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EDISON INTERNATIONAL - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS(Edgar Glimpses Via Acquire Media NewsEdge) 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; 39--------------------------------------------------------------------------------• 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. 40 -------------------------------------------------------------------------------- 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. Three months ended June 30, Six months ended June 30, (in millions) 2014 2013 Change 2014 2013 Change Net income (loss) attributable to Edison International Continuing operations SCE $ 362 $ (91 ) $ 453 $ 570 $ 165 $ 405 Edison International Parent and Other (10 ) (15 ) 5 (20 ) (13 ) (7 ) Discontinued operations 184 12 172 162 24 138 Edison International 536 (94 ) 630 712 176 536 Less: Non-core items SCE - (365 ) 365 (96 ) (365 ) 269 Edison International Parent and Other - - - - 7 (7 ) Discontinued operations 184 12 172 162 24 138 Total non-core items 184 (353 ) 537 66 (334 ) 400 Core earnings (losses) SCE 362 274 88 666 530 136 Edison International Parent and Other (10 ) (15 ) 5 (20 ) (20 ) - Edison International $ 352 $ 259 $ 93 $ 646 $ 510 $ 136 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. 41 -------------------------------------------------------------------------------- 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. 42 -------------------------------------------------------------------------------- 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. 43 -------------------------------------------------------------------------------- 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 44 -------------------------------------------------------------------------------- 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. 45 -------------------------------------------------------------------------------- 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. 46 -------------------------------------------------------------------------------- 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 |