8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): March 27, 2014

Commission File Number	Exact Name of Registrant as specified in its charter	State or Other Jurisdiction of Incorporation or Organization	IRS Employer Identification Number
1-9936	EDISON INTERNATIONAL	California	95-4137452
1-2313	SOUTHERN CALIFORNIA EDISON COMPANY	California	95-1240335

2244 Walnut Grove Avenue (P.O. Box 976) Rosemead, California 91770 (Address of principal executive offices)	2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California 91770 (Address of principal executive offices)
(626) 302-2222 (Registrant's telephone number, including area code)	(626) 302-1212 (Registrant's telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

This current report and its exhibit include forward-looking statements. Edison International and Southern California Edison Company ("SCE") based these forward-looking statements on their current expectations and projections about future events in light of its knowledge of facts as of the date of this current report and its assumptions about future circumstances. These forward-looking statements are subject to various risks and uncertainties that may be outside the control of Edison International and SCE. Edison International and SCE have no obligation to publicly update or revise any forward-looking statements, whether due to new information, future events, or otherwise. This current report should be read with Edison International's and SCE's Joint Annual Report on Form 10-K for the year ended December 31, 2013.

Item  1.01Entry Into A Material Definitive Agreement

Item  2.06    Material Impairment

Entry Into Settlement Agreement

On March 27, 2014, SCE entered into a Settlement Agreement with The Utility Reform Network (“TURN”), the Office of Ratepayer Advocates (“ORA”) of the California Public Utilities Commission (“CPUC”) and San Diego Gas & Electric Company (“SDG&E”). If implemented, the Settlement Agreement will constitute a complete and final resolution of the CPUC’s Order Instituting Investigation (“OII”) and related proceedings regarding the Steam Generator Replacement Project (“SGRP”) at the San Onofre Nuclear Generating Station (“San Onofre”) and the related outage and subsequent shutdown of San Onofre. The Settlement Agreement does not affect proceedings before the Nuclear Regulatory Commission or proceedings related to recoveries from third parties described below. The Settlement Agreement was signed following an all-party settlement conference in the OII, which was required under CPUC rules as a condition to a settlement.

Implementation of the terms of the Settlement Agreement is subject to the prior approval of the CPUC, as to which there is no assurance. The parties to the Settlement Agreement (“Settling Parties”) have agreed to exercise their best efforts to obtain CPUC approval. The Settlement Agreement is subject to termination by any of the Settling Parties if the CPUC has not approved it within six months of submission, but there can be no certainty of when or what the CPUC will actually decide.

The following summary of the Settlement Agreement is qualified in its entirety by reference to the complete text of the Settlement Agreement, which is filed as Exhibit 10.1 to this Current Report.

Disallowances, Refunds and Rate Recoveries

If the Settlement Agreement is approved, SCE will not be allowed to recover in rates its capitalized costs for the SGRP as of February 1, 2012 or a return on such investment after such date. As of February 1, 2012, SCE’s net book value in the SGRP was approximately $597 million. Additionally, SCE will not be allowed to recover in rates approximately $99 million of incremental inspection and repair costs incurred for the replacement steam generators (“RSGs”) in 2012 that were in excess of CPUC authorized operations and maintenance (“O&M”) expense. These costs, net of invoices paid, were previously expensed in SCE’s 2012 financial results, although they remain subject to recovery from the supplier of the RSGs. See “Third Party Recoveries” below. Neither will SCE be allowed to recover in rates provisionally authorized O&M expense in 2013 that exceeds amounts included in recorded O&M expense (including severance and incremental repair and inspection costs); such excess had not been recognized in 2013 earnings. Subject to the foregoing, SCE will be authorized to recover in rates its remaining investment in San Onofre , including base plant, materials and supplies, nuclear fuel inventory and contracts and construction work in progress (“CWIP”) generally over a ten-year period commencing February 1, 2012. Additionally, SCE will be authorized to recover in rates its provisionally authorized O&M expenses for 2012, recorded costs for the 2012 refueling outage of Unit 2, recorded O&M expenses for 2013, and recorded O&M expenses for 2014 subject to customary prudency review. Finally, SCE will also be authorized to recover in rates through its fuel and purchased power balancing account (“ERRA”) all costs incurred to purchase electric power in the market related to the outage and shutdown of San Onofre, and to recover by December 31, 2015 any San Onofre-related ERRA undercollections. Estimated market power costs through June 6, 2013 (the date of San Onofre’s retirement) were approximately $680 million using the methodology followed in the OII (and an additional approximately $333 million through December 31, 2013). To the extent that amounts otherwise recoverable in rates under the Settlement

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Agreement are recovered from SCE’s Decommissioning Trust as a decommissioning cost, the amounts otherwise recoverable in rates will be reduced with no impact on earnings.

The portion of SCE’s San Onofre investment in base plant, CWIP and materials and supplies which SCE is entitled to recover from February 1, 2012 will earn a return equal to the weighted average of SCE’s authorized return on debt and 50% of its authorized return on preferred equity, pro-rated to the percentage of the investment that equals SCE’s percentage of debt and preferred equity in its authorized capital structure. SCE will not earn a return on common equity on its amortizable San Onofre investment. Accordingly, SCE will be allowed to earn a rate of return of 2.95% in 2012, 2.62% for the period 2013-14 and a rate that will float during the amortization period thereafter with changes in SCE’s authorized return on debt and preferred equity. SCE’s investment in nuclear fuel will earn a return equal to commercial paper rates that SCE pays from time to time. Under the Settlement Agreement, the unamortized portion of SCE’s investment other than nuclear fuel may, at SCE’s option, be excluded from SCE’s capital structure for purposes of determining regulatory capital requirements. Were such exclusion elected as of March 31, 2014, SCE estimates that its common equity requirement would be reduced by more than $300 million.

A 5% incentive is provided for SCE to realize savings for ratepayers by selling materials and supplies and nuclear fuel, as well as reducing in nuclear fuel investment by contract cancellations. This incentive allows SCE to retain 5% of sales proceeds and to recover 5% of the excess of cancelled contract obligations over cancellation costs. The balance of sale proceeds and cancellation benefits is credited to ratepayers.

Third Party Recoveries

The Settlement Agreement also addresses how potential recoveries from third parties will be allocated between ratepayers and SCE.

As has been previously disclosed, San Onofre carries accidental property damage and carried accidental outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of claims under both policies. The NEIL policies have a number of exclusions and limitations that NEIL may assert to reduce or eliminate coverage and SCE may choose to challenge NEIL’s application of any such exclusions and limitations. SCE’s share of estimated claims under the accidental outage insurance through December 31, 2013 is approximately $320 million. Accidental outage policy benefits are reduced by 90% for the periods following announcement of the permanent retirement of San Onofre. SCE has not submitted a proof of loss under the accidental property damage insurance.

Under the Settlement Agreement, recoveries from NEIL, if any, will first be applied on and after December 31, 2014 to reimburse costs incurred in pursuing such recoveries, including litigation costs. To the extent SCE’s share of recoveries from NEIL exceed such costs, recoveries will be allocated 82.5% to ratepayers and 17.5% to SCE. SCE ratepayers’ portion of amounts recovered from NEIL would be distributed to SCE ratepayers via a credit to SCE’s ERRA account.

SCE is also pursuing claims against Mitsubishi Heavy Industries, Ltd. and related companies (“MHI”), which designed and supplied the RSGs. MHI warranted the RSGs for an initial period of 20 years from acceptance and is contractually obligated to repair or replace defective items with dispatch and to pay specified damages for certain repairs. MHI’s liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include “the cost of replacement power”; however, limitations in the contract are subject to applicable exceptions both in the contract and under law. SCE has advised MHI that it believes one or more of such exceptions apply and MHI’s liability is not limited to $138 million, and MHI has advised SCE that it disagrees. In October 2013, after a prescribed waiting period, SCE sent MHI a formal request for arbitration under the auspices of the International Chamber of Commerce seeking at least $4 billion of damages for all losses on behalf of itself and its ratepayers and in its capacity as Operating Agent for San Onofre. MHI has denied any liability and has asserted counterclaims for $41 million, for which SCE has denied any liability.

SCE, on behalf of itself and the other San Onofre co-owners has also submitted seven invoices to MHI totaling $149 million for inspection and repair costs through April 30, 2013. MHI paid the first invoice of $45 million while reserving rights to challenge it and subsequently rejected a portion of the invoice and has not paid further invoices,

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claiming further documentation is required, which SCE disputes. SCE recorded its share of the invoice paid (approximately $35 million) as a reduction of repair and inspection costs in 2012.

Under the Settlement Agreement, recoveries from MHI (including amounts paid by MHI under the first invoice), if any, will first be applied on and after December 31, 2014 to reimburse costs incurred in pursuing such recoveries, including litigation costs. To the extent SCE’s share of recoveries from MHI exceed such costs, they will be allocated as follows: (1) 85% of the first $100 million to SCE, and 15% to ratepayers; (2) 66.67% of the next $800 million to SCE, and 33.33% to ratepayers; and (3) 25% of any additional recoveries to SCE, and 75% to ratepayers. The first $282 million of SCE’s ratepayers’ portion of such recoveries will be distributed to ratepayers via a credit to a sub-account of SCE’s Base Revenue Requirement Balancing Account ("BRRBA"), thus reducing revenue requirements from ratepayers. Amounts in excess of the first $282 million distributable to SCE ratepayers will reduce SCE’s regulatory asset represented by the unamortized balance of investment in San Onofre base plant, thereby reducing the revenue requirement needed to amortize such investment. The amortization period, however, will be unaffected. Additional amounts, if any, will first reduce the unamortized balance of remaining investment to zero and then be applied to the BRRBA.

The Settlement Agreement provides the utilities with the discretion to resolve the NEIL and MHI disputes without CPUC approval or review, but the utilities are obligated to use their best efforts to inform the CPUC of any settlement or other resolution of these disputes to the extent this is possible without compromising any aspect of the resolution.

There is no assurance that there will be any recoveries from NEIL or MHI or that if there are recoveries, that they will exceed the costs incurred to pursue them. Were there to be recoveries, SCE cannot speculate when they would be received. SCE’s current expectation is that NEIL will make a coverage determination by the end of the second quarter of 2014.

Accounting and Financial Impacts

As a result of the decision to early retire San Onofre Units 2 and 3, generally accepted accounting principles (“GAAP”) required reclassification of the amounts recorded in property, plant and equipment and related tangible operating assets to a regulatory asset to the extent that management concluded it was probable of recovery through future rates. Regulatory assets may also be recorded to the extent management concludes it is probable that direct and indirect costs incurred to retire Units 2 and 3 as of each reporting date are recoverable through future rates.

In accordance with these requirements and as a result of its decision to retire San Onofre Units 2 and 3, SCE reclassified $1,521 million of its total investment in San Onofre at May 31, 2013 to a regulatory asset (“San Onofre Regulatory Asset”) and recorded an impairment charge of $575 million ($365 million after tax) in the second quarter of 2013. As of December 31, 2013, SCE recorded a net regulatory asset of approximately $1.3 billion, comprised of $1.56 billion of property, plant and equipment, less $266 million for estimated refunds of authorized revenue recorded in excess of SCE’s costs of service.

As a result of execution of the Settlement Agreement by the Settling Parties, SCE has concluded that the outcome of the OII that is more likely than any other outcome is approval and implementation of the Settlement Agreement, although a favorable decision by the CPUC remains uncertain. As a result, SCE expects to record in the first quarter of 2014 an additional pre-tax impairment charge of approximately $155 million (approximately $100 million after-tax). After adjustment for the Settlement Agreement, the total impairment recorded for the San Onofre Regulatory Asset, including amounts previously recorded in 2013, will be approximately $730 million (approximately $465 million after tax). The total pre-tax impairment charge is primarily due to:

• the disallowance of the SGRP investment ($542 million as of May 31, 2013),

• refund of revenues related to the SGRP previously recognized from February 1, 2012 through May 31, 2013 of $153 million, and

• implementation of the other terms of the Settlement Agreement, including refund of the authorized return in excess of the return allowed for non-SGRP investments.

The San Onofre Regulatory Asset at March 31, 2014 is estimated to be approximately $1.3 billion and a separate regulatory liability for refunds of revenues of approximately $256 million. Such amounts are estimates and subject to revision in connection with the preparation of SCE's first quarter financial statements.

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Assuming the Settlement Agreement is approved, SCE does not expect implementation of rate recoveries and rate refunds contemplated by the Settlement Agreement will have a material impact on future net income. Such amounts do not reflect any recoveries from third parties by SCE.

Rate Impacts

To the extent that SCE collects in rates amounts that are in excess of the amounts recoverable under the Settlement Agreement, such amounts will be credited to SCE’s ERRA account, thereby reducing the undercollected balance otherwise subject to rate recovery. SCE estimates that if the settlement were implemented on March 31, 2014, the refund of revenues related to the SGRP, the refund of the difference between authorized and recorded O&M expenses for 2013 and the first quarter of 2014, the refund from the reduction of returns on the balance of its San Onofre investment and the other elements of the settlement would have resulted in a refund to ratepayers of approximately $256 million. SCE’s ERRA undercollection at December 31, 2013 was approximately $1 billion.

As a result of the disallowances, refunds and reduced returns contemplated by the Settlement Agreement, SCE ratepayers will also have a reduction from the current level of authorized revenues set forth in SCE's 2012 General Rate Case. Calculation of the reduction of revenue requirement over any meaningful period of time is subject to a number of estimates and assumptions which may prove to be inaccurate. Subject to such uncertainty, SCE estimates that the present value of the revenue requirement that will be collected in rates under the Settlement Agreement will be more than $1 billion below the present value (using a 10% discount rate) of the revenue requirement that SCE had been seeking in the OII before the settlement.

Procedure

Under the Settlement Agreement, the Settling Parties are required to use their best efforts to obtain CPUC approval and expect to file a motion shortly requesting the CPUC to approve the Settlement Agreement without change, find the Settlement Agreement reasonable and expedite consideration of the Settlement Agreement in order to provide the benefits of it as soon as possible. The Settling Parties will also urge the CPUC to withdraw the November 19, 2013 Proposed Decision on Phase 1 and Phase 1A issues in the OII. During the pendency of proceedings regarding the Settlement Agreement, the Settling Parties are further bound to support and mutually defend the Settlement Agreement in its entirety, oppose any modifications proposed by any non-settling party to the OII unless all Settling Parties agree, and cooperate reasonably on all submissions. The Settling Parties further agree to review any CPUC orders regarding the Settlement Agreement to determine if the CPUC has changed or modified it, deleted a term or imposed a new term. If any Settling Party is unwilling to accept any such change, modification, deletion or addition of a new term, then the Settling Parties will negotiate in good faith to seek a resolution acceptable to all Settling Parties. If they are unable to resolve the matter to the satisfaction of all Settling Parties or to obtain prompt CPUC approval of an agreed upon resolution, then any Settling Party can terminate the Settlement Agreement upon prompt notice.

Under CPUC rules, parties in the OII will have an opportunity to comment on the Settlement Agreement, and if there are objections raising factual issues, then the CPUC’s review may include evidentiary proceedings. CPUC rules do not provide for any fixed time period for the CPUC to act on the Settlement Agreement. Pursuant to the CPUC’s rules, no settlement becomes binding on the parties to it unless the CPUC approves the settlement based on a finding that it is reasonable in light of the whole record, consistent with law, and in the public interest. The CPUC has discretion to approve or disapprove a settlement, or to condition its approval on changes to the settlement, which the parties may accept or reject.

Accordingly, there can be no assurance regarding the timing of any CPUC decision or that the CPUC will approve the Settlement Agreement or refrain from making changes to it that are not acceptable to all the Settling Parties. Thus, there can be no assurance that the OII proceeding will provide for recoveries as currently estimated by SCE in accordance with the Settlement Agreement, including the recovery of costs recorded as a regulatory asset, or that the CPUC does not order refunds to customers above those contemplated by the Settlement Agreement. Therefore, the amount recorded for the San Onofre Regulatory Asset is subject to further change based upon future developments and the application of SCE’s judgment to those events.

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Item  7.01 Regulation FD

Members of Edison International and SCE management will use the information in the presentation attached hereto as Exhibit 99.1 in an investor teleconference to be held on March 27, 2014. The attached presentation will also be posted on Edison International's website.

Certain documents distributed at the settlement conference prior to signing the Settlement Agreement are attached hereto as Exhibit 99.2.

Item  9.01 Financial Statements and Exhibits

(d) Exhibits

See the Exhibit Index below.

Limitation on Incorporation by Reference

The information furnished in Item 7.01 and the Exhibits 99.1 and 99.2 attached hereto shall not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended. Registration statements or other documents filed with the U.S. Securities and Exchange Commission shall not incorporate the information in Item 7.01 or the Exhibits by reference, except as otherwise expressly stated in such filing. The information furnished in Item 7.01of this Current Report on Form 8-K will not be deemed an admission as to the materiality of any information in Item 7.01 that is required to be disclosed solely by Regulation FD.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EDISON INTERNATIONAL

(Registrant)

/s/ Mark C. Clarke

Mark C. Clarke

Vice President and Controller

Date: March 27, 2014

SOUTHERN CALIFORNIA EDISON COMPANY

(Registrant)

/s/ Mark C. Clarke

Mark C. Clarke

Vice President and Controller

Date: March 27, 2014

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EXHIBIT INDEX

Exhibit No.	Description
10.1	Settlement Agreement between Southern California Edison Company, San Diego Gas & Electric Company, the Office of Ratepayer Advocates, and The Utility Reform Network, dated March 27, 2014
99.1	Proposed SONGS Settlement Presentation, dated March 27, 2014
99.2	Certain Documents Distributed at the March 27, 2014 Settlement Conference

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EX-10.1

Exhibit 10.1

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Investigation on the Commission’s Own Motion into the Rates, Operations, Practices, Services and Facilities of Southern California Edison Company and San Diego Gas & Electric Company Associated with the San Onofre Nuclear Generating Station Units 2 and 3.	Investigation 12-10-013 (Filed October 25, 2012)
And Related Matters.	Application 13-01-016 Application 13-03-005 Application 13-03-013 Application 13-03-014

SONGS OII SETTLEMENT AGREEMENT BETWEEN SOUTHERN CALIFORNIA EDISON COMPANY, SAN DIEGO GAS & ELECTRIC COMPANY, THE OFFICE OF RATEPAYER ADVOCATES, AND THE UTILITY REFORM NETWORK

Dated: March 27, 2014

SONGS OII SETTLEMENT AGREEMENT BETWEEN SOUTHERN CALIFORNIA EDISON COMPANY, SAN DIEGO GAS & ELECTRIC COMPANY, THE OFFICE OF RATEPAYER ADVOCATES, AND THE UTILITY REFORM NETWORK

Southern California Edison Company (“SCE”), San Diego Gas & Electric Company (“SDG&E”), the Office of Ratepayer Advocates (“ORA”), and The Utility Reform Network (“TURN”) (hereinafter collectively referred to as the “Settling Parties”) agree to settle all claims, allegations, and liabilities in the Order Instituting Investigation Regarding San Onofre Nuclear Generating Station Units 2 and 3, I.12-10-013, and all proceedings that have been consolidated therewith (including A. 13-01-016, A. 13-03-005, A. 13-03-013, and A. 13-03-014) (the “OII”), on the following terms and conditions, which shall only become effective on the Effective Date (as defined below).

This settlement agreement (“Agreement”) is entered into as a compromise of disputed claims in order to minimize the time, expense, and uncertainty of further regulatory proceedings. ORA and TURN agree to the following terms and conditions as a complete and final resolution of all claims against SCE and SDG&E in the OII, and SCE and SDG&E agree to these terms and conditions as a complete and final resolution of the OII. This Agreement constitutes the sole agreement between the Settling Parties concerning the subject matter of this Agreement.

As explained herein, the Settling Parties shall jointly submit this Agreement to the California Public Utilities Commission (“Commission” or “CPUC”) for approval. If the Effective Date does not occur within 6 months following the date of submission to the Commission, the Agreement shall be subject to termination by any of the Settling Parties upon written notice to the other Settling Parties.

I.THE PARTIES

1.1. The parties to this Agreement are SCE, SDG&E, TURN, and ORA.

1.2. SCE is an investor owned public utility in the State of California and is subject to the jurisdiction of the Commission with respect to providing electric service to its customers.

1.3. SDG&E is an investor owned public utility in the State of California and is subject to the jurisdiction of the Commission with respect to providing electric service to its customers.

1.4. ORA is an independent division of the Commission whose statutory mission is to obtain the lowest possible rate for service consistent with reliable and safe service levels. In fulfilling this goal, ORA also advocates for customer and environmental protections.

1.5. TURN is an independent, non-profit consumer advocacy organization that represents the interests of residential and small commercial utility customers.

1.6. The following entities have filed motions seeking party status in the OII, but are not parties to this Agreement: Women’s Energy Matters, the Alliance for Nuclear

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Responsibility, the Coalition to Decommission San Onofre, Ruth Henricks, the World Business Academy, Friends of the Earth, the National Asian American Coalition, the Latino Business Chamber of Greater Los Angeles, the Ecumenical Center for Black Church Studies, the Chinese American Institute for Empowerment, the Nevada Hydro Company, Inc., City of Riverside, the Clean Coalition, the Coalition of California Utility Employees, the Western Power Trading Forum, the Direct Access Customer Coalition, the Alliance for Retail Energy Markets, Southern California Gas Company, Distributed Energy Consumer Advocates, the Utility Consumers’ Action Network, the Independent Energy Producers Association, the California Cogeneration Council, Noble Americas Energy Solutions LLC, Amerinet, Inc., Public Agency Coalition, and the State of California.

II.
DEFINITIONS

2.1. AFUDC: Allowance for Funds Used During Construction.

2.2. Agreement: This document and any appendices.

2.3. ALJ: Administrative Law Judge.

2.4. Authorized Cost of Debt: The rate of return on debt authorized by the CPUC for a given utility from time to time. This rate of return may change during any of the amortization periods set forth in this Agreement.

2.5. Authorized Cost of Preferred Stock: The rate of return on preferred stock authorized by the CPUC for a given utility from time to time. This rate may change during any of the amortization periods set forth in this Agreement.

2.6. Base Plant: The Net Book Value of all SONGS-related capital investments, except the SGRP, in the Utilities’ rate bases.

(a) Base Plant includes the Net Book Value for all SONGS-related marine mitigation investments that the Utilities made in response to the California Coastal Commission’s directives to mitigate environmental impacts of SONGS, except the $22 million disallowed by the Commission in Decision No. 06-05-016.

(b) Base Plant includes the Net Book Value for all SONGS-related NDBD&DD investments.

(c) Base Plant does not include an adjustment for cash working capital.

(d) Base Plant does not include the M&S Investment.

(e) Base Plant does not include the Nuclear Fuel Investment.

2.7. BRRBA: The generation sub-account of the Base Revenue Requirement Balancing Account, or its successor account.

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2.8. Original Cost: The initial outlay for an investment, equal to the gross sum of all recorded direct and indirect expenditures associated with the capital investment.

2.9. Capital-Related Revenue Requirement: The total amount of revenue required by a utility to recover its capital investments and associated income and property taxes (including the effect of deferred taxes), including a return on those investments calculated in accordance with the utility’s authorized cost of capital and associated depreciation expenses computed in accordance with depreciation schedules authorized by the Commission.

2.10. Commission or CPUC: The California Public Utilities Commission.

2.11. Commission Approval: A decision of the Commission approving the Agreement in the form submitted without modification that has become final and is no longer subject to appeal.

2.12. Consolidated Proceedings: All proceedings that have been consolidated with the OII, including A. 13-01-016, A. 13-03-005, A. 13-03-013, and A. 13-03-014.

2.13. CWIP: CWIP means Construction Work In Progress or replacement projects (retirement work in progress or net salvage) recorded directly in accumulated depreciation.

(a) Cancelled CWIP: The total Original Cost of CWIP associated with SONGS-related projects that began prior to the Effective Date but that will not enter service at any time after February 1, 2012.

(b) Completed CWIP: The total Original Cost of CWIP associated with SONGS-related projects that began prior to the Effective Date and will enter service at any point after February 1, 2012, including all CWIP that will enter service after the Effective Date.

2.14. Effective Date: The day of the Commission’s decision adopting the ratemaking proposal set forth in this Agreement.

2.15. ERRA: Energy Resource Recovery Account, or its successor account.

2.16. FERC: Federal Energy Regulatory Commission.

2.17. Fuel Cancellation Costs: The total recorded costs (other than those costs that the Utilities are able to recover from the Nuclear Decommissioning Trusts) associated with cancelling SCE’s contracts entered into by SCE as the SONGS Operating Agent on behalf of itself and SDG&E to purchase nuclear fuel, including but not limited to the following costs:

(a) Termination fees and other amounts paid to obtain a release of any obligations under fuel procurement contracts.

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(b) Amounts paid by SCE as Operating Agent for itself and on behalf of SDG&E to fuel procurement vendors pursuant to settlements, judgments, or arbitration awards related to disputes arising from SCE’s termination of alleged contractual obligations to purchase nuclear fuel.

(c) Attorneys fees and other litigation costs incurred on and after January 1, 2013 by SCE as Operating Agent for itself and on behalf of SDG&E in seeking to minimize its obligations under fuel procurement contracts through arbitrations, negotiations, and/or judicial or administrative proceedings.

2.18. Fuel Net Proceeds: The total proceeds of all sales of nuclear fuel, net of costs incurred by SCE as Operating Agent for itself and on behalf of SDG&E in order to sell such nuclear fuel, including but not limited to:

(a) Costs incurred in order to store the nuclear fuel inventory pending the sale; and

(b) Costs incurred in order to render the nuclear fuel saleable.

2.19. Incremental Inspection and Repair Costs: Those costs recorded by the Utilities as incremental expenses associated with SCE’s efforts to inspect and repair the damage at SONGS. This amount also includes the $11 million (100% share) in costs for inspection and repair of SONGS that SCE originally recorded as base O&M and subsequently re-classified as incremental O&M.

2.20. Mitsubishi: Mitsubishi Heavy Industries, Ltd., related entities such as Mitsubishi Nuclear Energy Systems and Mitsubishi Heavy Industries America Inc., and any third party who has insured or indemnified any of these entities for any amounts owed to the Utilities in respect of the replacement steam generators.

2.21. M&S Investment: The total Original Cost of materials and supplies investments associated with SONGS.

2.22. M&S Net Proceeds: The total proceeds of all sales of materials and supplies, net of costs incurred by SCE in order to sell such materials and supplies.

2.23. NDBD&DD: Nuclear Design Basis Documentation and Deferred Debits. NDBD costs are associated with SCE’s efforts to comply with the NRC’s mandate that SCE establish a nuclear design documentation system. DD costs are plant-related regulatory assets that resolve accounting differences in capitalization policies between CPUC and FERC jurisdictions regarding the commercial operation of SONGS.

2.24. Net Book Value: Original Cost less the accumulated amortization and depreciation expenses, if any, associated with an investment.

2.25. NEIL: Nuclear Energy Insurance Limited.

2.26. NGBA: Non-fuel Generation Balancing Account, or its successor account.

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2.27. Non-O&M Balancing Account Expenses: All SONGS-related expenses for pensions, post-retirement benefits other than pensions, and short-term incentive compensation that are not recorded in FERC accounts 517-532.

2.28. Non-O&M Expenses: All SONGS-related expenses recorded in FERC accounts 408, 924, 925, and 926 that are not:

(a) Non-O&M Balancing Account Expenses;

(b) Capitalized overhead; or

(c) Recorded in FERC accounts 517-532.

2.29. Nuclear Decommissioning Trusts: The trusts established by the Utilities and approved by the CPUC pursuant to the Nuclear Facilities Decommissioning Act of 1985, Cal. Pub. Util. Code Sec. 8321 et seq., for the purpose of covering costs associated with decommissioning SONGS.

2.30. Nuclear Fuel Investment: The Net Book Value of all nuclear fuel (including in-core fuel and pre-core fuel), plus all Fuel Cancellation Costs. To the extent that SCE, as Operating Agent on behalf of itself and on behalf of SDG&E, incurs additional Fuel Cancellation Costs after the date of execution of this Agreement, those costs will be added to the Nuclear Fuel Investment at the time they are incurred.

2.31. NRC: Nuclear Regulatory Commission.

2.32. O&M: Operations and Maintenance.

2.33. OII: Order Instituting Investigation. As used in this Agreement, the term “OII” shall refer to the proceeding initiated by the Commission in I. 12-10-013, and all Consolidated Proceedings.

2.34. Operating Agent: SCE is the Operating Agent responsible for the performance of the operation and maintenance of SONGS.

2.35. ORA: The Office of Ratepayer Advocates or its successor division.

2.36. SCE: Southern California Edison Company.

2.37. SDG&E: San Diego Gas & Electric Company.

2.38. Settling Parties/Settling Party: SCE, SDG&E, ORA, and TURN, or any of them.

2.39. SGRP: Steam Generator Replacement Project.

2.40. SONGS: San Onofre Nuclear Generating Station.

2.41. SONGSBA: SDG&E’s San Onofre Nuclear Generating Station O&M Balancing Account.

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2.42. SONGS Litigation Balance: The total SONGS Litigation Recoveries, net of SONGS Litigation Costs.

2.43. SONGS Litigation Costs: All litigation costs recorded since January 31, 2012, including but not limited to fees paid to outside attorneys and experts, associated with pursuing and preparing to pursue SONGS Litigation Recoveries.

2.44. SONGS Litigation Recoveries: Any amounts received (whether by settlement, judicial order, arbitration award, or any other recovery) by the Utilities from NEIL and/or Mitsubishi or their respective affiliates in connection with the Utilities’ efforts to pursue recovery of amounts in respect of the failure of the steam generators and subsequent permanent shut down of SONGS. Any amounts obtained by the City of Riverside are not subject to this Agreement.

2.45. SONGSMA: SCE’s San Onofre Nuclear Generating Station Memorandum Account.

2.46. SONGSOMA: Either Utility’s San Onofre Nuclear Generating Station Outage Memorandum Account, including SDG&E’s SONGS OMA.

2.47. TURN: The Utility Reform Network.

2.48. U2C17 RFO: The refueling and maintenance outage for SONGS Unit 2 that was intended to last from January 10, 2012, until March 5, 2012.

2.49. Utility/Utilities: SCE and SDG&E, or either of them.

III.
GENERAL RECITALS

3.1. SCE owns a 78.21% share of SONGS. SDG&E owns a 20% share of SONGS. The City of Riverside owns a 1.79% share of SONGS.

3.2. In Decision No. 05-12-040, the Commission approved SCE’s application to replace the steam generators in SONGS Units 2 and 3.

3.3. In Decision No. 06-11-026, the Commission found that SDG&E’s participation in the SGRP was reasonable and approved an unopposed settlement agreement, including SDG&E’s ownership share of the maximum allowable 100%, 2004$, level of the SGRP cost plus SDG&E’s internal costs.

3.4. In January 2010, SCE replaced the steam generators in SONGS Unit 2. In January 2011, SCE replaced the steam generators in SONGS Unit 3.

3.5. The replacement steam generators in Units 2 and 3 were designed and manufactured by Mitsubishi.

3.6. On January 10, 2012, SONGS Unit 2 was removed from service for a scheduled refueling and maintenance outage that was expected to end on March 5, 2012.

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3.7. On January 31, 2012, SONGS Unit 3 was taken offline because station operators at SONGS detected a leak in a steam generator tube.

3.8. In early February, 2012, inspections of Unit 2 steam generators showed accelerated tube wear. This tube wear caused unexpected and extensive property damage to Unit 2’s steam generators

3.9. In February and March, 2012, inspections in Unit 3 revealed extensive wear on the Unit’s steam generator tubes. Some of this wear was caused by the steam generator tubes rubbing against each other (“tube-to-tube wear”). This tube-to-tube wear caused unexpected and extensive property damage to Unit 3’s steam generators.

3.10. On March 27, 2012, the NRC issued a Confirmatory Action Letter confirming SCE’s commitment not to restart either Unit 2 or Unit 3 until the source of the tube wear was understood and SCE had confidence that the units could be safely restarted.

3.11. Further inspections of the Unit 2 steam generators revealed more property damage in the form of early indications of tube-to-tube wear. SCE formally notified the NRC of SCE’s finding of tube-to-tube wear in Unit 2 on April 20, 2012.

3.12. On November 1, 2012, the Commission issued an Order Instituting Investigation Regarding San Onofre Nuclear Generating Station Units 2 and 3. (I. 12-10-013.) The Order stated that the Commission intended to examine “the causes of the outages, the utilities’ responses, the future of the SONGS units, and the resulting effects on the provision of safe and reliable electric service at just and reasonable rates.” The Order also set SONGS-related rates subject to refund as of January 1, 2012, and directed that the Utilities establish a memorandum account (the SONGSOMA) for the purpose of tracking those costs.

3.13. On December 10, 2012, the Commission issued Decision No. 12-11-051, which resolved SCE’s 2012 General Rate Case. Decision No. 12-11-051 directed SCE to establish a memorandum account (the “SONGSMA”), effective January 1, 2012, to track certain SONGS-related costs. The Commission further ordered SCE to file a reasonableness review application for post-2011 expenses recorded in the SONGSMA by January 31, 2013. In accordance with this directive, SCE filed A. 13-01-016 on January 31, 2013. A. 13-01-016 has been consolidated with this OII.

3.14. In D.12-11-051, the Commission also made SDG&E subject to the same conditional refund of SDG&E’s share of the SONGS-related O&M and capital costs. (See D.12-11-051 at 40-41, Finding of Fact 36, Conclusions of Law 21 and 22, Ordering Paragraphs 10 and 11.) On March 19, 2013, SDG&E filed A.13-03-005 requesting a reasonableness determination of SDG&E’s internal SONGS costs incurred during 2012 and capital expenses (excluding the SGRP) that were invoiced by SCE to SDG&E, including SCE’s overheads, and tracked in SDG&E’s SONGSOMA. A.13-03-014 has been consolidated with this OII.

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3.15. On January 28, 2013, the Assigned Commissioner and ALJ issued a Scoping Memo and Ruling. The Scoping Memo divided the OII into phases and provided that the OII would examine the following issues:

(a) In Phase 1, the Commission would examine:

(i) “Nature and effects of the steam generator failures in order to assess the reasonableness of SCE’s consequential actions and expenditures (e.g., was it reasonable to remove fuel from unit #3).”

(ii) “Whether 2012 SONGS-related expenses recorded in the SONGSMA are reasonable and necessary, including,

(A) 100% of O&M, including segregated safety-related costs;

(B) 100% of cost-savings from personnel reductions and other avoided costs;

(C) 100% of maintenance and refueling outage expenses; and

(D) 100% of capital expenditures.”

(iii) “A review of the reasonableness and effectiveness of SCE’s actions and expenditures for community outreach and emergency preparedness related to the SONGS outages.”

(iv) “Other issues as necessary to determine whether SCE should refund any rates preliminarily authorized in the 2012 GRC, in light of the changed facts and circumstances of the unit outages; and if so, when the refunds should occur.”

(b) In Phase 2, the Commission would examine “whether any reductions to SCE’s rate base and SCE’s 2012 revenue requirement are warranted or required due to the extended SONGS outages.”

(c) In Phase 3, the Commission would examine “causes of the [steam generator] damage and allocation of responsibility, whether claimed SGRP expenses are reasonable, including review of utility-proposed repair and/or replacement cost proposals using cost-effectiveness analysis and other factors.”

(d) In Phase 4, if necessary, the Commission would examine “whether SCE’s 2013 revenue requirement should be adjusted to reflect lower-than forecast O&M, Capex, replacement power costs, and other SONGS expenses.”

3.16. From December, 2012, through April, 2013, the Settling Parties exchanged testimony regarding Phase 1 issues.

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3.17. On March 15, 2013, SCE filed A. 13-03-005, seeking Commission approval to include the recorded capital costs of the SGRP permanently in rates. SCE’s testimony in support of this application established that the total recorded cost of the SGRP was $768.5 million in nominal dollars (100% share). SCE’s testimony in support of this application also established that the total recorded cost of the SGRP, adjusted for inflation using the Handy-Whitman index for fabrication and construction costs and the Commission-approved nuclear decommissioning burial escalation rates for burial costs, was $612.1 million in 2004 dollars (100% share). A. 13-03-005 has been consolidated with this OII.

3.18. On March 18, 2013, SDG&E filed A. 13-03-014, seeking Commission approval to include SGD&E’s share of recorded capital costs of the SGRP permanently in rates. A. 13-03-014 has been consolidated with this OII.

3.19. On April 2, 2013, SCE served testimony addressing the energy-market related impact of the SONGS outages in its ERRA compliance review proceeding (A. 13-04-001). On May 1, 2003, SDG&E served testimony addressing the energy-market related impact of the SONGS outages in I. 12-10-013.

3.20. On April 19, 2013, ALJs Darling and Dudney issued an Order clarifying that the topics identified in the January 28, 2013, Scoping Memo applied equally to SCE and SDG&E.

3.21. On May 6, 2013, by e-mail ruling, ALJ Dudney ruled that the OII would consider the issue of “what replacement power was purchased by the utilities in 2012 as a consequence of the SONGS outages.” ALJ Dudney scheduled separate evidentiary hearings to address this “replacement power” issue. The phase of the OII addressing this issue came to be known as Phase 1A.

3.22. ALJ Darling held an evidentiary hearing on Phase 1 issues from May 13, 2013, until May 17, 2013. The Settling Parties each submitted Opening and Reply Briefs on Phase 1 issues.

3.23. On June 7, 2013, SCE permanently retired SONGS Units 2 and 3. SCE had determined that Mitsubishi made errors in designing and manufacturing the replacement steam generators for Units 2 and 3. SCE determined that these errors caused deficiencies in design, manufacturing, and workmanship that prevented SCE from safely operating Units 2 or 3 as intended and contracted for. SCE determined that, because Mitsubishi had not proposed a viable plan to repair or replace the replacement steam generators in a timely manner, and because of the significant uncertainty as to whether or when Unit 2 would be permitted to restart even at partial power for a reduced operating period, it was no longer prudent to continue to pursue restart or repair.

3.24. On July 1, 2013, ALJs Darling and Dudney issued a Ruling on Miscellaneous Scheduling and Procedural Issues and Notice of Phase 2 Prehearing Conference. The ruling provided the following “statement” of the scope of Phase 2:

(a) What are the values of SONGS assets in rate base, and which of these assets should be removed from rate base pursuant to Public Utilities Code § 455.5, as of

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November 1, 2012, or a later date if any such asset became not “used and useful” after November 1, 2012?

(b) What are the related Operations and Maintenance costs associated with the assets removed from rate base according to [the issue] above?

(c) Any other issues relevant to the application of § 455.5 to the SONGS outage.

3.25. In July, 2013, the Settling Parties exchanged testimony on Phase 1A issues.

3.26. On July 22, 2013, ALJs Darling and Dudney further specified that Phase 1A would address “the method for calculating the cost of replacement power during 2012 due to the SONGS outage. This scope includes developing a formula/method for the calculation of costs (capacity, energy, foregone sales, and congestion) and establishing what values should be entered in to that formula.”

3.27. From July, 2013, until September, 2013, the Settling Parties exchanged testimony on Phase 2 issues.

3.28. ALJ Dudney held an evidentiary hearing on Phase 1A from August 5, 2013, until August 6, 2013. The Settling Parties each filed Opening and Reply Briefs on Phase 1A issues.

3.29. ALJs Dudney and Darling held an evidentiary hearing on Phase 2 issues from October 7, 2013, until October 11, 2013. The Settling Parties each filed Opening and Reply Briefs on Phase 2 issues.

3.30. Throughout the proceeding, SCE responded to 928 data request questions propounded by the parties to the OII. SDG&E similarly responded to data request questions propounded to it by the parties to the OII.

3.31. On October 16, 2013, SCE as the Operating Agent and Edison Material Supply LLC (“EMS”) filed a Request for Arbitration against Mitsubishi pursuant to the arbitration clause in the contract between EMS and Mitsubishi. Through this arbitration, which is ongoing as of the date of this Agreement, SCE and EMS are seeking recovery from Mitsubishi based on the non-operation of SONGS Units 2 and 3.

3.32. On July 18, 2013, SDG&E filed a complaint in California Superior Court against Mitsubishi seeking to recover damages SDG&E has incurred and will incur related to the defects in the steam generators. This action was later removed to Federal District Court. On August 8, 2013, Mitsubishi filed a motion to stay the action pending arbitration and on March 14, 2014, the Court issued an order granting Mitsubishi’s motion on the condition that SDG&E must be able to fully assert its own claims in an arbitration proceeding.

3.33. The Utilities have also submitted claims to NEIL based on their assessments that both SONGS units sustained accidental property damage. SCE has submitted proofs of loss under insurance policies covering SONGS and is continuing to pursue recovery as of the date of this Agreement.

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3.34. On November 19, 2013, ALJs Darling and Dudney issued a Proposed Decision on Phase 1 and Phase 1A issues. Each of the Settling Parties submitted Opening Comments on the Proposed Decision on December 9, 2013. Each of the Settling Parties submitted Reply Comments on the Proposed Decision on December 16, 2013.

3.35. On January 15, 2014, the Commission held an all-party meeting to discuss the Proposed Decision on Phase 1 and Phase 1A issues.

3.36. SCE’s share of the Net Book Value of the SGRP was $597 million as of February 1, 2012, including CWIP. SDG&E’s share of the Net Book Value of the SGRP was $160.4 million as of February 1, 2012, including CWIP.

3.37. SCE’s share of Base Plant was $622 million as of February 1, 2012, excluding CWIP. SDG&E’s share of Base Plant was $165.6 million as of February 1, 2012, excluding CWIP.

3.38. SCE’s share of the Nuclear Fuel Investment was $477 million as of December 31, 2013, exclusive of any paid or accrued Fuel Cancellation Costs. SDG&E’s share of the Nuclear Fuel Investment was $115.8 million as of December 31, 2013, exclusive of any paid or accrued Fuel Cancellation Costs.

3.39. SCE’s share of the M&S Investment was $99 million as of December 31, 2013. SDG&E’s share of the M&S Investment was $10.4 million as of December 31, 2013.

3.40. SCE’s share of Cancelled CWIP is estimated at $153 million as of December 31, 2013. Subject to an additional reconciliation with SCE, SDG&E’s Cancelled CWIP amounts will be provided pursuant to section 6.1 hereof, subject to ORA’s and TURN’s prerogative stated in the last sentence thereof.

3.41. SCE’s share of Completed CWIP is estimated at $302 million as of December 31, 2013. Subject to an additional reconciliation with SCE, SDG&E’s Completed CWIP amounts will be provided pursuant to section 6.1 hereof, subject to ORA’s and TURN’s prerogative stated in the last sentence thereof.

3.42. SCE’s share of O&M costs recorded in connection with the U2C17 RFO is $41.1 million, which consists of $4.9 million recorded in 2011, $35.3 million recorded in 2012, and $0.9 million recorded in 2013. SDG&E’s share of O&M costs recorded in connection with the U2C17 RFO as calculated by SCE is $9.3 million.

3.43. Decision No. 12-11-051 provisionally authorized $387.4 million (100% share) in base O&M costs for the year 2012 and $397.6 million (100% share) in base O&M costs for the year 2013.

3.44. In 2012, SCE recorded $99 million (SCE share) in Incremental Inspection and Repair Costs in excess of the amount of base O&M provisionally authorized in Decision No. 12-11-051. In 2012, SCE estimated that SDG&E paid $27.0 million in total Incremental Inspection and Repair Costs, including SCE overheads and portions allocated to Base and Incremental O&M. SDG&E’s base O&M provisionally authorized in Decision No. 12-

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11-051 and D.13-05-010 was greater than the total amount of recorded costs including overheads, as applicable to SDG&E.

3.45. SDG&E recorded $141.6 million, including overheads paid to SCE, to its SONGSBA in 2012; $27.0 million, including overheads paid to SCE, was defined by SCE as Incremental Inspection and Repair Costs in Base and Incremental O&M.

3.46. In 2013, SCE’s share of recorded base O&M costs was $241 million and SCE’s share of recorded Incremental Inspection and Repair Costs was $12 million.

3.47. SDG&E recorded $105.0 million, including overheads paid to SCE, to its SONGSBA in 2013.

3.48. SCE’s total amount of deferred taxes on SONGS investment (excluding investment in the SGRP) as of Feb 1, 2012, was $152 million. SDG&E’s total amount of deferred taxes on SONGS investment (excluding investment in the SGRP) as of February 1, 2012 is estimated at $4.5 million.

IV.
SETTLEMENT AGREEMENT TERMS AND CONDITIONS

4.1. In consideration of the mutual obligations, promises, covenants and conditions contained herein, the Settling Parties agree to support approval by the Commission of this Agreement, as further described herein, and to support this Agreement in its entirety before any regulatory agency or court of law where this Agreement, its meaning or effect is an issue, and no Settling Party shall take or advocate for, either directly, or indirectly through another entity, any action that would have the effect of modifying or abrogating the terms of this Agreement.

4.2. Capital-Related Revenue Requirement for the SGRP

(a) The Capital-Related Revenue Requirement for the SGRP will be terminated as of February 1, 2012.

(b) The Utilities shall refund to ratepayers all amounts collected in rates as the Capital-Related Revenue Requirement for the SGRP for all periods on and after February 1, 2012. These amounts shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.

(c) The Utilities will retain all amounts collected in rates as the Capital-Related Revenue Requirements for the SGRP for periods prior to February 1, 2012.

(d) The Utilities shall not recover in rates the Net Book Value of the SGRP as of February 1, 2012.

4.3. Base Plant

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(a) The Utilities’ respective shares of Base Plant will be removed from each Utility’s respective rate base as of February 1, 2012. The Utilities will retain all amounts collected in rates in respect of Capital-Related Revenue Requirements for Base Plant for periods prior to February 1, 2012.

(b) As of February 1, 2012, the Utilities will amortize Base Plant in rates as a regulatory asset ratably over 10 years.

(i) This amortization period will begin on February 1, 2012, and will end on February 1, 2022.

(ii) The Utilities have already collected amounts in rates in respect of Capital-Related Revenue Requirements for Base Plant for periods on and after February 1, 2012. To the extent that these amounts collected exceed the amounts permitted by this Agreement for periods on and after February 1, 2012, the Utilities shall refund the excess to ratepayers. These excess amounts shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.

(c) During the amortization period set forth in Section 4.3(b)(i) of this Agreement, each Utility shall earn a return on its respective share of unrecovered Base Plant, adjusted for deferred taxes. Each Utility’s rate of return on unrecovered Base Plant shall be calculated as the Utility’s Authorized Cost of Debt plus 50% of the Utility’s Authorized Cost of Preferred Stock, weighted by the amount of debt and preferred stock in the Utility’s authorized ratemaking capital structure. For the avoidance of doubt, the rate of return on common equity shall not be considered.

(i) The methodology for computing Base Plant to adjust for deferred taxes is illustrated in Appendix A to this Agreement.

(d) The Settling Parties agree that the Authorized Cost of Debt and the Authorized Cost of Preferred Stock described in Section 4.3(c) of this Agreement are floating rates that shall vary based on the rates authorized by the Commission at any given time.

(e) Pursuant to the method of calculating the return on Base Plant set forth in Section 4.3(c) of this Agreement, SCE will earn a rate of return of 2.95% on unrecovered Base Plant for the period February 1, 2012, through December 31, 2012. This rate of return is equal to:

(i) 6.22% weighted by the amount of debt in SCE’s authorized ratemaking capital structure; plus

(ii) 50% of 6.01% weighted by the amount of preferred stock in SCE’s authorized ratemaking capital structure.

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(f) Pursuant to the method of calculating the return on Base Plant set forth in Section 4.3(c) of this Agreement, SCE will earn a rate of return of 2.62% on unrecovered Base Plant for the years 2013 and 2014. This rate of return is equal to:

(i) 5.49% weighted by the amount of debt in SCE’s authorized ratemaking capital structure; plus

(ii) 50% of 5.79% weighted by the amount of preferred stock in SCE’s authorized ratemaking capital structure.

(g) Pursuant to the method of calculating the return on Base Plant set forth in Section 4.3(c) of this Agreement, SDG&E will earn a rate of return of 2.75% on unrecovered Base Plant for the period February 1, 2012, through December 31, 2012. This rate of return is equal to:

(i) 5.62% weighted by the amount of debt in SDG&E’s authorized ratemaking capital structure; plus

(ii) 50% of 7.25% weighted by the amount of preferred stock in SDG&E’s authorized ratemaking capital structure.

(h) Pursuant to the method of calculating the return on Base Plant set forth in Section 4.3(c) of this Agreement, SDG&E will earn a rate of return of 2.35% on unrecovered Base Plant for the years 2013 and 2014. This rate of return is equal to:

(i) 5.00% weighted by the amount of debt in SDG&E’s authorized ratemaking capital structure; plus

(ii) 50% of 6.22% weighted by the amount of preferred stock in SDG&E’s authorized ratemaking capital structure.

(i) The Settling Parties agree that the rates of return set forth in Section 4.3(e)-(h) of this Agreement do not reflect income taxes associated with the Utilities’ preferred equity return. Notwithstanding that fact, the Utilities will recover all income tax expenses associated with each Utility’s preferred equity return. Each Utility will therefore factor in a gross-up for this income tax when calculating its revenue requirement. This gross-up would be calculated in compliance with the Commission’s customary practices according to decisions rendered in OII 24, which was closed by Decision No. 84-05-036 (1984). In addition, the revenue requirement shall include franchise fees and uncollectibles.

(j) Notwithstanding Section 4.3(a) of this Agreement, the Utilities shall recover in rates all property taxes paid with respect to Base Plant, including amounts paid after February 1, 2012. To the extent rates include a forecast for these property taxes, the recovery shall be trued up to recorded amounts.

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4.4. At its option, without affecting the rates of return calculated in accordance with the foregoing, each Utility may select to exclude the regulatory assets to be amortized pursuant to this Agreement when measuring each Utility’s ratemaking capital structure for any purpose. In other words, the regulatory assets may be financed solely with debt, and the capital supporting these assets will not be recognized in determining each Utility’s ratemaking capital structure or cost of capital for the purposes of this Agreement or for any other purpose, if the Utility so chooses. If a Utility selects this option, the Settling Parties will support exclusion of the capital financing of these regulatory assets in determining the Utility’s overall AFUDC rate calculation at both the CPUC and FERC.

4.5. M&S Investment

(a) Each Utility’s respective share of the M&S Investment as of the last day of the month of the Effective Date shall be amortized as a regulatory asset ratably over the amortization period set forth for Base Plant in Section 4.3(b)(i) of this Agreement, and shall earn a rate of return during that amortization period equal to the rate set forth for Base Plant in Section 4.3(c) of this Agreement.

(b) To the extent that the Utilities are able to sell assets associated with the M&S Investment, and in order to incentivize the Utilities to do so, the following incentive mechanism shall be adopted notwithstanding the terms set forth in Section 4.5(a) of this Agreement:

(i) The Utilities shall retain their respective shares of 5% of all M&S Net Proceeds; and

(ii) The Utilities shall credit to their ratepayers their respective shares of the remaining 95% of all M&S Net Proceeds.

(c) On a monthly basis, the Utilities shall distribute the ratepayers’ portion of the proceeds of all sales of materials and supplies by providing credits to SCE’s BRRBA and SDG&E’s NGBA.

(d) The Settling Parties agree that the Utilities will, to the extent permitted by applicable tax laws without penalty and CPUC action, seek reimbursement of the M&S Investment from the Nuclear Decommissioning Trusts rather than recovering this investment through rates. The Utilities will not amortize in rates any portion of the M&S Investment that has been paid for by the Nuclear Decommissioning Trusts. To the extent the Utilities are unable to obtain full reimbursement of the M&S Investment from the trusts, the unreimbursed investments shall be added to the regulatory asset described in Section 4.5(a) of this Agreement (i.e., the M&S Investment) regardless of whether the inventory associated with that asset is used by the Utilities.

4.6. Nuclear Fuel Investment

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(a) The Nuclear Fuel Investment as of the last day of the month of the Effective Date shall be amortized as a regulatory asset ratably over the amortization period set forth for Base Plant in Section 4.3(b)(i) of this Agreement.

(b) During the amortization period set forth in Section 4.6(a) of this Agreement, the Utilities shall earn a rate of return on their respective shares of the unrecovered balance of the Nuclear Fuel Investment. This rate of return shall be equal to the cost of commercial paper (as defined in Section ZZ, 2. j of the preliminary statement of SCE’s CPUC tariffs [or its successor] and in Section I.E.3 of the preliminary statement of SDG&E’s CPUC tariffs [or its successor]) throughout the amortization period. The Settling Parties agree that the cost of commercial paper may change during the amortization period. The Settling Parties further agree that the rate that each Utility shall earn on the unrecovered balance of the Nuclear Fuel Investment will float with the commercial paper rate throughout the amortization period, such that each Utility will recover its actual costs of financing the Nuclear Fuel Investment with commercial paper, as those costs are incurred.

(c) The Settling Parties agree that, as of the date of execution of this Agreement, SCE still has outstanding alleged contractual obligations to purchase nuclear fuel. The Settling Parties further agree that Fuel Cancellation Costs incurred after the Effective Date will be added to the regulatory asset described in Section 4.6(a) of this Agreement (i.e., the Nuclear Fuel Investment) as those costs are incurred.

4.7. Incentive Mechanisms For Mitigation Of Nuclear Fuel Costs

(a) To the extent that SCE is able to sell any portion of its current nuclear fuel inventory, and in order to incentivize SCE to do so, the following incentive mechanism shall be adopted notwithstanding the terms set forth in Section 4.6 of this Agreement:

(i) The Utilities shall retain their respective shares of 5% of all Fuel Net Proceeds; and

(ii) The Utilities shall credit to their ratepayers their respective shares of the remaining 95% of all Fuel Net Proceeds.

(b) Upon each sale of nuclear fuel, the Utilities shall distribute the ratepayers’ portion of the Fuel Net Proceeds by reducing the amount of the regulatory asset described in Section 4.6(a) of this Agreement (i.e., the Nuclear Fuel Investment). The effect of this reduction to the Nuclear Fuel Investment shall be to decrease the yearly amount of the revenue requirement for Nuclear Fuel Investment. This reduction to the regulatory asset shall not affect the amortization period for Base Plant described in Section 4.3(b)(i) of this Agreement.

(c) To the extent that SCE, as Operating Agent on its own behalf and on behalf of SDG&E, is able to minimize the Fuel Cancellation Costs incurred after the date of execution of this Agreement, and in order to incentivize SCE to do so, the

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following incentive mechanism applicable to the Utilities shall be adopted notwithstanding the terms set forth in Section 4.6 of this Agreement:

(i) The regulatory asset described in Section 4.6(a) of this Agreement (i.e., the Nuclear Fuel Investment) shall be increased by 5% of the difference between:

(A) The sum of all amounts stated as SCE’s purchase obligations (as Operating Agent on its own behalf and on behalf of SDG&E) in outstanding nuclear fuel contracts, on the one hand; and

(B) SCE’s total recorded Fuel Cancellation Costs (as Operating Agent on its own behalf and on behalf of SDG&E), on the other hand.

(ii) The Utilities shall each establish a memorandum account to determine the yearly amount of the incentive described in Section 4.7(c)(i). In order to account for all recorded costs and cancelled obligations since January 31, 2012, each Utility shall establish this memorandum account as of January 31, 2012. Every time SCE cancels a nuclear fuel contract (or is otherwise relieved from its obligations thereunder), the Utilities shall record a positive value in this memorandum account equal to the amount stated in the contract as SCE’s purchase obligation. The Utilities shall also record all Fuel Cancellation Costs, as they are incurred, as negative values in this account. If there is a negative balance in either Utility’s account at the end of a given year, the negative balance will be carried over to the next year. If there is a positive balance in either Utility’s account at the end of a given year, the Utility shall increase the regulatory asset described in Section 4.6(a) of this Agreement (i.e., the Nuclear Fuel Investment) by 5% of this balance. The effect of any increase to the regulatory asset pursuant to this incentive mechanism shall be to increase the yearly amount of the revenue requirement for Nuclear Fuel Investment. This increase to the regulatory asset shall not affect the amortization period for Base Plant described in Section 4.3(b)(i) of this Agreement. Positive balances shall not carry over from one year to the next; instead, the account balance shall be reset to zero on the first of the year following any increase to the regulatory asset pursuant to this Section of the Agreement.

4.8. CWIP

(a) The Utilities will recover in rates the full amounts recorded as SONGS-related CWIP, including the full amounts of both Cancelled CWIP and Completed CWIP. The CWIP balance shall be recovered as follows:

(i) For Cancelled CWIP:

(A) An AFUDC amount for the Cancelled CWIP balance will be applied from the date of the first recorded amount of Cancelled

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CWIP until January 31, 2012. The AFUDC rate shall be equal to the authorized AFUDC rate in effect at the time.

(B) The AFUDC amount, as calculated in Section 4.8(a)(i)(A) of this Agreement, shall be added to the balance for Cancelled CWIP.

(C) The Cancelled CWIP balance (including the AFUDC amount) as of the last day of the month of the Effective Date shall be amortized as a regulatory asset ratably over the amortization period set forth for Base Plant in Section 4.3(b)(i) of this Agreement.

(D) During the amortization period set forth in Section 4.8(a)(i)(C) of this Agreement, the Cancelled CWIP balance (plus all accumulated AFUDC), adjusted for deferred taxes if applicable, shall earn a rate of return equal to the rate set forth for Base Plant in Section 4.3(c) of this Agreement.

(ii) For Completed CWIP:

(A) An AFUDC amount for the Completed CWIP balance will be applied from the date of the first recorded amount of Completed CWIP until the last day of the month of the Effective Date. The AFUDC rate will be as follows:

(1) For the period from the date of the first recorded amount of Completed CWIP until January 31, 2012, the AFUDC rate shall be equal to the authorized AFUDC rate in effect at the time.

(2) For the period from February 1, 2012, until the date on which the associated asset was placed into service or the Effective Date (whichever is earlier) , the AFUDC rate shall be equal to the rate set forth for Base Plant in Section 4.3(c) of this Agreement.

(B) The AFUDC amount, as calculated in Section 4.8(a)(ii)(A) of this Agreement, shall be added to the balance for Completed CWIP.

(C) The Completed CWIP balance (including all accumulated AFUDC) as of the last day of the month of the Effective Date shall be amortized as a regulatory asset ratably starting on the date on which the associated asset was placed into service or the Effective Date (whichever is earlier) and ending on February 1, 2022.

(D) During the amortization period set forth in Section 4.8(a)(ii)(C) of this Agreement, the Completed CWIP balance (plus all accumulated AFUDC), adjusted for deferred taxes if applicable,

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shall earn a rate of return equal to the rate set forth for Base Plant in Section 4.3(c) of this Agreement

(b) The Settling Parties agree that the Utilities will, to the extent permitted by applicable tax laws without penalty and CPUC action, seek reimbursement of Completed CWIP that enters service after June 7, 2013, as expenses from the Nuclear Decommissioning Trusts rather than recovering this investment through rates. The Utilities will not amortize in rates any portion of the Completed CWIP balance that has been paid for by the Nuclear Decommissioning Trusts.

4.9. O&M and other costs

(a) The Utilities will retain all rate revenue collected for 2012 pursuant to the revenue requirement for SONGS base O&M (100% share) provisionally authorized in Decision No. 12-11-051, which adopted SCE’s Test Year 2012 General Rate Case application, and in Decision No. 13-05-010, which adopted SDG&E’s Test Year 2012 General Rate Case application.

(i) The Utilities may apply 2012 revenues to defray base O&M costs recorded in their respective SONGSOMA for 2012, as well as costs recorded in their respective SONGSOMA for 2012 associated with severance of employees at SONGS or resulting from the permanent shut down at SONGS.

(ii) The Utilities may also apply 2012 revenues to defray Incremental Inspection and Repair Costs recorded in their respective SONGSOMA for 2012, except that the Utilities shall not be allowed to recover in rates any Incremental Inspection and Repair Costs incurred in 2012 in excess of the revenue requirement for base O&M costs (100% share) provisionally authorized in Decision No. 12-11-051 and Decision No. 13-05-010.

(iii) Provided however, if applicable, SDG&E will refund any amount of provisionally authorized O&M in excess of total recorded O&M costs incurred in 2012 invoiced by SCE.

(b) Subject to the following two sentences, SCE will retain all SONGS-related rate revenue collected pursuant to the revenue requirement for Non-O&M Expenses provisionally authorized in Decision No. 12-11-051 for calendar year 2012. Notwithstanding the foregoing, SCE will refund to ratepayers any such SONGS-related rate revenues collected in 2012 pursuant to Decision No. 12-11-051 that exceed 2012 recorded Non-O&M Expenses by more than $10 million. Any amount to be refunded pursuant to this Section of the Agreement shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.

(c) For calendar year 2012, SDG&E will retain rate revenue sufficient to defray all recorded Non-O&M Expenses.

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(d) For calendar year 2012, the Utilities will retain rate revenue sufficient to defray all recorded Non-O&M Balancing Account Expenses.

(e) Provided that the sum of the amounts listed in Sections 4.9(e)(i)-(iii) of this Agreement does not exceed the revenue requirement for each Utility’s respective share of SONGS base O&M costs provisionally authorized for the year 2013 pursuant to Decision Nos. 12-11-051 and 13-05-010, the Utilities will retain rate revenue sufficient to defray:

(i) All base O&M costs recorded in 2013;

(ii) All costs associated with severance of employees at SONGS or resulting from the permanent shut down at SONGS recorded in 2013; and

(iii) All Incremental Inspection and Repair Costs recorded in 2013.

(f) If the revenue requirement for each Utility’s respective share of SONGS base O&M costs provisionally authorized for the year 2013 pursuant to Decision Nos. 12-11-051 and 13-05-010 exceeds the sum of the amounts set forth in Sections 4.9(e)(i)-(iii) of this Agreement, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the sum of the recorded amounts in Sections 4.9(e)(i)-(iii). Likewise, if the Utilities recover any portion of the recorded amounts in Sections 4.9(e)(i)-(iii) through the Nuclear Decommissioning Trusts, those portions shall also be refunded to ratepayers. These amounts shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.

(g) For calendar year 2013, the Utilities will retain rate revenue sufficient to defray all recorded SONGS-related non-O&M expenses (including both Non-O&M Expenses and Non-O&M Balancing Account Expenses). The Utilities shall also seek recovery of these recorded amounts through the Nuclear Decommissioning Trusts to the extent permitted by applicable tax laws without penalty and CPUC action. If the revenue requirement for each Utility’s respective share of SONGS-related non-O&M expenses provisionally authorized for the year 2013 pursuant to Decision Nos. 12-11-051 and 13-05-010 exceeds the amount of each Utility’s respective recorded SONGS-related non-O&M expenses in 2013, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the amounts recorded. Likewise, if the Utilities recover any portion of their SONGS-related non-O&M expenses recorded in 2013 through the Nuclear Decommissioning Trusts, those portions shall also be refunded to ratepayers. Any amount to be refunded pursuant to this Section of the Agreement shall be refunded per the refund mechanism set forth in Section 4.12 of this Agreement.

(h) Nothing in this Agreement shall be construed to limit the Commission’s ability to review the reasonableness of the Utilities’ 2014 SONGS-related O&M or non-

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O&M expenses (including both Non-O&M Expenses and Non-O&M Balancing Account Expenses) in any appropriate proceeding.

(i) If the revenue requirement for each Utility’s respective share of SONGS-related O&M and non-O&M expenses provisionally authorized for the year 2014 pursuant to Decision Nos. 12-11-051 and 13-05-010 exceeds the amount of each Utility’s respective recorded SONGS-related O&M and non-O&M expenses in 2014, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the amounts recorded. Likewise, if the Utilities recover any portion of their SONGS-related O&M or non-O&M expenses recorded in 2014 through the Nuclear Decommissioning Trusts, and/or if the CPUC disallows any such expenses, those portions shall also be refunded to ratepayers. Section 4.9(j) of this Agreement sets forth the procedure that each Utility shall use to determine the amount of any refunds pursuant to this Section of the Agreement.

(j) In order to determine the amount of any refunds based on the difference between recorded and provisionally authorized expenses under Section 4.9(i) of this Agreement, each Utility shall use the following procedure:

(i) On the last day of the month of the Effective Date, each Utility shall calculate the difference between recorded and provisionally authorized amounts of SONGS-related O&M and non-O&M expenses during the time period from January 1, 2014, until the last day of available recorded cost data in 2014. If the provisionally authorized revenue requirement for such costs during this time period exceeds the recorded amount of such costs during this time period, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the amounts recorded, with such refund to be effectuated per the refund mechanism set forth in Section 4.12 of this Agreement.

(ii) On the last day of the month of the Effective Date, each Utility shall also calculate a forecast of SONGS-related O&M and non-O&M expenses for the time period from the last day of available recorded cost data in 2014 until December 31, 2014. If the provisionally authorized revenue requirement for such costs during this time period exceeds the forecasted amounts of such costs during this time period, the Utilities shall refund to ratepayers the difference between the amounts provisionally authorized and the amounts forecasted as the excess revenue is received, with such refund to be effectuated as a credit to SCE’s ERRA account and SDG&E’s NGBA.

(iii) In the first quarter of 2015, each Utility shall calculate the difference between recorded and forecasted amounts of SONGS-related O&M and non-O&M expenses during the time period set forth in Section 4.9(j)(ii) of this Agreement. If the forecasted revenue requirement for such costs during this time period exceeds the recorded amounts of such costs during

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this time period, the Utilities shall refund to ratepayers the difference between the amounts forecasted and the amounts recorded, with such refund to be effectuated as a credit to SCE’s ERRA and SDG&E’s NGBA. If, on the other hand, the recorded amounts exceed the forecasted revenue requirement, the Utilities shall recover the difference between the amounts forecasted and the amounts recorded from ratepayers via a debit to SCE’s ERRA account and SDG&E’s NGBA.

(iv) On the last day of the month following a CPUC decision authorizing the Utilities to recover any portion of their SONGS-related O&M or non-O&M expenses recorded in 2014 through the Nuclear Decommissioning Trusts, and/or of a decision disallowing any such costs, the Utilities shall effectuate a refund of such amounts per the refund mechanism set forth in Section 4.12 of this Agreement.

(k) In determining the provisionally authorized revenue requirement for Non-O&M Expenses pursuant to Sections 4.9(b), 4.9(g), 4.9(i), and 4.9(j) of this Agreement, the Utilities shall utilize a formula agreeable to all Settling Parties for allocating company-wide expenses to SONGS.

(l) The Utilities will recover all recorded O&M costs incurred in connection with the U2C17 RFO.

(m) Except as expressly provided in this Agreement, the O&M and other costs that the Utilities are entitled to retain pursuant to Section 4.9 of this Agreement shall not be subject to any disallowance, refund, or any form of reasonableness review by the Commission.

4.10. Market Power Purchases

(a) The Utilities will recover in rates the full amount of any costs designated as SONGS “replacement power costs,” SONGS “replacement energy costs,” or “net SONGS costs” incurred to purchase power in the market from January 1, 2012, until the last day of the month of the Effective Date.

(b) The Utilities will recover in rates the entire SONGS-related portion of the under-collected balance in each Utility’s respective ERRA account as of the last day of the month of the Effective Date. The SONGS-related under-collected balances in each Utility’s respective ERRA accounts shall be amortized over a period beginning on the first day of the month (or the nearest date practicable) following the Effective Date and ending no later than December 31, 2015. Nothing in this Agreement shall be construed to limit the Commission’s ability to review, in an appropriate proceeding, the Utilities’ requests to amortize the remaining (non-SONGS-related) portion of this under-collected balance. Although nothing in this Agreement shall limit TURN or ORA’s ability to challenge the eligibility of the remaining (non-SONGS-related) portion of this under-collected balance for cost recovery, neither TURN nor ORA shall oppose either Utility’s request to amortize

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by December 31, 2015 any portion of the under-collected balance found by the CPUC to be eligible for recovery.

(c) The Commission shall not impose any disallowance, on either of the Utilities, of any of the Utilities’ costs incurred to purchase power in the market as a result of the non-operation of SONGS. None of the Settling Parties will advocate before the Commission or any other judicial, legislative, or administrative body for any disallowance of past or future costs incurred by the Utilities to purchase power in the market as a result of the non-operation of SONGS.

(d) No future adjustments or disallowances to the Utilities’ ERRA accounts shall be made as a result of the non-operation of SONGS. This limitation includes foregone revenues; there will be no future adjustments or disallowances to the Utilities’ ERRA accounts as a result of foregone sales of SONGS output. No Settling Party shall object in an ERRA or other Commission proceeding to the Utilities’ showing on the grounds that the applied-for purchased power-related expenses were related to the non-operational status of SONGS.

4.11. SONGS Litigation Balance

(a) The SONGS Litigation Balance shall be determined by netting SONGS Litigation Costs from SONGS Litigation Recoveries. The mechanism for netting SONGS Litigation Costs from SONGS Litigation Recoveries shall be to establish memorandum accounts. In order to account for all recorded costs booked since January 31, 2012, each Utility shall establish memorandum accounts as of January 31, 2012. Each Utility shall establish two separate memorandum accounts (or sub-accounts) as follows:

(i) Each Utility shall establish one memorandum account (or sub-account) for netting costs and recoveries related to NEIL. Every year, the Utilities shall record all SONGS Litigation Costs related to pursuing recovery and planning to pursue recovery from NEIL and all SONGS Litigation Recoveries received from NEIL in this memorandum account.

(ii) Each Utility shall establish one memorandum account (or sub-account) for netting costs and recoveries related to Mitsubishi. Every year, the Utilities shall record all SONGS Litigation Costs related to pursuing recovery and planning to pursue recovery from Mitsubishi and all SONGS Litigation Recoveries received from Mitsubishi in this memorandum account.

(b) If there is a positive balance (i.e., SONGS Litigation Costs in excess of SONGS Litigation Recoveries) in either memorandum account at the end of a given year, the positive balance will be carried over to the next year. If there is a negative balance (i.e., SONGS Litigation Costs are less than SONGS Litigation Recoveries) in either memorandum account as of December 31, 2014, or at the end of any subsequent year, each Utility shall distribute to ratepayers their portion of the SONGS Litigation Recoveries as determined by the sharing formula in

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Section 4.11(c) of this Agreement. These amounts shall be distributed to ratepayers pursuant to the distribution method set forth in Section 4.11(d) of this Agreement. The Utilities’ portion of the SONGS Litigation Recoveries, as determined by the sharing formula in Section 4.11(c) of this Agreement, shall be retained by the Utilities at the time the ratepayers’ portions are distributed. Negative balances shall not carry over from one year to the next; instead, the account balance shall be reset to zero on the first of the year following any distribution of SONGS Litigation Recoveries pursuant to this Section of the Agreement.

(c) The SONGS Litigation Balance shall be shared between the Utilities and the ratepayers according to the following formula:

(i) SONGS Litigation Balance recovered from NEIL shall be shared as follows:

(A) The Utilities shall retain 17.5% of the balance

(B) The Utilities shall distribute to ratepayers 82.5% of the balance

(ii) SONGS Litigation Balance recovered from Mitsubishi shall be shared as follows:

(A) With respect to SCE:

(1) For the first $100 million of SONGS Litigation Balance recovered from Mitsubishi:

a. SCE shall retain 85% of the balance

b. SCE shall distribute to ratepayers 15% of the balance

(2) For the next $800 million of SONGS Litigation Balance recovered from Mitsubishi:

a. SCE shall retain 66.67% of the balance

b. SCE shall distribute to ratepayers 33.33% of the balance

(3) For any SONGS Litigation Balance recovered from Mitsubishi in excess of the first $900 million:

a. SCE shall retain 25% of the balance

b. SCE shall distribute to ratepayers 75% of the balance

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(B) With respect to SDG&E:

(1) For the first $25 million of SONGS Litigation Balance recovered from Mitsubishi:

a. SDG&E shall retain 85% of the balance

b. SDG&E shall distribute to ratepayers 15% of the balance

(2) For the next $200 million of SONGS Litigation Balance recovered from Mitsubishi:

a. SDG&E shall retain 66.67% of the balance

b. SDG&E shall distribute to ratepayers 33.33% of the balance

(3) For any SONGS Litigation Balance recovered from Mitsubishi in excess of the first $225 million:

a. SDG&E shall retain 25% of the balance

b. SDG&E shall distribute to ratepayers 75% of the balance

(d) Any amounts to be distributed to ratepayers pursuant to Section 4.11(b) of this Agreement shall be distributed pursuant to the following distribution mechanism:

(i) The ratepayers’ portion of the SONGS Litigation Balance recovered from NEIL shall be distributed to ratepayers via a credit to each Utility’s respective ERRA account.

(ii) The first $282 million of SONGS Litigation Balance recovered from Mitsubishi that is distributed to SCE ratepayers pursuant to Section 4.11(b) of this Agreement shall be distributed via a credit to SCE’s BRRBA.

(iii) The first $71 million of SONGS Litigation Balance recovered from Mitsubishi that is distributed to SDG&E ratepayers pursuant to Section 4.11(b) of this Agreement shall be distributed via a credit to SDG&E’s NGBA.

(iv) The ratepayers’ portion of any further SONGS Litigation Balance recovered from Mitsubishi shall be distributed to ratepayers as follows:

(A) First, by reducing the regulatory assets described in Sections 4.3(b), 4.8(a), 4.5(a), and 4.6(a) of this Agreement, in the order listed. The effect of the reduction to these regulatory assets shall be to decrease the yearly amount of the revenue requirement for each

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regulatory asset. This reduction to regulatory assets shall not affect the amortization period for the regulatory assets described in Sections 4.3(b), 4.8(a), 4.5(a), and 4.6(a) of this Agreement.

(B) Second, any remaining amounts shall be distributed via a credit to SCE’s BRRBA and SDG&E’s NGBA.

(e) In consideration of the Utilities retaining SONGS Litigation Recoveries to the extent of the SONGS Litigation Costs, the Utilities shall remove all SONGS Litigation Costs booked in the memorandum accounts described in Section 4.11(a) of this Agreement from the recorded costs used to develop future general rate case forecasts. Nothing in this Agreement shall preclude the Settling Parties from making any arguments in either Utility’s general rate cases regarding costs used to develop general rate case forecasts.

(f) In consideration of the sharing of net SONGS Litigation Recoveries, the Utilities shall have complete discretion to settle, compromise, or otherwise resolve claims against NEIL and/or Mitsubishi in any manner and whenever the Utilities determine, in the exercise of their business judgment, without prior or subsequent review or approval, disapproval, or disallowance by the CPUC or any parties to this OII.

(g) The Utilities shall promptly notify the CPUC of any such settlement, compromise, or other resolution of their claims against NEIL or MHI, provided, however, that:

(i) The Utilities may provide such notification in a manner that preserves the confidentiality thereof insofar as may be reasonably necessary to further the Utilities’ flexibility to settle, compromise, or otherwise resolve such claims; and

(ii) The CPUC shall not review the reasonableness or prudence of the Utilities’ litigation, settlement, compromise, or other resolution of such claims and shall not impose any ratemaking adjustment in respect of such claims except as expressly provided in this Agreement.

(h) The Utilities shall each use their best efforts to provide all Settling Parties with advance notice of any such settlement, compromise, or other resolution of their claims against NEIL or MHI, to the extent possible under the circumstances and the terms of any agreement with NEIL or MHI, before the Utilities notify the CPUC or otherwise make public the agreement.

4.12. Any amounts that the Utilities may be required to refund to ratepayers pursuant to Sections 4.2(b), 4.3(b)(ii), 4.9(b), 4.9(f), 4.9(g), 4.9(j)(i), and 4.9(j)(iv) of this Agreement shall be refunded via a reduction to each Utility’s respective under-collected ERRA balance as of the last day of the month of the Effective Date. This refund mechanism shall not change the amortization period set forth in Section 4.10(b) of this Agreement.

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4.13. For the period from the first day of the month after the Effective date to December 31, 2014, the difference between the Capital-Related Revenue Requirement for SONGS assets provisionally authorized in Decision No. 12-11-051 and the revenue requirement for Base Plant, CWIP, M&S and Nuclear Fuel Investment shall be credited to each Utility’s respective ERRA account. To the extent the difference referenced in the prior sentence is calculated based on a forecast, a true-up will be recorded in ERRA in the first quarter of 2015 to reflect the actual difference. For the period from January 1, 2015 to the date of Utility implements new base rates pursuant to its next GRC decision, such difference will be credited to ERRA (for SCE) and NGBA (for SDG&E).

4.14. Except as expressly provided in this Agreement, all costs recorded in SCE’s SONGSMA, SDG&E’s SONGSBA, and both Utilities’ SONGSOMA shall be recovered in rates and shall not be subject to any disallowance, refund, or any form of reasonableness review by the Commission.

4.15. Because this Agreement provides a ratemaking disposition for all costs recorded in SCE’s SONGSMA, SDG&E’s SONGSBA, and both Utilities’ SONGSOMA, these memorandum accounts will not be necessary after the last day of the month of the Effective Date and will be terminated by the Utilities as of that day.

4.16. Resolution of Consolidated Proceedings

(a) The Settling Parties intend for this Agreement to resolve the OII and all Consolidated Proceedings in their entirety. The Settling Parties agree that the Consolidated Proceedings should be resolved as follows in this section of the Agreement.

(b) A. 13-03-005

(i) The Commission shall find that SCE’s testimony in support of A. 13-03-005 conclusively established that the total cost of the SGRP was $612.1 million in 2004 dollars (100% share). The Settling Parties shall not take the position, in any proceeding whatsoever, that SCE spent more than $612.1 million (100% share, 2004$) on the SGRP.

(ii) The Commission shall find that SCE’s testimony in support of A. 13-03-005 utilized appropriate inflation indexes to deflate the total cost of the SGRP from nominal dollars to 2004 dollars. This includes the use of the Handy-Whitman index for fabrication and construction costs and the Commission-approved nuclear decommissioning burial escalation rates for burial costs. The Settling Parties shall not take the position, in any proceeding whatsoever, that SCE used inappropriate inflation indexes in its testimony in support of A. 13-03-005.

(iii) Because this Agreement provides a ratemaking disposition for all costs described in A. 13-03-005, no further reasonableness review is required. The Settling Parties shall jointly request that the Commission allow SCE

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to retain all rate revenues collected from customers for the SGRP prior to February 1, 2012, as a resolution of A. 13-03-005.

(c) A. 13-03-014

(i) The provisions set forth in Section 4.16(b)(i)-(ii) are incorporated herein as though set forth in their entirety.

(ii) Because this Agreement provides a ratemaking disposition for all costs described in A. 13-03-014, no further reasonableness review is required. The Settling Parties shall jointly request that the Commission allow SDG&E to retain all rate revenues collected from customers for the SGRP prior to February 1, 2012, as a resolution of A. 13-03-014.

(d) A. 13-01-016

(i) The Settling Parties agree that the costs recorded in SCE’s SONGSMA during the year 2012 were reasonable and prudent to the extent this Agreement provides that SCE shall recover such costs.

(ii) None of the Settling Parties will take the position, in any proceeding whatsoever, that any of the costs recorded in SCE’s SONGSMA during 2012 were unreasonable, or should be disallowed, except to the extent that this Agreement provides that such costs be refunded to ratepayers.

(iii) Because this Agreement provides a ratemaking disposition for all costs described in A. 13-01-016, no further reasonableness review is required. The Settling Parties shall jointly request that the Commission grant A. 13-01-016 to the extent that this Agreement provides for rate recovery of the costs recorded in SCE’s SONGSMA during 2012.

(e) A. 13-03-013

(i) The Settling Parties agree that the costs recorded in SDG&E’s SONGSBA during the year 2012 were reasonable and prudent to the extent this Agreement provides that SDG&E shall recover such costs.

(ii) None of the Settling Parties will take the position, in any proceeding whatsoever, that any of the costs recorded in SDG&E’s SONGSBA during 2012 were unreasonable, or should be disallowed, except to the extent that this Agreement provides that such costs be refunded to ratepayers.

(iii) Because this Agreement provides a ratemaking disposition for all costs described in A. 13-03-013, no further reasonableness review is required. The Settling Parties shall jointly request that the Commission grant A. 13-03-013 to the extent that this Agreement provides for rate recovery of the costs recorded in SDG&E’s SONGSBA during 2012.

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4.17. In light of this Agreement, the Settling Parties urge the CPUC to withdraw the November 19, 2013, Proposed Decision on Phase 1 and Phase 1A issues.

V.
GENERAL PROVISIONS AND RESERVATIONS

5.1. The Settling Parties shall use their best efforts to obtain Commission Approval. Following execution of this Agreement, the Settling Parties shall:

(a) Jointly file a motion requesting that the Commission:

(i) Approve the Agreement in its entirety without change;

(ii) Find the Agreement to be reasonable in light of the whole record, consistent with law, and in the public interest; and

(iii) Expedite its consideration and approval of the Agreement in order to provide the benefits of the Agreement as soon as possible.

(b) Support and mutually defend this Agreement in its entirety until the Commission has issued final approval of the Agreement.

(c) Oppose any modifications to this Agreement proposed by any non-settling party to the OII, unless all Settling Parties jointly agree to support such modification.

(d) Cooperate reasonably on all submissions, including briefs, necessary to achieve Commission Approval of the Agreement.

(e) Review any Commission orders regarding this Agreement to determine if the Commission has changed or modified this Agreement, deleted a term, or imposed a new term in this Agreement. If any Settling Party is unwilling to accept such change, modification, deletion, or addition of a new term, that Settling Party shall so notify the other Settling Parties within 15 days of issuance of the order by the Commission. The Settling Parties shall thereafter promptly discuss each change, modification, deletion, or new term to this Agreement found unacceptable and negotiate in good faith to achieve a resolution acceptable to all Settling Parties and promptly seek Commission approval of the resolution so achieved. Failure to resolve such change, modification, deletion, or new term to this Agreement to the satisfaction of all Settling Parties within 15 days of notification, or to obtain Commission approval of such resolution promptly thereafter, shall entitle any Settling Party to terminate this Agreement through prompt notice to all other Settling Parties.

5.2. In accordance with Rule 12.5, the Settling Parties intend that Commission adoption of this Agreement will be binding on all parties to the OII, including their legal successors, assigns, partners, members, agents, parent or subsidiary companies, affiliates, officers, directors, and/or employees. Unless the Commission expressly provides otherwise, such

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adoption does not constitute approval of or precedent for any principle or issue in this or any future proceeding.

5.3. Since this Agreement represents a compromise by them, the Settling Parties have entered into each stipulation contained in this Agreement on the basis that the stipulation not be construed as an admission or concession by any Settling Party regarding any fact or matter of law at issue in this proceeding. Should this Agreement not be approved in its entirety by the Commission, the Settling Parties reserve all rights to take any position whatsoever with respect to any fact or matter of law at issue in the OII.

5.4. The Settling Parties agree that no signatory to this Agreement or any employee thereof assumes any personal liability as a result of this Agreement.

5.5. If any Settling Party fails to perform its respective obligations under this Agreement, any other Settling Party may come before the Commission to pursue a remedy including enforcement.

5.6. The provisions of this Agreement are not severable. If the Commission, or any court of competent jurisdiction, overrules or modifies as legally invalid any material provision of this Agreement, the Agreement may be considered rescinded, at the discretion of any of the Settling Parties, as of the date such ruling or modification becomes final.

5.7. The Settling Parties acknowledge and stipulate that they are agreeing to this Agreement freely, voluntarily, and without any fraud, duress, or undue influence by any other party. Each Settling Party hereby states that, through its authorized representatives, it has read and fully understands its rights, privileges, and duties under this Agreement, including each Settling Party’s right to discuss this Agreement with its legal counsel and has exercised those rights, privileges, and duties to the extent deemed necessary.

5.8. In executing this Agreement, each Settling Party declares and mutually agrees that the terms and conditions herein are reasonable, consistent with the law, and in the public interest.

5.9. This Agreement constitutes the Settling Parties’ entire agreement on the subject matters addressed herein, which cannot be amended or modified without the express written and signed consent of all the Settling Parties hereto.

5.10. None of the provisions of this Agreement shall be considered waived by any Settling Party unless such waiver is given in writing. The failure of a Settling Party to insist in any one or more instances upon strict performance of any of the provisions of this Agreement or to take advantage of any of their rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect.

5.11. No Settling Party has relied, or presently relies, upon any statement promise, or representation by any other Settling Party, whether oral or written, except as specifically set forth in this Agreement. Each Settling Party expressly assumes the risk of any mistake

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of law or fact made by such Settling Party or its authorized representative in entering into this Agreement.

5.12. This Agreement may be executed in up to four separate counterparts by the different Settling Parties hereto with the same effect as if all Settling Parties had signed one and the same document. All such counterparts shall be deemed to be an original and shall together constitute one and the same Agreement.

5.13. This Agreement shall become effective and binding on the Settling Parties as of the Effective Date. However, the provisions of Section 5.1 of this Agreement shall impose obligations on the Settling Parties immediately upon the execution of this Agreement by all of the Settling Parties.

5.14. This Agreement shall be governed by the laws of the State of California as to all matters, including but not limited to, matters of validity, construction, effect, performance, and remedies.

5.15. To the extent this Agreement requires that any Settling Party provide notice to any other Settling Party, such notice shall be in writing and directed to the signatories to this agreement.

VI.
IMPLEMENTATION OF SETTLEMENT AGREEMENT

6.1. Within 30 days of the Effective Date, the Utilities shall file revised tariff sheets to implement the revenue requirement, accounting procedures, and charges authorized in this Agreement and to incorporate the relevant findings and conclusions of the decision adopting this Agreement. The revised tariff sheets shall become effective on filing, subject to a finding of compliance by the Energy Division, and shall comply with General Order 96-B. Notwithstanding any of the figures set forth in Sections 3.36 – 3.48 of this Agreement, ORA and TURN have the prerogative to review and validate any amounts used by the Utilities to implement the revenue requirement, accounting procedures, and charges authorized in this Agreement, to meet and confer with the Utilities to resolve any concerns, and to protest the advice letters if such concerns are not resolved to their satisfaction.

6.2. The Utilities shall file Tier 2 Advice Letters (which may be combined with Tier 2 Advice Letters proposing consolidated rate changes pursuant to the Utilities’ respective General Rate Case decisions) to implement changes to their respective revenue requirements, including implementation of changes pursuant to Sections 4.2, 4.3, 4.5, and 4.6 – 4.13 consistent with the terms of this Agreement.

VII.
EXECUTION

IN WITNESS WHEREOF, the Settling Parties have duly executed this Agreement. This Agreement is executed in four counterparts, each of which shall be deemed an original. The undersigned represent that they are authorized to sign on behalf of the party represented.

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SOUTHERN CALIFORNIA EDISON COMPANY By: /s/ Ronald L. Litzinger Title: President Date: 3/27/14	SAN DIEGO GAS & ELECTRIC COMPANY By: /s/ Lee Schavrien Title: SVP Finance, Regulatory & Legislative Affairs Date:3/27/14
THE UTILITY REFORM NETWORK By: /s/ Matthew Friedman Title: Staff Attorney Date: 3/27/14	OFFICE OF RATEPAYER ADVOCATES By: /s/ Joseph P. Como Title: Acting Director, Office of Ratepayer Advocates Date: 3/27/14

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Appendix A

ILLUSTRATIVE EXAMPLE FOR BASE PLANT AND MATERIALS AND SUPPLIES (M&S)

	As of February 1, 2012
Base Plant1	$	622
M&S		99
Regulatory Asset		721
Less: Accumulated Deferred Taxes2		(152)
Regulatory Asset, adjusted for deferred taxes		569
Rate of Return		2.95	%
Return 3,4	$	17

__________________________

¹ Base Plant excludes nuclear fuel and CWIP

² Includes deferred taxes associated with nuclear fuel

³ Does not include associated income taxes

⁴ Calculation of return illustrative for a single point in time; actual calculation will be based on an average

CONFIDENTIAL

PRELIMINARY AND APPROXIMATE

EX-99.1

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 0 Proposed SONGS Settlement

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 1 Statements contained in this presentation about future performance that are not purely historical, are forward-looking statements. These forward-looking statements reflect our current expectations; however, such statements involve risks and uncertainties. Actual results could differ materially from current expectations. These forward-looking statements represent our expectations only as of the date of this presentation, and Edison International assumes no duty to update them to reflect new information, events or circumstances. Important factors that could cause different results are discussed under the headings “Risk Factors” and “Management’s Discussion and Analysis” in Edison International’s Form 10-K and other reports filed with the Securities and Exchange Commission, which are available on our website: www.edisoninvestor.com. These filings also provide additional information on historical and other factual data contained in this presentation. Forward-Looking Statements

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 2 SONGS Settlement - Material Economic Terms Term Description Steam Generators • Steam Generator Replacement Project (“SGRP”) removed from rates as of February 1, 2012, with book value balance disallowed. Revenues related to the SGRP after February 1, 2012 are refunded to customers. Power Costs • Full recovery of replacement power costs and under-collected fuel and purchased power account Regulatory Asset Recovery • Non SGRP plant costs are recovered in rates over 10 years from 2/1/12 • Weighted average return equal to authorized cost on debt and 50% of authorized cost on preferred; no return on equity. Results in current weighted average return of 2.62%. • Construction Work in Progress (CWIP) and materials and supplies are recovered with same return over same period • Nuclear Fuel amortized over same period but receives return at customary commercial paper rate • 5% of proceeds of any sales/dispositions of materials, supplies and nuclear fuel go to shareholders • Significant portion of Regulatory Asset can be removed from ratemaking capital structure, thus reducing equity requirement in excess of $300 million Operations & Maintenance Costs • Recorded O&M for 2013 recovered, including incremental inspection and repair costs • O&M for 2012 limited to CPUC authorized amounts • Leaves $99 million incremental inspection and repair costs not recovered in rates (these costs were previously expensed) Sharing of SCE Recovery Proceeds • NEIL: 82.5% ratepayers/17.5% Shareholders • MHI: Shareholders receive 85% of first $100 million; 2/3 of next $800 million; and 1/4 of amounts above $900 million • Litigation costs recovered before sharing starts

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 3 Asset Impairment (February Business Update) Exposure to refunds for amounts collected from customers Exposure to recovery of net investment from future rates Revenue Subject to Refund Since 1/1/12 Since 11/1/12 Authorized revenues (as of 12/31/13) $1,248 $706 Replacement power (as of 6/6/13) $680 $339 SONGS Regulatory Asset Net investment1 (as of 5/31/13) $2,096 Less: $575 million impairment (575) Add: other costs 70 Regulatory Asset2 (as of 12/31/13) $1,591 ($ millions) 1 Includes approximately $404 million of PP&E, including CWIP, that is expected to support ongoing activities at the site and also includes excess nuclear fuel and material and supplies that, if sold, would reduce the amount of the regulatory asset by such proceeds 2 SCE has also recorded $266 million as a reduction to its regulatory asset for revenue collected in excess of amounts recognized resulting in a Net Regulatory Asset of $1,325 million Recognition of a regulatory asset is based on an assessment that such amount is probable of recovery2

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 4 Settlement Accounting • In Q2 2013, SCE recorded a $575 million (pre-tax) impairment based on management’s judgment of the recoverability of its SONGS investment  Developed based on a range of possible outcomes  Each quarter management must assess recoverability • In Q1 2014, SCE expects to increase its pre-tax impairment to ~$730 million (~$465 million after-tax) based on terms of Settlement. Primary drivers:  Disallowance of SGRP investment ($542 million as of May 31, 2013)  Refund of revenues related to SGRP previously recognized from February 1, 2012 through May 31, 2013 of $153 million  Implementation of other terms of the Settlement Agreement, including refund of authorized return in excess of the return allowed for non-SGRP investments • If approved, the settlement would result in a core earnings benefit of approximately $0.03 per share in 2014 and $0.04 per share annualized, declining over 10 years • SCE will not record a receivable for potential recoveries from either MHI or NEIL SCE expects to record an additional pre-tax impairment of ~$155 million (~$100 million after tax or $0.31 per share) in Q1 2014

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 5 SONGS Regulatory Asset Category December 31, 20131 March 31, 2014 Authorized Return Base Plant $492 2.62% SGRP - n/a CWIP2 $2,166 408 2.62% Materials and Supplies 78 2.62% Nuclear Fuel 400 Commercial Paper Asset Impairment (575) (34) n/a Regulatory Asset $1,591 $1,344 Estimated Revenue Refund Authorized revenue in excess of recorded (266) (256)3 1 December 31, 2013 balance of $2,166 million comprised of $2,096 million net investment at May 31, 2013 plus $70 million of costs recorded thereafter. Individual components not disclosed. 2 CWIP includes both completed and cancelled CWIP as defined by the Settlement agreement 3 Includes an estimate of $83 million of authorized revenues in excess of recorded for the three months ended March 31, 2014 and impact of Settlement Agreement. Refund to be credited to ERRA under collection. As of March 31, 2014, assets subject to a lower return under the Settlement Agreement are $1.3 billion with recovery expected through January 31, 2022 ($ millions)

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 6 Cash Flow Impact of Settlement • With SONGS shutdown, SCE has purchased significant amounts of replacement power  Energy Resource Recovery Account (ERRA) balance $1 billion under collected as of December 31, 2013  Expected to grow by $100 million each month  SONGS related amount in ERRA balance $467 million • Settlement would allow recovery of SONGS replacement power costs in ERRA proceeding  Refunds owed to customers, and return of over collected SONGS accounts, to be credited against ERRA under collection  Decision in 2014 ERRA proceeding still required • Subject to CPUC approval, SONGS decommissioning trusts may also provide additional funds to reduce ERRA balance • On March 24, SCE received proposed decision in 2014 ERRA proceeding  SCE will file comments supporting adoption of the proposed decision The settlement and other related actions may allow SCE to substantially offset its under collected fuel and purchased power account

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 7 1,005 264 195 1,464 (186) (267) (517) (61) (213) 220 ERRA 2013 End of Year Jan - April 2014 May 2014 due to ERRA delay May 31, 2014 ERRA Decom. Trust (June '13 - May '14) SONGS Settlement - May 31, 2014 Refund June - Dec 2014 ERRA Decom. Trust (June '14 - Dec '14) Settlement - June - Dec '14 Refund ERRA 2014 End of Year SAR2 15.7 16.6 16.5 Jan 2015 $ Millions Key Items 2014 ERRA: Assumes Commission approves March 25 proposed decision Decommissioning Trust: recorded O&M recovered from Trust beginning June 2013 SONGS Settlement: Capital and O&M revenue from Feb 1, 2012 – December 31, 2014 refunded as part of settlement 1 Assumes June 1, 2014 Effective Date 2 SAR = System Average Rate Note: Settlement refunds include nuclear fuel amortization Forecasted ERRA Recovery1

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 8 2014 Core and Basic Earnings Guidance Note: See Use of Non-GAAP Financial Measures in Appendix Key Assumptions: • Midpoint rate base of $22.1 billion • Approved capital structure – 48% equity, 10.45% CPUC & FERC ROE • 325.8 million common shares outstanding (no change) • No significant transmission project delays Other Assumptions: • EME results not consolidated • No changes in tax policy • O&M cost savings flow through to ratepayers in 2015 GRC • Updates to be provided on SONGS and EME bankruptcy as they develop 2014 Earnings Guidance as of 2/25/14 Low $3.60 Mid $3.70 High $3.80 • Cost savings / other - $0.35 • Income taxes - $0.14 • Energy efficiency earnings - $0.03 • SONGS LT Debt & Pf dividends $3.40 $(0.07) $0.52 $(0.15) $3.70 SCE 2014 EPS from Rate Base Forecast SONGS Shutdown SCE 2014 Positive Variances EIX Parent & Other 2014 Midpoint Guidance

Exhibit 99.1 EDISON INTERNATIONAL® Leading the Way in Electricity SM March 27, 2014 9 Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings 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 are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (or losses) are defined as earnings or losses attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including sale of certain assets, and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings. A reconciliation of Non-GAAP information to GAAP information is included on the slide where the information appears. Use of Non-GAAP Financial Measures EIX Investor Relations Contacts Scott Cunningham, Vice President (626) 302-2540 scott.cunningham@edisonintl.com Felicia Williams, Senior Manager (626) 302-5493 felicia.williams@edisonintl.com

EX-99.2

Exhibit 99.2 CERTAIN DOCUMENTS DISTRIBUTED AT THE SAN ONOFRE SETTLEMENT CONFERENCE MARCH 27, 2014

SUMMARY OF KEY TERMS OF SETTLEMENT AGREEMENT Confidential – Subject to Rule 12.6 Do Not Distribute The following summary of the Settlement Agreement is qualified in its entirety by reference to the complete text of the Settlement Agreement 23125433.2 1 Disallowances, Refunds, and Rate Recoveries Steam Generators  The utilities will not recover in rates the net investment associated with the steam generators as of February 1, 2012 (§ 4.2(d)), which is the first day following the tube leak in Unit 3. (§ 4.2(d).) These amounts ($597 million for SCE and $160.4 million for SDG&E) will not be recoverable in rates.  The utilities will refund any capital-related revenue requirement associated with the steam generators collected after February 1, 2012. (§ 4.2(b).) The utilities keep all capital-related revenues for the steam generators collected prior to February 1, 2012. (§ 4.2(c).) Base Plant  The utilities will remove Base Plant from rate base as of February 1, 2012. (§ 4.3(a).) Base Plant will be recovered at a reduced rate of return over 10 years. The rate of return is calculated as each utility’s authorized cost of debt plus 50% of each utility’s authorized cost of preferred stock, weighted by the amount of debt and preferred stock in each utility’s authorized ratemaking capital structure; return on equity is not considered. (§ 4.3(c).) Using this approach, the weighted average return for SCE base plant is 2.95% in 2012 and 2.62% in 2013 and 2014. For SDG&E, the return on base plant is 2.75% in 2012 and 2.35% in 2013 and 2014.  The utilities are entitled to retain all capital-related revenues collected for Base Plant prior to February 1, 2012. (§ 4.3(a).) For periods after February 1, 2012, the utilities will refund to ratepayers all revenues for Base Plant that exceed the revenue the utilities are entitled to collect under the reduced rate of return and amortization period set forth in the settlement agreement. (§ 4.3(b)(ii).)  Base Plant includes the net investment of all SONGS-related capital investments (including marine mitigation projects, nuclear design basis documentation, and deferred debits), but excludes the SGRP, nuclear fuel, and the materials and supplies inventory, which are addressed separately. (§ 2.6.)  Each utility has the option to exclude the unamortized portion of its investment from its capital structure for purposes of determining regulatory capital requirements. (§ 4.4.)

SUMMARY OF KEY TERMS OF SETTLEMENT AGREEMENT Confidential – Subject to Rule 12.6 Do Not Distribute The following summary of the Settlement Agreement is qualified in its entirety by reference to the complete text of the Settlement Agreement 23125433.2 2 Materials and Supplies  The settlement agreement allows the utilities rate recovery of their net investments in Materials and Supplies (“M&S”) over 10 years at the reduced rate of return provided for base plant. (§ 4.5(a).)  To provide an incentive to sell M&S, the utilities will retain 5% of all sales of the M&S inventory. (§ 4.5(b).) The remaining 95% will be credited to ratepayers. (§ 4.5(b).) Nuclear Fuel  The settlement agreement also allows the utilities rate recovery of entire net investment in nuclear fuel (§ 4.6(a)), including those costs that the utilities incur in connection with efforts to cancel their outstanding obligations to purchase nuclear fuel. (§ 2.30.) Nuclear fuel costs are recovered over 10 years at a rate of return equal to commercial paper. (§ 4.6(b).)  To provide an incentive to sell nuclear fuel, the utilities will retain 5% of net sale proceeds, while the ratepayers will be credited the remaining 95%. (§ 4.7(a).) Also, the utilities will retain 5% of the difference between outstanding contractual obligations to purchase nuclear fuel and the costs incurred to cancel these contracts. (§ 4.7(c)(i).) Construction Work in Progress  The settlement agreement allows the utilities to collect the balance of Construction Work in Progress (“CWIP”), except the portion of CWIP associated with the replacement steam generators. (§§ 4.8(a) & 3.37.)  Prior to February 1, 2012, the CWIP balance accumulates the authorized Allowance for Funds Used During Construction (“AFUDC”) rate. After February 1, 2012, CWIP associated with projects that the utilities cancelled will stop earning AFUDC. (§ 4.8(a)(i)(A).) For projects the utilities did not cancel, the associated CWIP will earn AFUDC post February 1, 2012, at the same rate as the return on Base Plant. (§ 4.8(a)(ii)(A) & (a)(ii)(A)(2).)  CWIP will be amortized over 10 years with the same return as Base Plant, except that the amortization period for CWIP associated with projects that the utilities have not cancelled will begin on the day the project enters service or the last day of the month of the Commission’s approval of the settlement, whichever is earlier. (§ 4.8(a)(i)(C)- (D) & (ii)(C)-(D).)

SUMMARY OF KEY TERMS OF SETTLEMENT AGREEMENT Confidential – Subject to Rule 12.6 Do Not Distribute The following summary of the Settlement Agreement is qualified in its entirety by reference to the complete text of the Settlement Agreement 23125433.2 3 Operations and Maintenance Costs  For 2012, SCE will retain Operations and Maintenance (“O&M”) expenses provisionally authorized in SCE’s 2012 General Rate Case (the “GRC”). (§ 4.9(a).) The utilities may not recover the incremental steam generator inspection and repair (“SGIR”) costs that exceed the provisionally authorized revenue requirement for O&M in 2012. (§ 4.9(a)(ii).) These incremental costs are $99 million for SCE. (§ 3.44.) For 2012, SDG&E will recover its recorded O&M expenses, resulting in a refund of approximately $5.1 million. (§ 4.9(a)(iii).)  For 2012 non-O&M expenses, the utilities will be permitted to retain the provisionally authorized revenue requirement, except that the utilities shall refund revenues that exceed recorded non-O&M expenses by more than $10 million. (§ 4.9(b).)  For 2013, the utilities will recover their recorded O&M, SONGS-related severance expenses, incremental steam generator inspection and repair costs, and non-O&M expenses, up to authorized. (§ 4.9(e) & (g).) The utilities will refund amounts that exceed these recorded costs. (§ 4.9(f).) 2014 costs are subject to future CPUC review (§ 4.9(h)), and the utilities will refund amounts collected in 2014 pursuant to provisionally authorized rates that exceed the utilities’ recorded costs in 2014. (§ 4.9(i).)  To the extent the utilities recover costs from the Nuclear Decommissioning Trusts, the utilities will refund any rates collected that duplicate recoveries from the trusts. (See, e.g., § 4.9(g) & (i).) Replacement Power Costs  The settlement agreement allows the utilities to recover all purchased power costs associated with replacing the output of SONGS from January 1, 2012, until the last day of the month of the Commission’s decision approving the settlement agreement. (§ 4.10(a).) The utilities are permitted to amortize these costs in rates by December 31, 2015. (§ 4.10(b).) Provision of Refunds Associated with Previous Overcollections  Refunds of revenues previously collected in rates will be effectuated via a reduction to each utility’s respective under-collected ERRA balance. (§ 4.12.)

SUMMARY OF KEY TERMS OF SETTLEMENT AGREEMENT Confidential – Subject to Rule 12.6 Do Not Distribute The following summary of the Settlement Agreement is qualified in its entirety by reference to the complete text of the Settlement Agreement 23125433.2 4 Third-Party Recoveries  The utilities are seeking recovery from Mitsubishi Heavy Industries, Inc., and related entities (“MHI”) and from Nuclear Energy Insurance Limited (“NEIL”). (§§ 3.31-3.33.) The utilities will apply recoveries from MHI and NEIL first to recover the costs of pursuing recovery of those claims. (§ 4.11(a) & (b).) The remaining net proceeds are shared between ratepayers and the utilities. Net recoveries from NEIL are provided 82.5% to ratepayers and 17.5% retained by the utilities. (§ 4.11(c)(i).) Net recoveries from MHI are shared as follows. SCE shall retain 85% of the first $100 million, 66.67% of the next $800 million, and 25% of any further recoveries, and shall distribute the remainder to ratepayers. (§ 4.11(c)(ii)(A).) SDG&E shall retain 85% of the first $25 million, 66.67% of the next $200 million, and 25% of any further recoveries, and shall distribute the remainder to ratepayers (§ 4.11(c)(ii)(B).)  Ratepayer share of litigation recoveries will be applies as follows: NEIL recoveries applied to reduce ERRA; first two tranches of MHI recoveries applied as a credit to BRRBA/NGBA; last tranche of MHI recoveries applied to reduce regulatory assets and then as a credit to BRRBA/NGBA. (§ 4.11(d).)  The utilities have discretion to resolve the NEIL and MHI disputes without CPUC approval or review (§ 4.11(f)), but the utilities will use their best efforts to inform the Commission of any settlement or other resolution of these disputes to the extent this is possible without compromising any aspect of the resolution. (§ 4.11(g).) Procedure  The terms and conditions are not binding unless and until the Commission issues a decision approving the agreement. (§ 5.13.) Settling parties will use best efforts to obtain CPUC approval without modification. (§ 5.1(a)(i).) If CPUC does not approve settlement within six months, settling parties may terminate. (Introduction).  After the Commission approves the settlement agreement, the utilities are required to file revised tariff sheets and Tier 2 Advice Letters to implement the rate changes provided under the settlement agreement. (§§ 6.1 & 6.2.)

CONFIDENTIAL  PRELIMINARY AND APPROXIMATE Forecasted ERRA Recovery1 1,005  264  195  1,464  (186) (267) (517) (61) (213) 220  ERRA 2013 End of Year Jan ‐ April 2014 May 2014 due to ERRA delay May 31, 2014 ERRA Decom. Trust (June '13 ‐ May '14) SONGS Settlement ‐ May 31, 2014 Refund June ‐ Dec 2014 ERRA Decom. Trust (June '14 ‐ Dec '14) Settlement ‐ June ‐ Dec '14 Refund ERRA 2014 End of Year 1. Assumes June 1, 2014 Effective Date 2. SAR = System Average Rate Note: Settlement refunds include nuclear fuel amortization SAR1 15.7 16.6 16.5 Jan 2015 $ Millions Key Items 2014 ERRA: Assumes Commission approves  March 25 proposed decision Decommissioning Trust: recorded O&M  recovered from Trust beginning June 2013 SONGS Settlement: Capital and O&M revenue  from Feb 1, 2012 – December 31, 2014  refunded as part of settlement

CONFIDENTIAL  PRELIMINARY AND APPROXIMATE $ Millions SCE TURN Litigation  ORA Litigation   Settlement  SCE Litigation  PVRR @ 10.00% 2,061$                         1,923$                         2,571$                         3,693$                         Components: RSG ‐                               86                               ‐                              696 Base Plant 900                              708 1,115                         1,416 O&M 659                              627                             673                             773 Nuclear Fuel 419                              419                             394                             419 Replacement Power1 83                                 83                                 389                               389 Return (% 2013) RSG 0.00% 0.00% 0.00% 5.54% Debt 0.00% 0.00% 0.00% 5.49% Preferred 0.00% 0.00% 0.00% 5.79% Equity 0.00% 0.00% 0.00% 5.54% Base Plant ‐ Required 2,3,4 0.00% 0.00% 2.62% 7.90% Debt 0.00% 0.00% 5.49% 5.49% Preferred 0.00% 0.00% 2.90% 5.79% Equity 0.00% 0.00% 0.00% 10.45% Base Plant ‐ Not Required 4 0.00% 0.00% n/a 5.54% Debt 0.00% 0.00% n/a 5.49% Preferred 0.00% 0.00% n/a 5.79% Equity 0.00% 0.00% n/a 5.54% 1. Does not include forgone sales 2. In Settlement Agreement, Non‐RSG plant is not distinguished as "required" or "not‐required" as defined in the SCE litigation position.  As such, Base Plant, CWIP, and M&S earns the rate of return shown in the table 3. In SCE litigation position, higher return on required plant only applicable through 2017. Thereafter, rate of return on "not‐required" plant applies. 4. Base Plant includes CWIP and M&S