SOUTHERN CALIFORNIA EDISON Co: Form 10-Q for the period ended Jun 30, 2014

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International's and SCE's current expectations and projections about future events based on Edison International's and SCE's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by Edison International and SCE that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact Edison International and SCE, include, but are not limited to the:

• ability of SCE to recover its costs in a timely manner from its customers through regulated rates, including regulatory assets related to San Onofre and undercollection of fuel and purchased power costs;
• decisions and other actions by the CPUC, the FERC, the NRC and other regulatory authorities and delays in regulatory actions;
• ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms;
• possible customer bypass or departure due to technological advancements, federal and state subsidies, or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable;
• risks inherent in the construction of transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable the acceptance of power delivery), and governmental approvals;
• risks associated with the operation of transmission and distribution assets and power generating facilities including: public safety issues, failure, availability, efficiency, and output of equipment and availability and cost of spare parts;
• risks associated with the retirement and decommissioning of nuclear generating facilities;
• physical security of SCE's critical assets and personnel and the cyber security of SCE's critical information technology systems for grid control, and business and customer data;
• cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs in the event of power plant outages or significant counterparty defaults under power-purchase agreements;
• environmental laws and regulations, at both the state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business;
• risk that the costs incurred in connection with San Onofre may not be recoverable from SCE's supplier or insurance coverage;
• changes in the fair value of investments and other assets;
• changes in interest rates and rates of inflation, including escalation rates, which may be adjusted by public utility regulators;
• governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by the California Independent System Operator, Regional Transmission Organizations, and adjoining regions;
• availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations;
• cost and availability of labor, equipment and materials;
• ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance or in the absence of insurance the ability to recover uninsured losses;
• effects of legal proceedings, changes in or interpretations of tax laws, rates or policies;
• potential for penalties or disallowances caused by non-compliance with applicable laws and regulations;
• cost and availability of fuel for generating facilities and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;
• extent of technological change in the generation, storage, transmission, distribution and use of electricity;
• cost and availability of emission credits or allowances for emission credits;
• risk that competing transmission systems will be built by merchant transmission providers in SCE's service area; and
• weather conditions and natural disasters.

Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in Edison International's and SCE's combined 2013 Form 10-K, including the "Risk Factors" section in Part I, Item 1A. Readers are urged to read this entire report, including the information incorporated by reference, as well as the 2013 Form 10-K, and carefully consider the risks, uncertainties and other factors that affect Edison International's and SCE's businesses. Forward-looking statements speak only as of the date they are made and neither Edison International nor SCE are obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International and SCE with the SEC.

The MD&A for the six months ended June 30, 2014 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International and SCE since December 31, 2013, and as compared to the six months ended June 30, 2013. This discussion presumes that the reader has read or has access to Edison International's and SCE's MD&A for the calendar year 2013 (the "year-ended 2013 MD&A"), which was included in the 2013 Form 10-K.

Except when otherwise stated, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to "Edison International Parent and Other" mean Edison International Parent and its consolidated non-utility subsidiaries.

MANAGEMENT OVERVIEW

Highlights of Operating Results

Edison International is the parent holding company of SCE. SCE is an investor-owned public utility primarily engaged in the business of supplying and delivering electricity. Edison International is also the parent company of subsidiaries that are engaged in competitive businesses related to the generation or use of electricity. Such competitive business activities are currently not material to report as a separate business segment. References to Edison International refer to the consolidated group of Edison International and its subsidiaries. References to Edison International Parent and Other refer to Edison International Parent and its nonutility subsidiaries. Unless otherwise described, all of the information contained in this report relates to both filers.

(in millions)

Edison International's earnings are prepared in accordance with GAAP used in the United States. Management uses core earnings internally for financial planning and for analysis of performance. Core earnings (losses) are also used when communicating with investors and analysts regarding Edison International's earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: exit activities, including sale of certain assets, and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings.

SCE's second quarter 2014 core earnings increased $88 million from the second quarter of 2013 primarily due to higher authorized revenues from rate base growth, income tax benefits, and other income. During the second quarter of 2014, SCE recorded $29 million of income tax benefits from revisions to liabilities for uncertain tax positions, $11 million from a change in estimate of revenues under its FERC formula rate, and benefits of $9 million related to FERC energy settlements. See "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses." During the second quarter of 2014 and 2013, SCE incurred severance costs (after-tax) related to workforce reductions of $4 million and $17 million, respectively.

Edison International Parent and Other's second quarter core losses decreased $5 million primarily due to consolidated state income tax benefits.

SCE's core earnings for the six months ended June 30, 2014 increased $136 million from the six months ended June 30, 2013 primarily due to higher authorized revenues from rate base growth, income tax benefits, lower operation and maintenance expenses and other income. During the six months ended June 30, 2014, SCE recorded $29 million of income tax and $20 million of other benefits described under the quarter results above. During the six months ended June 30, 2014 and 2013, SCE incurred severance costs (after-tax) related to workforce reductions of $5 million and $26 million, respectively.

Edison International Parent and Other's core losses for the six month periods ended June 30, 2014 and 2013 were about the same with tax benefits related to consolidated state income taxes offset by higher corporate and new business expenses.

Consolidated non-core items for 2014 and 2013 for SCE and Edison International included:

• Impairment and other charges of $231 million ($96 million after-tax) in the first quarter of 2014 related to the San Onofre OII Settlement Agreement (as defined below) and $575 million ($365 million after-tax) in the second quarter of 2013 related to the permanent retirement of San Onofre Units 2 and 3. These charges result in a total impact of the San Onofre OII settlement estimated to be $806 million (approximately $461 million after-tax). Assuming the San Onofre OII Settlement Agreement is approved, SCE does not expect implementation of rate recoveries and rate refunds contemplated by the San Onofre OII Settlement Agreement to have a material impact on future net income. Such amounts do not reflect any recoveries from third parties by SCE. For further information, see "—San Onofre Issues" and "Notes to Consolidated Financial Statements—Note 9. San Onofre Issues—Accounting and Financial Impact."
• Income of $184 million during the second quarter of 2014 related to the estimated impact of the transactions called for in the EME Settlement Agreement (as defined below). The EME Amended Plan of Reorganization, including the EME Settlement Agreement, was completed on April 1, 2014 with the sale of substantially all of EME's assets to NRG Energy, Inc. In addition, Edison International recorded an income tax loss of $22 million for the first quarter of 2014 compared to a benefit of $12 million and $24 million for the three- and six-month periods in 2013 from revised estimates of the tax impact of a tax deconsolidation of EME from Edison International. Edison International continues to consolidate EME for federal and certain combined state tax returns. For further information, see "—EME Chapter 11 Bankruptcy."
• An income tax benefit of $7 million in the first quarter of 2013 from reduction in state income taxes related to the sale of Edison Capital's interest in Unit No. 2 of the Beaver Valley Power plant. The sale of Edison Capital's lease interest was completed in 2012, however, the final determination of state income taxes paid was not completed until the first quarter of 2013 which resulted in a change in the estimate of state income taxes due.

San Onofre Issues

As discussed in the 2013 Form 10-K, replacement steam generators were installed at San Onofre in 2010 and 2011. On January 31, 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators. The Unit was safely taken off-line and subsequent inspections revealed excessive tube to tube wear. At the time, Unit 2 was off-line for a planned outage when areas of unexpected tube to support structure wear were found. Later, evidence of tube to tube wear in Unit 2 was also discovered. On June 6, 2013, SCE decided to permanently retire Units 2 and 3.

CPUC Proceedings and Proposed Settlement

In October 2012 the CPUC issued an Order Instituting Investigation ("OII") that consolidated all San Onofre issues in related CPUC regulatory proceedings to consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, substitute market power costs, capital expenditures, and operation and maintenance costs.

On March 27, 2014, SCE entered into a Settlement Agreement (the "San Onofre OII Settlement Agreement") with The Utility Reform Network ("TURN"), the CPUC's Office of Ratepayer Advocates ("ORA") and SDG&E, which was later joined by the Coalition of California Utility Employees ("CUE") and Friends of the Earth ("FOE") (together, the "Settling Parties"). If implemented, the San Onofre OII Settlement Agreement will constitute a complete and final resolution of the CPUC's OII and related proceedings regarding the Steam Generator Replacement Project ("SGRP") at San Onofre and the related outage and subsequent shutdown of San Onofre. The San Onofre OII Settlement Agreement does not affect proceedings before the NRC or proceedings related to recoveries from third parties described below, but does describe how shareholders and customers will share any potential recoveries. Implementation of the San Onofre OII Settlement Agreement is subject to the approval of the CPUC. The parties to the San Onofre OII Settlement Agreement have agreed to exercise their best efforts to obtain CPUC approval. The San Onofre OII 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.

For further information regarding the San Onofre OII Settlement Agreement's treatment of disallowances, refunds and rate recoveries, the accounting impact thereof, and the current status of CPUC proceedings related to the San Onofre OII Settlement Agreement, see "Notes to Consolidated Financial Statements—Note 9. San Onofre Issues" and "—Highlights of Operating Results." As indicated in Note 9 and "—Highlights of Operating Results," SCE has recorded the effects of the San Onofre OII Settlement Agreement assuming it is approved. Accordingly, if the San Onofre OII Settlement Agreement is approved, SCE does not expect implementation of rate recoveries and rate refunds contemplated by the San Onofre OII Settlement Agreement will have a material impact on future net income. Such amounts do not reflect any recoveries from third parties by SCE.

Third-Party Recoveries

As discussed in the 2013 Form 10-K, San Onofre carries accidental property damage and carried accidental outage insurance issued by Nuclear Electric Insurance Limited ("NEIL") and has placed NEIL on notice of claims under both policies. The NEIL policies have a number of exclusions and limitations that NEIL may assert reduce or eliminate coverage, and SCE may choose to challenge NEIL's application of any such exclusions and limitations. The estimated total claims under the accidental outage insurance through February 22, 2014 are approximately $414 million (SCE's share of which is approximately $325 million). Accidental outage policy benefits are reduced by 90% for the periods following announcement of the permanent retirement of the Units. The accidental outage insurance at San Onofre has been canceled prospectively as a result of the permanent retirement. SCE has not submitted a proof of loss under the accidental property damage insurance. It is possible that the NEIL Board of Directors will make a coverage determination by the end of the third quarter of 2014, but it may take longer. SCE may challenge any reduction or denial of coverage. No amounts have been recognized in SCE's financial statements, pending NEIL's response.

Under the San Onofre OII 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 exceeds 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 that MHI's liability is not limited to $138 million, and MHI has advised SCE that it disagrees. In October 2013, after a prescribed 90-day waiting period from the service of an earlier notice of dispute, SCE sent MHI a formal request for binding arbitration under the auspices of the International Chamber of Commerce in accordance with the purchase contract seeking damages for all losses. In the request for arbitration, SCE alleges contract and tort claims and seeks at least $4 billion in damages on behalf of itself and 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. Each of the other co-owners filed lawsuits against MHI, alleging claims arising from MHI's supplying the faulty steam generators, which have been stayed pending the arbitration. The other co-owners (SDG&E and Riverside) have been added as additional claimants in the arbitration, with party status.

SCE, on behalf of itself and the other San Onofre co-owners, has submitted seven invoices to MHI totaling $149 million for steam generator repair costs incurred through April 30, 2013. MHI paid the first invoice of $45 million, while reserving its right to challenge it and subsequently rejected a portion of the first invoice and has not paid further invoices, 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 San Onofre OII 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 between SCE and its ratepayers as follows:

• 85% to SCE and 15% to ratepayers for the first $100 million;
• 66.67% to SCE and 33.33% to ratepayers for the next $800 million; and
• 25% to SCE and 75% to ratepayers for any additional recoveries over $900 million.

The first $282 million of SCE's ratepayers' portion of such recoveries from MHI 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. Any additional amounts received after the regulatory asset is recovered will be applied to the BRRBA.

The San Onofre OII 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.

Rate Impacts

To the extent that SCE collects in rates amounts that are in excess of the amounts recoverable under the San Onofre OII Settlement Agreement, such amounts will be credited to SCE's ERRA account, thereby reducing the undercollected balance that would otherwise be subject to rate recovery. SCE estimates that if the settlement had been implemented on June 30, 2014, the refund of revenue related to the SGRP, the refund of the difference between authorized and recorded operation and maintenance expenses for 2013 and the first half 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 $483 million. SCE's ERRA undercollection at June 30, 2014 was $1.62 billion. See "—ERRA Balancing Account" below for more information.

As a result of the disallowances, refunds and reduced returns contemplated by the San Onofre OII Settlement Agreement, SCE ratepayers will also have a reduction from the current level of authorized revenue 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 San Onofre OII 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.

Continuing NRC Proceedings

For information on the continuing NRC proceedings, see "Notes to Consolidated Financial Statements—Note 9. San Onofre Issues—Continuing NRC Proceedings."

Decommissioning

As discussed in the 2013 Form 10-K, the decommissioning of a nuclear plant requires the management of three related activities: radiological decommissioning, non-radiological decommissioning and the management of spent nuclear fuel. The decommissioning process may take many years as is expected at San Onofre.

During the second quarter of 2014, SCE updated its decommissioning cost estimate based on a site specific assessment. The decommissioning cost estimate in 2014 dollars is $4.4 billion (SCE share – $3.3 billion) and includes costs from June 7, 2013 through to the respective completion dates to decommission San Onofre Units 2 and 3. The decommissioning cost estimate is subject to a number of estimates including the cost of burial of nuclear waste, cost of removal of property, site remediation costs as well as a number of other assumptions and estimates, including when the federal government may remove spent fuel canisters from the San Onofre site, as to which there can be no assurance. The cost estimate is subject to change and such changes may be material. SCE's share of the present value of decommissioning costs after escalation and using current discounts rates was $2.9 billion at June 30, 2014. For further information, see "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—Asset Retirement Obligation."

SCE has nuclear decommissioning trust funds for San Onofre Units 2 and 3 of $3.36 billion as of June 30, 2014, which is comprised of annual contributions made through rates and earnings on the trust funds' balances. Other than the use of funds for the planning of radiological decommissioning (up to a maximum of 3% of a generic formula amount under NRC regulations, or $31 million), the CPUC must issue an order granting prior approval for withdrawal of decommissioning trust funds to be used for radiological decommissioning, non-radiological decommissioning and spent fuel management. The CPUC's authority to authorize the use of trust funds for decommissioning activities is provided by the Nuclear Facility Decommissioning Act of 1985. SCE has filed a request with the CPUC to authorize early release of trust funds for costs up to a specified cost cap of $214 million to cover SCE's share of 2013 decommissioning costs. The request also seeks CPUC approval for a process by which SCE will be able to seek the release of trust funds to cover decommissioning costs incurred in 2014 and future periods until the CPUC approves a permanent San Onofre decommissioning plan and cost recovery mechanism.

ERRA Balancing Account

Rates related to fuel and purchased power are set annually based on a forecast of the costs SCE expects to incur in the following year. Actual fuel and power costs that are either greater or less than the forecast are tracked in the ERRA balancing account and collected from or refunded to customers in subsequent periods depending upon whether the balancing account is under collected or over collected. Until November 2013, SCE continued to recover in rates amounts that had been authorized in the 2012 ERRA proceeding and which were significantly below the costs actually incurred, resulting in a significant undercollection in the balancing account. In October 2013, the CPUC issued a decision on SCE's 2013 ERRA forecast that approved a portion of SCE's 2013 ERRA forecast and allowed SCE to increase rates by approximately $160 million. Under this decision, SCE was required to defer collection of its San Onofre-related replacement power costs that exceeded those estimated in the 2013 ERRA forecast filing pending the review of such costs in the San Onofre OII proceeding.

In May 2014, the CPUC issued a final decision in the 2014 ERRA forecast proceeding that adopted SCE's requested increase of $1.12 billion and deferred collection of $467 million of San Onofre-related replacement power costs incurred through 2013 until resolution of such costs in the San Onofre OII proceeding consistent with the CPUC decision in the 2013 ERRA forecast proceeding. SCE implemented a rate increase from the 2014 forecast proceeding consistent with the final decision, effective June 1, 2014.

In June 2014, SCE filed its 2015 ERRA forecast application, requesting an annual revenue requirement, beginning on January 1, 2015, of $5.62 billion (assuming the San Onofre OII Settlement Agreement is approved by the CPUC in 2014) or, alternatively, $6.41 billion (assuming the San Onofre OII Settlement Agreement is not approved by the CPUC or delayed beyond 2014).

As of June 30, 2014, SCE's fuel and power procurement-related costs were undercollected by $1.62 billion. Fuel and power procurement costs during 2014 are currently forecasted to exceed the amounts requested in the 2014 ERRA proceeding primarily due to higher natural gas and power prices. Actual natural gas and power costs may vary from the forecast. In addition to the implementation of the 2014 ERRA rate increase in June 2014, the ERRA undercollection balance is expected to continue to decrease assuming:

• approval of the application of refunds provided for in the San Onofre OII Settlement Agreement, including refunds related to the SGRP and authorized revenue in excess of SCE cost of service during 2013 and 2014 as discussed above under the heading "—San Onofre Issues;"
• approval of SCE's request to classify the majority of costs incurred at San Onofre since June 7, 2013 as decommissioning costs and reimbursement from SCE's nuclear decommissioning trust; and
• approval of SCE's 2015 ERRA forecast application in 2014.

These decreases may be partially offset by higher than forecasted natural gas and power prices. SCE may finance unrecovered power procurement-related costs with commercial paper or other borrowing, subject to availability in the capital markets. Delays in approval of rate increases to recover undercollection of fuel and purchase power costs would adversely impact SCE's liquidity.

2015 General Rate Case

As discussed in the year-ended 2013 MD&A, in November 2013, SCE filed its 2015 GRC application requesting a 2015 base rate revenue requirement of $6.462 billion, which was subsequently reduced in April 2014 to $5.860 billion to remove costs related to Four Corners and San Onofre, as directed by the ALJs assigned to the case. SCE's revised request would be a $227 million increase over currently authorized base rate revenue. The application also proposed post-test year increases in 2016 and 2017 of $321 million and $330 million, respectively. On July 3, 2014, SCE submitted supplemental testimony, as requested by an Assigned Commissioner Ruling, that provided specific information on how mitigation of safety- and reliability-related risks were taken into account in SCE's 2015 GRC application. Evidentiary hearings on SCE's 2015 GRC are tentatively scheduled to take place in the fall of 2014. This request for supplemental testimony is expected to delay a final 2015 GRC decision until beyond 2014, although consistent with historical CPUC practice, SCE expects that a final decision will be retroactively effective as of January 1, 2015. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or when a final decision will be adopted.

Capital Program

During the first six months of 2014, SCE's capital program continued to emphasize projects for maintaining reliability and expanding the capability of SCE's transmission and distribution system; upgrading and constructing new transmission lines and substations for system reliability and increased access to renewable energy; and maintaining performance of SCE's natural gas, and hydro-electric generating plants. Total capital expenditures (including accruals) were $1.6 billion for the first six months of 2014 and 2013.

SCE continues to project that 2014 capital expenditures will be in the range of $3.6 billion to $4.1 billion. SCE forecasts capital expenditures in the range of $15.1 billion to $17.2 billion for 2014 – 2017. Actual capital spending will be affected by: changes in regulatory, environmental and engineering design requirements; permitting and project delays; cost and availability of labor, equipment and materials; and other factors.

EME Chapter 11 Bankruptcy

As discussed in the 2013 Form 10-K, in December 2012, EME and certain of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.

In February 2014, Edison International, EME and the Consenting Noteholders entered into a settlement agreement (the "EME Settlement Agreement") pursuant to which EME amended its Plan of Reorganization to incorporate the terms of the EME Settlement Agreement, including extinguishing all existing claims between EME and Edison International. The Amended Plan of Reorganization, including the EME Settlement Agreement, was completed on April 1, 2014 with the sale of substantially all of EME's assets to NRG Energy, Inc. and the transactions called for in the EME Settlement Agreement.

Under the Amended Plan of Reorganization, EME emerged from bankruptcy free of liabilities but remained an indirect wholly-owned subsidiary of Edison International, which will continue to be consolidated with Edison International for income tax purposes. On April 1, 2014, all of the assets and liabilities of EME that were not otherwise discharged in the bankruptcy or transferred to NRG Energy were transferred to a newly formed trust under the control of EME's existing creditors (the "Reorganization Trust"), except for (a) EME's income tax attributes ("EME Tax Attributes"), which are retained by the Edison International consolidated income tax group; (b) certain tax and pension related liabilities in the approximate amount of $342 million, which have been assumed by Edison International and for substantially all of which Edison International had joint and several responsibility; and (c) EME's indirect interest in Capistrano Wind Partners and a small hydroelectric project.

As called for in the EME Settlement Agreement, Edison International made an initial cash payment to the Reorganization Trust of $225 million in April 2014, which represented the first installment due on its 50% share of the EME Tax Attributes that were initially estimated to be approximately $1.191 billion. The balance due under the EME Settlement Agreement will be paid in two installment payments to be made on September 30, 2015 and 2016, respectively. The amount of the two installment payments with interest of 5% per annum from April 1, 2014 will be fixed once the estimate of the EME Tax Attributes is completed. Based on the initial estimate of the EME Tax Attributes, the two installment payments would be approximately $199 million and $210 million, respectively, including applicable interest. The parties are continuing to follow the procedures set for in the EME Settlement Agreement. Based on completion of the review of information provided on behalf of the Reorganization Trust, Edison International does not expect that the EME Tax Attributes will vary from the initial estimate by more than 10%. The final estimate of the EME Tax Attributes and the two installment payments is expected to be finalized by the fourth quarter of 2014.

During the second quarter of 2014, Edison International recorded, as part of discontinued operations, $184 million in income related to the estimated impact of the EME Settlement Agreement.

Assuming continuation of existing tax law and tax rates, Edison International also anticipates realization of the tax benefits over a period similar to the period for which it pays for them. Extension of bonus depreciation could defer realization of the benefits, and reduction of federal income tax rates could permanently reduce them. Pending the realization of the tax benefits, Edison International will finance the settlement from existing credit lines. See "Notes to Consolidated Financial Statements—Note 16. Discontinued Operations" for additional information related to these bankruptcy proceedings.

RESULTS OF OPERATIONS

Southern California Edison Company

SCE's results of operations are derived mainly through two sources:

• Utility earning activities – representing revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of authorized operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in utility earnings activities are revenue or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.
• Utility cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery of specific project or program costs, subject to reasonableness review or compliance with upfront standards. Utility cost-recovery activities include rates which provide recovery, subject to reasonableness review of, among other things, fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses and nuclear decommissioning expenses.

The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities.

Three months ended June 30, 2014 versus June 30, 2013

(in millions)

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

• Lower operating revenue of $29 million primarily due to the following:
• A decrease in San Onofre-related estimated revenue of $118 million, as discussed below.
• A decrease in Four Corners-related revenue of $34 million due to the sale of SCE's ownership interest in the Four Corners Generating Station in December 2013 (primarily offset in operation and maintenance expense and depreciation expense below).
• An increase in CPUC-related revenue of $80 million primarily related to the increase in authorized revenue to support rate base growth.
• An increase in FERC-related revenue of $45 million primarily related to rate base growth and higher operating costs, as well as $19 million of additional revenue recorded from a change in estimate under the FERC formula rate mechanism.
• Lower operation and maintenance expense of $95 million primarily due to:
• A decrease in San Onofre-related expense of $100 million discussed below and Four Corners-related expense of $17 million.
• A decrease in severance costs of $6 million (excluding San Onofre).
• An increase of $30 million of higher operating costs related to transmission and distribution, safety, legal and insurance costs.
• Lower depreciation, decommissioning and amortization expense of $3 million primarily due to a decrease in San Onofre-related expense of $34 million discussed below, and Four Corners-related expense of $10 million, partially offset by a $41 million increase in depreciation primarily related to transmission and distribution investments.
• Higher interest income and other of $15 million primarily due to $14 million in FERC energy settlements and $5 million in insurance benefits, partially offset by lower AFUDC equity income due to lower AFUDC rates and lower construction work in progress balances in 2014. See "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses."
• Higher interest expense of $4 million primarily due to lower capitalized interest (AFUDC debt).
• Higher income taxes of $197 million primarily due to higher pre-tax income, partially offset by a $29 million income tax benefits from revisions to liabilities for uncertain tax positions. See "—Income Taxes" below for more information.

On June 6, 2013, SCE decided to permanently retire San Onofre Units 2 and 3. On March 27, 2014, SCE entered into the San Onofre OII Settlement Agreement to resolve CPUC regulatory issues associated with San Onofre and the failure of its replacement steam generators. See "Management Overview—San Onofre Issues" above for more information. The following table summarizes the results of operations attributable to the San Onofre plant for the three- and six-month periods ended June 30, 2014 and 2013, respectively:

(in millions)

1 Includes severance costs of $79 million for the three- and six-month periods ended June 30, 2013.

2 Includes a property tax refund of $5 million related to replacement steam generators reflected in the three- and six-month periods ended June 30, 2014.

Utility Cost-Recovery Activities

Utility cost-recovery activities were primarily affected by the following:

• Higher fuel and purchased power expense of $82 million was primarily driven by an increased load related to warmer weather experienced in 2014 relative to 2013 and higher power and gas prices experienced in 2014 relative to 2013, partially offset by lower realized losses on economic hedging activities ($4 million in 2014 compared to $7 million in 2013), lower fuel expense in 2014 due to the sale of Four Corners in December 2013 and FERC energy settlements refunded to customers (see "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses" for more information). In addition, during the second quarter of 2014, the CAISO issued invoices implementing a FERC order which revised FERC tariffs for costs associated with scheduling coordinator activities. The order and revised invoices reflect a shift in responsibility from transmission activities charged to all ISO participating transmission customers to generation activities charged to load customers. The impact of implementing the order and revised invoices resulted in a transmission refund of $106 million reflected in operation and maintenance expense and a generation surcharge of $83 million reflected in purchased power expense. These transactions did not impact earnings as the net refund was provided to ratepayers through a FERC balancing account mechanism.
• Lower operation and maintenance expense of $87 million primarily due to the CAISO refund of $106 million mentioned above and lower costs for the GHG cap-and-trade program related to utility owned generation, partially offset by higher transmission access charges.

Six months ended June 30, 2014 versus June 30, 2013

(in millions)

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

• Lower operating revenue of $28 million primarily due to the following:
• A decrease in San Onofre-related estimated revenue of $200 million, as discussed above.
• A decrease in Four Corners-related revenue of $55 million due to the sale of SCE's ownership interest in the Four Corners Generating Station in December 2013 (primarily offset in operation and maintenance expense and depreciation expense below).
• An increase in CPUC-related revenue of $155 million primarily related to the increase in authorized revenue to support rate base growth.
• An increase in FERC-related revenue of $70 million primarily related to rate base growth and higher operating costs, as well as $19 million of additional revenue from a change in estimate under the FERC formula rate mechanism.
• Lower operation and maintenance expense of $172 million primarily due to:
• A decrease in San Onofre-related expense of $143 million discussed above and Four Corners-related expense of $30 million.
• A decrease in severance costs of $22 million (excluding San Onofre) and lower planned outage costs of $10 million at Mountainview.
• An increase of $40 million of higher operating costs primarily related to transmission and distribution, legal, safety and insurance costs.
• Lower depreciation, decommissioning and amortization expense of $8 million primarily due to a decrease in San Onofre-related expense of $69 million discussed above, and Four Corners-related expense of $20 million, partially offset by a $81 million increase in depreciation primarily related to transmission and distribution investments.
• Higher interest income and other of $5 million primarily due to $14 million in FERC energy settlements and $5 million in insurance benefits, offset by lower AFUDC equity income related to lower AFUDC rates and lower construction work in progress balances in 2014, including SCE no longer accruing AFUDC on construction work in progress balances for San Onofre, pending the outcome of the San Onofre OII, and higher other expenses. See "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses."
• Higher interest expense of $13 million primarily due to lower capitalized interest (AFUDC debt) and higher balances on long-term debt to support rate base growth.
• Higher income taxes of $73 million primarily due to higher pre-tax income, partially offset by a $29 million income tax benefits from revisions to liabilities for uncertain tax positions and income tax benefits related to repair deductions and the San Onofre Agreements discussed below. See "—Income Taxes" below for more information.

Utility Cost-Recovery Activities

Utility cost-recovery activities were primarily affected by the following:

• Higher fuel and purchased power expense of $373 million was primarily driven by an increased load related to warmer weather experienced in 2014 relative to 2013, higher power and gas prices experienced in 2014 relative to 2013 and higher realized losses on economic hedging activities ($41 million in 2014 compared to $23 million in 2013), partially offset by lower fuel expense in 2014 due to the sale of Four Corners in December 2013 and FERC energy settlements refunded to customers (see "Notes to Consolidated Financial Statements—Note 15. Interest and Other Income and Other Expenses" for more information). In addition, as discussed above, the CAISO issued invoices implementing a FERC order which revised FERC tariffs for costs associated with scheduling coordinator activities. The impact of implementing the order and revised invoices resulted in a transmission refund of $106 million reflected in operation and maintenance expense and a generation surcharge of $83 million reflected in purchased power expense. These transactions did not impact earnings as the net refund was provided to ratepayers through a FERC balancing account mechanism.
• Lower operation and maintenance of $83 million primarily due to the CAISO refund of $106 million mentioned above and lower costs for the GHG cap-and-trade program related to utility owned generation, partially offset by higher transmission access charges.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account overcollections/undercollections) was $2.9 billion for both the three months ended June 30, 2014 and 2013 and $5.2 billion for both the six months ended June 30, 2014 and 2013. The revenue reflects:

• Retail billed revenue reflects a slight sales volume increase for the three months ended June 30, 2014 due to higher load requirements related to warmer weather experienced in the second quarter of 2014 compared to the same period last year.
• A rate decrease for the six months ended June 30, 2014 due to the greenhouse gas auction revenue and base rate differences refunded to customers in April 2014, partially offset by the implementation of the 2014 ERRA rate increase in June 2014.

As a result of the CPUC-authorized decoupling mechanism, SCE earnings are not affected by changes in retail electricity sales (see "Item 1. Business—Overview of Ratemaking Process" in the 2013 Form 10-K).

Income Taxes

SCE's income tax provision increased by $73 million during the first six months of 2014 compared to same period in 2013. The effective tax rates were 12.1% and 5.7% for the six months ended June 30, 2014 and 2013, respectively. The effective tax rate increase in 2014 was primarily due to higher pre-tax income, partially offset by income tax benefits related to repair deductions and the San Onofre OII Settlement Agreement. In addition, in the second quarter of 2014, SCE recorded $29 million of income tax benefits from revisions to liabilities for uncertain tax positions. See "Management Overview—San Onofre Issues" above and "Item 1. Notes to Consolidated Financial Statements—Note 7. Income Taxes" for more information.

The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences, which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.

See "Item 1. Notes to Consolidated Financial Statements—Note 7. Income Taxes" for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Edison International Parent and Other

Results of operations for Edison International Parent and Other include amounts from other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.

Income from Discontinued Operations (Net of Tax)

Income from discontinued operations, net of tax, was $184 million and $162 million for the three- and six-month periods in 2014, compared to income of $12 million and $24 million for the respective periods in 2013. The 2014 income was primarily due to the completion of the Amended Plan of Reorganization, including transactions recorded in the second quarter of 2014 associated with the sale of substantially all of EME's assets to NRG Energy, Inc. and other transactions called for in the EME Settlement Agreement. The 2013 income from discontinued operations resulted from revised estimates of the tax impact of expected future deconsolidation and separation of EME from Edison International (see "Notes to Consolidated Financial Statements—Note 16. Discontinued Operations" for further information).

LIQUIDITY AND CAPITAL RESOURCES

Southern California Edison Company

SCE's ability to operate its business, fund capital expenditures, and implement its business strategy is dependent upon its cash flow and access to the capital markets. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, interest obligations and dividend payments to Edison International, and the outcome of tax and regulatory matters.

SCE expects to fund its 2014 obligations, capital expenditures and dividends through operating cash flows, and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities to fund requirements.

Available Liquidity

At June 30, 2014, SCE had a $2.75 billion multi-year revolving credit facility. For further details see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."

SCE's cash flows are affected by regulatory balancing accounts overcollections or undercollections. As of June 30, 2014 and December 31, 2013, SCE had net regulatory balancing account overcollections of $48 million and $554 million, respectively. The change was primarily due to higher undercollections related to fuel and procurement-related costs. See "Management Overview—ERRA Balancing Account" for further information. SCE may finance unrecovered power procurement-related costs as well as other balancing account undercollections and working capital requirements to support operations and capital expenditures with commercial paper or other borrowings, subject to availability in the capital markets.

Debt Covenant

The debt covenant in SCE's credit facility limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At June 30, 2014, SCE's debt to total capitalization ratio was 0.46 to 1.

Regulatory Proceedings

FERC Formula Rates

In July 2014, SCE provided its preliminary 2015 annual transmission revenue requirement update to interested parties. The update provided support for an increase in SCE's transmission revenue requirement of $95 million or 11.6% over amounts currently authorized in rates. The primary reason for the increase is the inclusion of costs associated with several large transmission projects that were completed in 2013, including Devers-Colorado River, Eldorado-Ivanpah, and the Red Bluff substation. SCE expects to file its 2015 annual update with the FERC by December 1, 2014 and the proposed rates would be effective from January 1, 2015 to December 31, 2015. SCE filed a request with the FERC to recover $14.5 million in abandoned plant costs incurred as a result of the CPUC's order directing SCE to underground the Chino Hills segment of the Tehachapi transmission project in the 2016 formula rate update.

Dividend Restrictions

The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above 48% on a 13-month weighted average basis. At June 30, 2014, SCE's 13-month weighted-average common equity component of total capitalization was 48.5% and the maximum additional dividend that SCE could pay to Edison International under this limitation was approximately $119 million, resulting in a restriction on net assets of approximately $12.58 billion.

SCE paid the $126 million dividend declared in February 2014 to Edison International during the second quarter. In June 2014, SCE declared another $126 million dividend to Edison International which will be paid in the third quarter of 2014. Future dividend amounts and timing of distributions are dependent upon several factors including the level of capital expenditures, operating cash flows and earnings.

Margin and Collateral Deposits

Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at June 30, 2014, due to the addition of incremental power and energy procurement contracts with collateral requirements, if any, and the impact of changes in wholesale power and natural gas prices on SCE's contractual obligations.

Some of the power procurement contracts contain provisions that require SCE to maintain an investment grade credit rating from the major credit rating agencies. If SCE's credit rating were to fall below investment grade, SCE may be required to pay the liability or post additional collateral.

The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of June 30, 2014.

(in millions)

1 Collateral provided to counterparties and other brokers consisted of $7 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $7 million of cash reflected in "Other current assets" on the consolidated balance sheets and $153 million in letters of credit and surety bonds.

2 SCE does not project a material increase in the total posted and potential collateral requirements based on SCE's forward positions as of June 30, 2014 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level.

Edison International Parent and Other

Edison International Parent and Other's liquidity and its ability to pay operating expenses and dividends to common shareholders is dependent on dividends from SCE and access to bank and capital markets.

At June 30, 2014, Edison International Parent had a $1.25 billion multi-year revolving credit facility. For further details, see "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements." Edison International may finance working capital requirements to support operations and capital expenditures with commercial paper or other borrowings, subject to availability in capital markets.

The debt covenant in Edison International Parent's credit facility requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At June 30, 2014, Edison International Parent's consolidated debt to total capitalization ratio was 0.49 to 1.

As discussed in "Management Overview—EME Chapter 11 Bankruptcy," Edison International made an initial cash payment to the Reorganization Trust of $225 million in April 2014, which represented the first installment due on its 50% share of the EME tax attributes that were initially estimated to be approximately $1.191 billion. The balance due under the EME Settlement Agreement will be paid in two installment payments to be made on September 30, 2015 and 2016, respectively. The amount of the two installment payments with interest of 5% per annum from April 1, 2014 will be fixed once the estimate of the EME tax attributes is completed. Assuming continuation of existing law and tax rates, Edison International also anticipates realization of the tax benefits over a period similar to the period for which it pays for them. Extension of bonus depreciation could defer realization of the benefits, and reduction of federal income tax rates could permanently reduce them. Pending the realization of the tax benefits, Edison International will finance the settlement from existing credit lines.

Historical Cash Flows

Southern California Edison Company

(in millions)

53

Net Cash Provided by Operating Activities

Net cash provided by operating activities decreased $247 million during the first six months of 2014 compared to the same period in 2013 primarily due to the following:

• $350 million decrease in balancing accounts primarily composed of:
• $109 million decrease resulting from higher ERRA balancing account undercollections for fuel and power procurement-related costs in 2014 compared to 2013. The change in the ERRA balancing account decreased operating cash flows by $612 million in 2014 compared to a decrease in operating cash flows of $503 million in 2013.
• $241 million decrease due primarily to increased spending and lower funding of public purpose and energy efficiency programs.
• higher cash inflow of approximately $200 million due to cash collected in excess of cost of service for San Onofre.
• higher cash inflow of approximately $131 million due to the increase in pre-tax income, before depreciation and impairment and other charges, primarily driven by the increase in authorized revenue.
• timing of cash receipts and disbursements related to working capital items. In addition, SCE had workforce reduction severance costs paid of $13 million and $88 million during the first six months of 2014 and 2013, respectively.

Net Cash Provided by Financing Activities

The following table summarizes cash provided (used) by financing activities for the six months ended June 30, 2014 and 2013. Issuances of debt and preference stock are discussed in "Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "—Note 13. Preferred and Preference Stock."

(in millions)

Net Cash Used by Investing Activities

Cash flows from investing activities are primarily due to capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $1.9 billion and $1.8 billion for the six months ended June 30, 2014 and 2013, respectively, primarily related to transmission, distribution and generation investments. Net purchases of nuclear decommissioning trust investments and other was $83 million and $172 million for the six months ended June 30, 2014 and 2013, respectively.

Edison International Parent and Other

The table below sets forth condensed historical cash flow from operations for Edison International Parent and Other.

(in millions)

54

Net Cash Used by Operating Activities

Net cash used by operating activities increased $411 million for the first six months of 2014 compared to 2013 due to:

• $225 million initial cash payment to the Reorganization Trust in April 2014, see, "Management Overview—EME Chapter 11 Bankruptcy," for further information;
• $189 million deposit made with the IRS related to open tax years 2003 through 2006, see "Notes to Consolidated Financial Statements Note 7—Income Taxes—Tax Disputes." for further information; and
• the timing of payments and receipts relating to interest, operating costs and income taxes.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the first six months of 2014 were as follows:

• Paid $231 million of dividends to Edison International common shareholders;
• Received $126 million of dividend payments from SCE; and
• Borrowed $632 million of short-term debt (net) to fund interim working capital requirements.

Net cash provided by financing activities for the first six months of 2013 were as follows:

• Paid $220 million of dividends to Edison International common shareholders;
• Received $240 million of dividend payments from SCE; and
• Borrowed $25 million under Edison International Parent's line of credit to fund interim working capital requirements.

Contingencies

SCE has contingencies related to San Onofre, San Gabriel Valley Windstorm Investigation, Four Corners Environmental Matters, Nuclear Insurance, Wildfire Insurance and Spent Nuclear Fuel which are discussed in "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies."

Environmental Remediation

As of June 30, 2014, SCE had identified 19 material sites for remediation and recorded an estimated minimum liability of $111 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies" for further discussion.

MARKET RISK EXPOSURES

Edison International and SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. Derivative instruments are used, as appropriate, to manage market risks including market risks of SCE's customers. For a further discussion of market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Notes to Consolidated Financial Statements—Note 6. Derivative Instruments" and "—Note 4. Fair Value Measurements."

Commodity Price Risk

The fair value of outstanding derivative instruments used to mitigate exposure to commodity price risk was a net liability of $885 million and $821 million at June 30, 2014 and December 31, 2013 respectively. For further discussion of fair value measurements and the fair value hierarchy, see "Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."

Credit Risk

Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these arrangements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. Exposure excludes amounts related to contracts classified as normal purchases and sales and non-derivative contractual commitments that are not recorded on the consolidated balance sheets, except for any related net accounts receivable. As of June 30, 2014, SCE had a counterparty balance sheet exposure from CAISO of $310 million with an A credit rating by S&P.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

For a complete discussion on Edison International's and SCE's critical accounting policies, see "Critical Accounting Estimates and Policies" in the year-ended 2013 MD&A.

NEW ACCOUNTING GUIDANCE

New accounting guidance is discussed in "Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

Information responding to Item 3 is included in the MD&A under the heading "Market Risk Exposures" and is incorporated herein by reference.

Disclosure Controls and Procedures

The management of Edison International and SCE, under the supervision and with the participation of Edison International's Chief Executive Officer and Chief Financial Officer and SCE's President and Chief Financial Officer, have evaluated the effectiveness of Edison International's and SCE's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended), respectively, as of the end of the second quarter of 2014. Based on that evaluation, Edison International's Chief Executive Officer and Chief Financial Officer and SCE's President and Chief Financial Officer have each concluded that, as of the end of the period, Edison International's and SCE's disclosure controls and procedures, respectively, were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in Edison International's or SCE's internal control over financial reporting, respectively, during the second quarter of 2014 that have materially affected, or are reasonably likely to materially affect, Edison International's or SCE's internal control over financial reporting.

Jointly Owned Utility Plant

Edison International's and SCE's respective scope of evaluation of internal control over financial reporting includes their Jointly Owned Utility Projects as discussed in Note 2. Property, Plant and Equipment in the 2013 Form 10-K.

Prolonged drought conditions in California increase the risk of severe wildfire events and could create local transmission constraints that could materially affect SCE.

The entire state of California has been declared to be in a state of severe drought, with many areas of the state (including some within SCE's service territory) in even more worse conditions, from extreme to exceptional. These drought conditions increase the risk of severe wildfire events in SCE's territory that could damage the electric infrastructure necessary to deliver power to SCE's customers and affect reliability. These events can lead to lost revenues and increased expenses, including higher maintenance and repair costs. They can also result in regulatory penalties and disallowances, particularly if SCE encounters difficulties in restoring power to its customers. The drought conditions may also affect the amount of power available from SCE's hydroelectric generation facilities, which could create local transmission constraints and affect reliability in certain areas.