the timing of a final CPUC decision in connection with the Alberhill System Project proceeding.

Approximately 48% of the Alberhill System Project costs spent to date would be subject to recovery through CPUC revenue and 52% through FERC revenue. In October 2017, SCE obtained approval from the FERC for abandoned plant treatment for the Alberhill System Project, which allows SCE to seek recovery of 100% of all prudently incurred costs after the approval date and 50% of prudently incurred costs prior to the approval date. Excluding land costs, which may be recovered through sale to a third party, SCE has incurred approximately $46 million of capital expenditures, including overhead costs, as of December 31, 2019, of which approximately $34 million may not be recoverable if the project is cancelled.

Riverside Transmission Reliability

The Riverside Transmission Reliability Project is a joint project between SCE and Riverside Public Utilities ("RPU"), the municipal utility department of the City of Riverside. While RPU would be responsible for constructing some of the project's facilities within Riverside, SCE's portion of the project consists of constructing upgrades to its system, including a new 230-kV Substation; certain interconnection and telecommunication facilities and transmission lines in the cities of Riverside, Jurupa Valley and Norco and in portions of unincorporated Riverside County. The purpose of the project is to provide RPU and its customers with adequate transmission capacity to serve existing and projected load, to provide for long-term system capacity for load growth, and to provide needed system reliability. Due to changed circumstances since the time the project was originally developed, SCE informed the CPUC in August 2016 that it supports revisions to the proposed Project. In October 2018, the CPUC issued an environmental report that identified a new route alternative, as the environmentally preferred project and proposed an additional underground section of the proposed 220-kV power line. In January 2020, SCE received a proposed decision from the CPUC that would approve the project consistent with the environmental report. If adopted, the cost of the revised project is estimated to be $584 million.

Eldorado-Lugo-Mohave Upgrade

The Eldorado-Lugo-Mohave Upgrade Project will increase capacity on existing transmission lines to allow additional renewable energy to flow from Nevada to southern California. The project would modify SCE's existing Eldorado, Lugo, and Mohave electrical substations to accommodate the increased current flow from Nevada to southern California; increase the power flow through the existing 500-kV transmission lines by constructing two new capacitors along the lines; raise transmission tower heights to meet ground clearance requirements; and install fiber optics on the transmission lines to

provide communications between existing SCE substations. A final CPUC decision is anticipated during 2020. In April 2019, as directed by the CPUC, SCE filed an amended application for a certificate of public convenience and necessity with the CPUC, which included total project costs of $257 million. A subsequent change to the project work scope reduced the project total cost to $246 million, a decrease of $11 million as compared to the estimate provided in the amended application.

See "Management Overview—Wildfire Mitigation and Wildfire Insurance Expenses."

Medium- and Heavy-Duty Vehicle Transportation Electrification

In January 2017, SCE filed an application with the CPUC requesting approval of transportation electrification programs to accelerate the adoption of electric transportation, which is critical to California's climate change and GHG reduction objectives. The application proposed a five-year program to fund medium- and heavy-duty vehicle charging infrastructure that follows the model developed for SCE's Charge Ready program, as well as six pilot projects to be considered on an accelerated basis. In January 2018, the CPUC issued a final decision approving five pilot projects with a budget of $16 million ($10 million capital) in 2016 dollars. In May 2018, the CPUC issued a final decision approving the five-year program, with certain modifications, to install charging infrastructure to support the electrification of 8,490 medium- and heavy-duty electric vehicles at 870 sites, which must be fully contracted for by 2024. The final decision includes an approved five-year budget of $356 million ($242 million capital) in nominal dollars. SCE expects to propose additional programs and pilots in the future. SCE's 2020 capital plan contemplates $4 million of medium- and heavy-duty vehicle transportation electrification spending.

Charge Ready Program

In January 2016, the CPUC approved SCE's $22 million Charge Ready Program Pilot, which allows SCE to install light-duty electric vehicle charging infrastructure, provide rebates to offset the cost of qualified customer-owned charging stations, and implement a supporting marketing, education and outreach campaign. As of December 31, 2019, SCE had executed agreements and reserved funding for 81 sites to deploy 1,301 charge ports under this pilot. The results of this pilot helped shape Charge Ready 2, the second phase of the Charge Ready program.

In June 2018, SCE filed an application to obtain approval for Charge Ready 2. In the application, SCE requested approval for $760 million ($561 million capital) in 2018 dollars to install infrastructure and provide rebates to support 48,000 new electric vehicle charging ports as part of a four-year program that will also include a marketing, education and outreach campaign. In December 2018, the CPUC approved $22 million in bridge funding to continue the Charge Ready Program Pilot while the Charge Ready 2 application remains pending. As of December 31, 2019, with this additional funding, SCE had executed agreements and reserved funding for 66 additional sites to deploy 1,463 additional charge ports. SCE's 2020 capital plan contemplates $8 million of bridge Charge Ready Program Pilot spending.

The decommissioning of a nuclear plant requires the management of three related activities: radiological decommissioning, non-radiological decommissioning and the management of spent nuclear fuel. SCE has engaged a decommissioning general contractor to undertake a significant scope of decommissioning activities for Units 1, 2 and 3 at San Onofre. The decommissioning of San Onofre is expected to take many years.

Decommissioning of San Onofre Unit 1 began in 1999 and the transfer of spent nuclear fuel from Unit 1 to dry cask storage in the Independent Spent Fuel Storage Installation ("ISFSI") was completed in 2005. Major decommissioning work for Unit 1 has been completed except for reactor vessel disposal and certain underground work. Some spent nuclear fuel from Units 2 and 3 also was transferred to the ISFSI between 2007 and 2012. Radiological decommissioning of San Onofre Units 2 and 3 began in June 2013 with SCE filing a certification of permanent cessation of power operations at San Onofre with the NRC. The transfer of the remaining spent nuclear fuel from Units 2 and 3 to the ISFSI began in 2018. The spent fuel transfer operations were suspended on August 3, 2018 due to an incident that occurred when an SCE contractor was loading a spent fuel canister into the ISFSI. The incident did not result in any harm to the public or workers and the canister was subsequently safely loaded into the ISFSI. In May 2019, after an extensive review, the NRC determined that fuel loading can be safely resumed at San Onofre. SCE commenced fuel transfer operations at San Onofre in July 2019. In October 2019, the California Coastal Commission approved SCE's application for the Coastal Development Permit, the principle discretionary permit required to start major decommissioning activities at San Onofre. SCE plans on commencing major decommissioning activities in 2020 in accordance with the terms of the permit, subject to any court rulings in a proceeding brought in

December 2019 to challenge the California Coastal Commission's issuance of the permit.

In December 2018, SCE updated its decommissioning cost estimate for decommissioning activities to be completed at San Onofre Units 2 and 3 to $3.4 billion (SCE share is $2.5 billion) in 2017 dollars. The decommissioning cost estimate includes costs through the respective expected decommissioning completion dates, currently estimated to be in 2051 for San Onofre Units 2 and 3. The decommissioning cost estimate is subject to a number of uncertainties including the cost of disposal of nuclear waste, cost of removal of property, site remediation costs as well as a number of other assumptions and estimates, including when the federal government will provide for either interim or permanent off-site storage of spent nuclear fuel enabling the removal and transport of spent fuel canisters from the San Onofre site, as to which there can be no assurance. The cost estimate is subject to change as decommissioning proceeds and such changes may be material. The CPUC will conduct a reasonableness review for costs for each year. SCE's share of the San Onofre decommissioning costs recorded during 2019 were $172 million.

SCE had nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $2.8 billion as of December 31, 2019. Based upon the resolution of a number of uncertainties, including the cost and timing of nuclear waste disposal, the time it will take to obtain required permits, cost of removal of property, site remediation costs, the financial performance of the nuclear decommissioning trust fund investments, as well as the resolution of a number of other assumptions and estimates, additional contributions to the nuclear decommissioning trust funds may be required. If additional contributions to the nuclear decommissioning trust funds become necessary, SCE will seek recovery of such additional funds through electric rates and any such recovery will be subject to a reasonableness review by the CPUC. Cost increases resulting from contractual disputes or significant permitting delays, among other things, could cause SCE to materially overrun the decommissioning cost estimate and could materially impact the sufficiency of trust funds.

As a California corporation, SCE's ability to pay dividends is also governed by the California General Corporation Law. California law requires that for a dividend to be declared: (a) retained earnings must equal or exceed the proposed dividend, or (b) immediately after the dividend is made, the value of the corporation's assets must exceed the value of its liabilities plus amounts required to be paid, if any, in order to liquidate stock senior to the shares receiving the dividend. Additionally, a California corporation may not declare a dividend if it is, or as a result of the dividend would be, likely to be unable to meet its liabilities as they mature. Prior to declaring dividends, SCE's Board of Directors evaluates available information, including when applicable, information pertaining to the 2017/2018 Wildfire/Mudslide Events, to ensure that the California law requirements for the declarations are met. On February 27, 2020, SCE declared a dividend to Edison International of $269 million.

In June 2019, Edison International Parent extended its credit facility through May 2024, pursuant to an option to extend, and may extend the credit facility for one additional year with the lenders' approval. At December 31, 2019, Edison International Parent's entire $1.5 billion credit facility was available for borrowing.

During 2019, Edison International Parent engaged in a financing program to support SCE's initial contribution to the Wildfire Insurance Fund in September 2019, fund SCE's wildfire mitigation expenditures, and increase the equity portion of SCE's capital structure. This included issuing 2.8 million shares of common stock for net proceeds of $198 million through the ATM program and issuing 32.2 million shares of common stock for net proceeds of $2.2 billion in an underwritten offering during 2019. For further details, see "Notes to Consolidated Financial Statements—Note 14. Equity." Edison International Parent also issued $1.4 billion of senior notes during 2019. The proceeds of these financing activities allowed Edison International to contribute $3.3 billion to SCE as equity contributions and repay a $1.0 billion term loan. The term loan was borrowed in April 2019 and the proceeds of the term loan were contributed to SCE largely to enable repayment of SCE's February 2019 term loan. Edison International Parent's term loan was repaid in full in December 2019.

At December 31, 2019, the current portion of Edison International Parent’s long-term debt included senior notes of $400 million due in April 2020.

A debt covenant in Edison International Parent's credit facility requires a consolidated debt to total capitalization ratio as defined in the credit agreement of less than or equal to 0.70 to 1. At December 31, 2019, Edison International Parent's consolidated debt to total capitalization ratio was 0.55 to 1.

Edison International Parent's long-term issuer credit ratings remain at investment grade levels after downgrade actions taken by the major credit rating agencies in 2018 and early 2019. In the third quarter of 2019, the major credit agencies changed Edison International Parent's outlook from negative to stable, due to the passage of AB 1054 and the establishment of the Wildfire Insurance Fund, which provided the AB 1054 Liability Cap and the new standard that the CPUC must apply when assessing the prudency of a utility in wildfire-related cost recovery proceedings. The following table summarizes Edison International Parent's current, long-term issuer credit ratings and outlook from the major credit rating agencies:

Edison International has approximately $1.3 billion of tax effected net operating loss and tax credit carryforwards at December 31, 2019 (after offsetting $212 million of unrecognized tax benefits and $212 million of Capistrano Wind net operating loss and tax credit carryforwards), which are available to offset future consolidated tax liabilities. See "Notes to Consolidated Financial Statements—Note 8. Income Taxes" for further information regarding taxes payable to Capistrano Wind. Forecast monetization has been delayed, mainly due to anticipated future payment of wildfire claims and the contribution to the Wildfire Insurance Fund as described in AB 1054. Edison International expects to utilize its net operating loss and tax credit carryforwards through 2027.

SCE's statements of cash flows includes nuclear decommissioning activities, which are reflected in the following line items:

Net cash used in operating activities relates to interest and dividends less administrative expenses, taxes and SCE's decommissioning costs. Investing activities represent the purchase and sale of investments within the nuclear decommissioning trusts, including the reinvestment of earnings from nuclear decommissioning trust investments.

Funds for decommissioning costs are requested from the nuclear decommissioning trusts one month in advance. Decommissioning disbursements are funded from sales of investments of the nuclear decommissioning trusts. See "Notes to Consolidated Financial Statements—Note 10. Investments" for further information. The net cash impact reflects timing of decommissioning payments ($172 million and $140 million in 2019 and 2018, respectively) and reimbursements to SCE from the nuclear decommissioning trust ($173 million and $150 million in 2019 and 2018, respectively).

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. SCE manages the credit risk on the portfolio of counterparties based on credit ratings and other publicly disclosed information, such as financial statements, regulatory filings and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. Based on SCE's policies and risk exposures related to credit, SCE does not anticipate a material adverse effect on their financial statements as a result of counterparty nonperformance. At December 31, 2019, SCE's power and gas trading counterparty credit risk exposure was $91 million, 98% of which is associated with entities that have an investment grade rating of A or higher. SCE assigns a credit rating to counterparties based on the lower of a counterparty's S&P or Moody's rating.

For more information related to credit risks, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments."

The current ARO estimates for San Onofre and Palo Verde are based on:

See "Liquidity and Capital Resources—SCE—Decommissioning of San Onofre" for further discussion of the plans for decommissioning of San Onofre.

suspended on August 3, 2018 due to an incident that occurred when an SCE contractor was loading a spent fuel canister into the ISFSI. The incident did not result in any harm to the public or workers and the canister was subsequently safely loaded into the ISFSI. In May 2019, after an extensive review, the NRC determined that fuel loading can be safely resumed at San Onofre. SCE commenced fuel transfer operations at San Onofre in July 2019. In October 2019, the California Coastal Commission approved SCE's application for the Coastal Development Permit, the principle discretionary permit required to start major decommissioning activities at San Onofre. SCE plans on commencing major decommissioning activities in 2020 in accordance with the terms of the permit, subject to any court rulings in a proceeding brought in December 2019 to challenge the California Coastal Commission's issuance of the permit.

The following table illustrates the increase to the ARO liability if the cost escalation rate was adjusted while leaving all other assumptions constant:

The increase in the ARO liability driven by an increase in the escalation rate would result in a decrease in the regulatory liability for recoveries in excess of ARO liabilities.

As of December 31, 2019, Edison International and SCE had unrecognized pension costs of $181 million and $104 million, respectively, and unrecognized PBOP gains of $414 million and $416 million, respectively. The unrecognized pension costs and PBOP gains primarily consisted of the cumulative impact of the reduced discount rates on the respective benefit obligations and the cumulative difference between the expected and actual rate of return on plan assets. Of these deferred costs or gains, $87 million of SCE's pension costs and $416 million of SCE's PBOP gains are recorded as regulatory assets and regulatory liabilities, respectively, and are expected to be recovered or refunded over the average expected future service of employees.

Management concluded it would be most appropriate to account for the contributions to the Wildfire Insurance Fund similar to prepaid insurance, ratably allocating the expense to periods based on an estimated period of coverage.

Edison International's ability to obtain financing, as well as its ability to refinance debt and make scheduled payments of principal and interest, are dependent on numerous factors, including its levels of indebtedness, maintenance of acceptable credit ratings, financial performance, liquidity and cash flow, and other market conditions. In addition, the factors affecting SCE's business will impact Edison International's ability to obtain financing. Edison International's inability to borrow funds from time to time could have a material effect on Edison International's liquidity and operations.

SCE operates in a highly regulated environment. SCE's business is subject to extensive federal, state and local energy, environmental and other laws and regulations. Among other things, the CPUC regulates SCE's retail rates and capital structure, and the FERC regulates SCE's wholesale rates. The NRC regulates the decommissioning of San Onofre in addition to the local and state agencies that require permits. The construction, planning, and siting of SCE's power plants and transmission lines in California are also subject to regulation by the CPUC and other local, state and federal agencies.

SCE must periodically apply for licenses and permits from these various regulatory authorities, including environmental regulatory authorities, and abide by their respective orders. Should SCE be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose fines, penalties or disallowances on SCE, SCE may be prevented from executing its strategy and its business could be materially affected. The process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by opponents and such delay or defeat could have a material effect on SCE's business.

Edison International and SCE continue to pursue regulatory and legal strategies, and anticipate pursuing legislative strategies on the longer term, to address the application of a strict liability standard to wildfire-related property damages without the guaranteed ability to recover resulting costs in electric rates. To the extent the Wildfire Insurance Fund and other provisions of AB 1054 do not effectively mitigate the significant risk faced by California investor-owned utilities related to liability for damages arising from catastrophic wildfires where utility facilities are a substantial cause, not achieving a more comprehensive solution could have a detrimental effect on SCE's business and financial condition. The effectiveness of AB 1054 to mitigate the wildfire-related risk faced by SCE is conditioned in part on the performance of various entities newly formed under AB 1054 and related legislation to, among other things, administer the Wildfire Insurance Fund, issue safety certifications, oversee and enforce compliance with wildfire safety standards, and develop metrics to reduce risk and measure compliance with risk reduction. In addition, CPUC approval is required to recover the costs SCE is incurring to strengthen its wildfire mitigation and prevention efforts described in its 2019 and 2020 WMPs, including costs being incurred for its GS&RP. See "Management Overview—Southern California Wildfires and Mudslides" and "Management Overview—Wildfire Mitigation and Wildfire Insurance Expenses" in the MD&A.