Commitments and Contingencies

Third-Party Power Purchase Agreements

SCE enters into various agreements to purchase power and electric capacity, including:

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Renewable Energy Contracts – California law requires retail sellers of electricity to comply with an RPS by delivering renewable energy, primarily through power purchase contracts. Renewable energy contract payments generally consist of payments based on a fixed price per megawatt hour. As of December 31, 2012, SCE had 53 renewable energy contracts that were approved by the CPUC and met critical contract provisions which expire at various dates between 2013 and 2035.

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Qualifying Facility Power Purchase Agreements – Under the Public Utility Regulatory Policies Act of 1978 ("PURPA"), electric utilities are required, with exceptions, to purchase energy and capacity from independent power producers that are qualifying co-generation facilities and qualifying small power production facilities ("QFs"). As of December 31, 2012, SCE had 155 QF contracts which expire at various dates between 2013 and 2025.

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Other Power Purchase Agreements – In accordance with the SCE's CPUC-approved long-term procurement plans, SCE has entered into capacity agreements with third parties, including 10 combined heat and power contracts, 14 tolling arrangements, 19 power call options and 112 resource adequacy contracts. SCE's obligations under a portion of these agreements are limited to payments for the availability of such resources.

At December 31, 2012, the undiscounted future minimum expected payments for the SCE power purchase agreements that have been approved by the CPUC and have completed major milestones for construction were as follows:



(in millions)	Renewable Energy Contracts		QF Power Purchase Agreements		Other Purchase Agreements
2013	$	629	$	361	$	851
2014	685		358		891
2015	756		324		765
2016	780		258		531
2017	781		226		523
Thereafter	13,031		387		2,554
Total future commitments	$	16,662	$	1,914	$	6,115

Some of the power purchase agreements that SCE entered into with independent power producers are treated as operating and capital leases. The following table shows the future minimum expected payments due under the contracts that are treated as operating and capital leases (these amounts are also included in the table above). The future expected payments for capital leases are discounted to their present value in the table below using SCE's incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the amount representing interest.



(in millions)	Operating Leases		Capital Leases
2013	$	958	$	33
2014	914		71
2015	933		109
2016	856		109
2017	830		109
Thereafter	11,688		1,642
Total future commitments	$	16,179	$	2,073
Amount representing executory costs			(438		)
Amount representing interest			(752		)
Net commitments			$	883

Operating lease expense for these power purchase agreements was $1.3 billion in 2012, $1.4 billion in 2011 and $1.3 billion in 2010. The timing of SCE's recognition of the lease expense conforms to ratemaking treatment for SCE's recovery of the cost of electricity and is included in purchased power.

At December 31, 2012 and 2011, SCE's net capital leases reflected in "Utility plant" on the consolidated balance sheets were $216 million and $222 million, including accumulated amortization of $33 million and $27 million, respectively. SCE had $6 million and $6 million included in "Other current liabilities" and $210 million and $216 million included in "Other deferred credits and other liabilities," representing the present value of the minimum lease payments due under these contracts recorded on the consolidated balance sheets at December 31, 2012 and 2011, respectively. SCE has a power purchase contract, with net commitments totaling $667 million, that meet the requirements for capital lease treatment, but is not reflected on the consolidated balance sheets since the lease term begins in 2014.

Other Lease Commitments

The following summarizes the estimated minimum future commitments for SCE's noncancelable other operating leases (excluding SCE's power purchase agreements discussed above):



(in millions)	Operating Leases – Other
2013	$	71
2014	68
2015	54
2016	41
2017	27
Thereafter	201
Total future commitments	$	462

Operating lease expense for other leases (primarily related to vehicles, office space and other equipment) were $75 million in 2012, $66 million in 2011 and $62 million in 2010.

Nuclear Decommissioning Commitment

SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts. The recorded liability to decommission SCE's nuclear power facilities is $2.7 billion as of December 31, 2012, based on site-specific studies performed in 2008 for San Onofre and 2007 for Palo Verde. Changes in the estimated costs, timing of decommissioning or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission. SCE estimates that it will spend approximately $8.6 billion through 2053 to decommission its active nuclear facilities. This estimate is based on SCE's decommissioning cost methodology used for ratemaking purposes, escalated at rates ranging from 1.8% to 6.9% (depending on the cost element) annually. These costs are expected to be funded from independent decommissioning trusts, which received contributions of $23 million in 2012, 2011 and 2010. SCE estimates annual after-tax earnings on the decommissioning funds of 4.2% to 5.7%. If the assumed return on trust assets is not earned, it is probable that additional funds needed for decommissioning will be recoverable through rates in the future. If the assumed return on trust assets is greater than estimated, funding amounts may be reduced through future decommissioning proceedings.

All of SCE's San Onofre Unit 1 decommissioning costs will be paid from its nuclear decommissioning trust funds and are subject to CPUC review. The estimated remaining cost to decommission San Onofre Unit 1 is recorded as an ARO liability of $68 million at December 31, 2012. Total expenditures for the decommissioning of San Onofre Unit 1 were $598 million from the beginning of the project in 1998 through December 31, 2012.

Decommissioning expense under the ratemaking method was $23 million, $23 million and $30 million in 2012, 2011 and 2010, respectively. The ARO for decommissioning SCE's active nuclear facilities was $2.6 billion and $2.5 billion at December 31, 2012 and 2011, respectively. See Note 4 and Note 15 for discussion on the nuclear decommissioning trusts.

Other Commitments

Certain other commitments for SCE for the years 2013 through 2017 are estimated below:



(in millions)	2013		2014		2015		2016		2017		Thereafter		Total
Nuclear fuel supply contracts¹	$	170	$	76	$	76	$	126	$	95	$	369	$	912
Other fuel supply contracts	42		60		86		48		—		—		236
Other contractual obligations	32		38		38		19		15		271		413


¹	These supply contracts are under review as part of events at San Onofre. See "—Contingencies—San Onofre Outage, Inspection and Repair Issues" below for further information.

Costs incurred for other commitments were $249 million in 2012, $281 million in 2011 and $177 million in 2010. SCE has fuel supply contracts which require payment only if the fuel is made available for purchase. SCE has a coal fuel contract that requires payment of certain fixed charges whether or not coal is delivered.

Indemnities

Edison International and SCE have various financial and performance guarantees and indemnity agreements which are issued in the normal course of business. The contracts discussed below included performance guarantees.

Indemnity Provided as Part of the Acquisition of Mountainview

In connection with the acquisition of the Mountainview power plant, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired in 2004 as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

Mountainview Filter Cake Indemnity

SCE has indemnified the City of Redlands, California in connection with Mountainview's California Energy Commission permit for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.

Other Indemnities

Edison International and SCE provide other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and indemnities for specified environmental liabilities and income taxes with respect to assets sold. Edison International's and SCE's obligations under these agreements may or may not be limited in terms of time and/or amount, and in some instances Edison International and SCE may have recourse against third parties. Edison International and SCE have not recorded a liability related to these indemnities. The overall maximum amount of the obligations under these indemnifications cannot be reasonably estimated.

Contingencies

In addition to the matters disclosed in these Notes, Edison International and SCE are involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International and SCE believe the outcome of these other proceedings will not, individually or in the aggregate, materially affect its results of operations or liquidity.

San Onofre Outage, Inspection and Repair Issues

Two replacement steam generators were installed at San Onofre in each of Units 2 and 3 in 2010 and 2011, respectively. In the first quarter of 2012, a water leak suddenly occurred in one of the heat transfer tubes in San Onofre's Unit 3 steam generators and the Unit was safely taken off-line. At the time, Unit 2 was off-line for a planned outage when areas of unexpected tube to support structure wear were found. Both Units have remained off-line for extensive inspections, testing and analysis of their steam generators. Each Unit will be restarted only when and if SCE determines that it is safe to do so and when start-up has been approved by the NRC pursuant to the terms of a Confirmatory Action Letter (“CAL”) issued by the NRC in March 2012. The CAL requires NRC permission to restart Unit 2 and Unit 3 and outlines actions SCE must complete before permission to restart either Unit may be sought. In October 2012, SCE submitted to the NRC a response to the CAL and restart plans for Unit 2. SCE proposed to restart Unit 2 and operate at a reduced power level (70%) for approximately five months, followed by a mid-cycle scheduled outage and inspection.

The NRC has been engaged in conducting a series of inspections, evaluations, reviews and public meetings about the causes of the steam generator malfunction and damage and to verify that SCE has performed the actions described in the CAL response and as otherwise required by its obligations as a nuclear operator. This process has included inspections and review by an NRC-appointed Augmented Inspection Team. SCE has been advised that the NRC's Office of Investigations has initiated an investigation into the accuracy and completeness of information SCE has provided to the NRC regarding the San Onofre steam generators. Should the NRC find a deficiency in SCE's performance or provision of information, SCE could be subject to additional NRC actions, including the imposition of penalties, and the findings could be taken into consideration in the CPUC regulatory proceedings described below.

Under California Public Utilities Code Section 455.5, SCE is required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months (not including preplanned outages). SCE provided such notice to the CPUC on November 1, 2012 for Unit 3 and December 6, 2012 for Unit 2. The CPUC is required within 45 days of SCE's notice for a particular Unit to initiate an investigation to determine whether to remove from customer rates some or the entire revenue requirement associated with the portion of the facility that is out of service. From the initiation date of the investigation, such rates are collected subject to refund. Under Section 455.5, any determination to adjust rates is made after hearings are conducted in connection with the utility's next general rate case.

In October 2012, in advance of SCE's required notification under Section 455.5, the CPUC issued an Order Instituting Investigation that consolidates all San Onofre issues in related regulatory proceedings and considers 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, operations and maintenance costs, and seismic study costs. The Order requires that all San Onofre-related costs incurred on and after January 1, 2012 be tracked in a memorandum account and, to the extent included in rates, collected subject to refund. The Order also states that the CPUC will determine whether to order the immediate removal, effective as of the date of the order, of all costs related to San Onofre from SCE's rates, with placement of those costs in a deferred debit account pending the return of one or both Units to useful service, or other possible action. It is currently expected that the investigation will be conducted in phases that will extend at least into 2014.

In parallel with the Order Instituting Investigation, the 2012 GRC final decision requires SCE to track San Onofre-related costs in a memorandum account subject to refund, beginning January 1, 2012. SCE filed an application in January 2013 seeking a reasonableness determination regarding these costs. That application has been consolidated with the Order Instituting Investigation proceeding.

The steam generators were designed and supplied by Mitsubishi Heavy Industries, Inc. ("MHI") and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. SCE's purchase contract with MHI states that MHI's liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions both in the contract and under law. SCE has notified MHI that it believes one or more of such exceptions now apply and that MHI's liability is not limited to $138 million, and MHI has advised SCE that it disagrees. The disagreement may ultimately become subject to dispute resolution procedures set forth in the purchase agreement, including international arbitration. SCE, on behalf of itself and the other San Onofre co-owners, has submitted three invoices to MHI totaling $106 million for steam generator repair costs incurred through October 31, 2012. MHI paid the first invoice of $45 million, while reserving its right to challenge any of the charges in the invoice. In January 2013, MHI advised SCE that it rejected a portion of the first invoice and required further documentation regarding the remainder of the invoice. SCE has recorded its share of the invoice paid as a reduction of repair and inspection costs.

San Onofre carries both property damage and outage insurance issued by Nuclear Electric Insurance Limited (“NEIL”) and has placed NEIL on notice of potential claims for loss recovery. In October 2012, SCE filed separate proofs of loss for Unit 2 and Unit 3 under the outage policy. Pursuant to these proofs of loss SCE is seeking the weekly indemnity amounts provided under the policy for each Unit. Because the outage is ongoing, SCE will supplement these proofs of loss in the future. No amounts have been recognized in SCE's financial statements, pending NEIL's response. To the extent any costs are recovered under the outage policy, SCE expects to refund those amounts to ratepayers through the ERRA balancing account.

The 2012 costs tracked in the memorandum account under the CPUC's Order Instituting Investigation include $613 million of SCE's 2012 authorized revenue requirement associated with operating and maintenance expenses, and depreciation and return on SCE's investment in Unit 2, Unit 3 and common plant. This amount is subject to refund depending on the outcome of the investigation.

In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million based on SCE's estimate after adjustment for inflation using the Handy-Whitman Index) for SCE's 78.21% share of the costs to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $601 million through December 31, 2012 on the steam generator replacement project. These expenditures remain subject to CPUC reasonableness review and approval.

As a result of outages associated with the steam generator inspection and repair, electric power and capacity normally provided by San Onofre are being purchased in the market by SCE (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market power costs through December 31, 2012 were approximately $300 million, net of avoided nuclear fuel costs, and are typically recoverable through the ERRA balancing account subject to CPUC reasonableness review, which will now take place as part of the CPUC's Order Instituting Investigation proceeding. Future market power costs cannot be estimated at this time due to uncertainties associated with when and at what output levels the Units will or may be returned to service; however, such amounts may be material.

Through December 2012, SCE's share of incremental inspection and repair costs totaled $102 million for both Units (not including payments made by MHI as described below), and repairs to restart Unit 2 at the reduced power levels described above were completed. The costs for Unit 2 may increase following NRC review under the CAL. Total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain. SCE recorded its share of payments made to date by MHI ($36 million) as a reduction of incremental inspection and repair costs.

SCE believes that the actions taken and costs incurred in connection with the San Onofre replacement steam generators and outages have been prudent. Accordingly, SCE considers its operating, capital, and market power costs, recoverable through base rates and the ERRA balancing account, as offset by third party recoveries where applicable. SCE cannot provide assurance that either or both Units of San Onofre will be returned to service, that the CPUC will not disallow costs incurred or order refunds to customers of amounts collected in rates, or that SCE will be successful in recovering amounts from third parties. A delay in the restart of San Onofre Unit 2 beyond this summer may impact plans for future operations of both Units. Disallowances of costs and/or refund of amounts received from customers could be material and adversely affect SCE's financial condition, results of operations and cash flows. SCE will pursue recoveries arising from available agreements, but there is no assurance that SCE will recover all of its applicable costs pursuant to these arrangements.

EME Chapter 11 Filing

On the Petition Date, EME and the wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Support Agreement to which EME, Edison International and certain of EME's senior unsecured noteholders are parties, each of them has agreed to support Bankruptcy Court approval of the Settlement Transaction. The Bankruptcy Court may not approve the Settlement Transaction, or even if the Settlement Transaction is approved, it may not be consummated if certain conditions are not met. If the Settlement Transaction is not approved and consummated, Edison International may not be entitled to the benefits of the Settlement Transaction and it will remain subject to any claims of EME and the noteholders, including claims relating to or arising out of any shared services, the tax allocation agreement, and any other relationships or transactions between the companies. For further information, see Note 17.

SED Investigations

San Gabriel Valley Windstorm Investigation

In November 2011, a windstorm resulted in significant damage to SCE’s electric system and service outages for SCE customers primarily in the San Gabriel Valley. The CPUC directed its Safety and Enforcement Division (“SED”) to conduct an investigation focused on the cause of the outages, SCE’s service restoration effort, and SCE’s customer communications during the outages. The SED issued its final report on January 11, 2013. The report asserts that SCE and others with whom SCE shares utility poles violated certain CPUC safety rules applicable to overhead line construction, maintenance and operation, which may have caused the failures of affected poles and supporting cables. The report also concludes that SCE’s restoration time was not adequate and makes other assertions. Additionally, the report contends that SCE violated CPUC rules by failing to preserve evidence relevant to the investigation when it did not retain damaged poles that were replaced following the windstorm. If the CPUC issues an OII regarding this matter and SCE is found to have violated any CPUC rules, it could face penalties. SCE is unable to estimate a possible loss or range of loss associated with any penalties that may be imposed by the CPUC on SCE.

The final decision in SCE’s 2012 GRC directed SCE to, among other things, make an assessment of a representative sampling of its poles to determine their conformance with current legal standards and report by July 31, 2013 on the results of this assessment. The cost of any large scale review of poles or other equipment for safety compliance, as well as any remediation measures required to assure compliance, could be significant.

Malibu Fire Order Instituting Investigation

Following a 2007 wildfire in Malibu, California, the CPUC issued an OII to determine if any statutes, CPUC general orders, rules or regulations were violated by SCE or telecomm providers (“OII Respondents”) that shared the use of three failed power poles in the wildfire area. The SED has alleged, among other things, that the poles were overloaded, that the OII Respondents violated the CPUC's rules governing the design, construction and inspection of poles and misled the CPUC during its investigation of the fire, and that SCE failed to preserve evidence relevant to the investigation. In October 2011, the SED proposed that the OII Respondents be assessed penalties of approximately $99 million, with SCE being allocated approximately $50 million of the total. SCE has denied the allegations and believes the proposed penalties are excessive. In September 2012, the CPUC approved a partial settlement between the SED and three telecomm providers, leaving SCE and a non-settling telecomm provider as the remaining respondents. The partial settlement did not resolve any of the claims against SCE or the remaining telecomm provider.

Four Corners New Source Review Litigation

In October 2011, four private environmental organizations filed a CAA citizen lawsuit against the co-owners of Four Corners. The complaint alleges that certain work performed at the Four Corners generating units 4 and 5, over the approximate periods of 1985-1986 and 2007- 2010, constituted plant “major modifications” and the plant's failure to obtain permits and install best available control technology ("BACT") violated the PSD requirements and the New Source Performance Standards of the CAA. The complaint also alleges subsequent and continuing violations of BACT air emissions limits. The lawsuit seeks injunctive and declaratory relief, civil penalties, including a mitigation project and litigation costs. In November 2012, the parties requested a stay of the litigation to allow for settlement discussion, and the court stayed the matter to March 2013. In November 2010, SCE entered into an agreement to sell its ownership interest in generating units 4 and 5 to APS. The sale remains contingent upon APS obtaining a long-term fuel supply agreement for the plant. As of January 2013, the sale agreement may be terminated by either party. As of the date of this report, the agreement has not been terminated by either

party. Under the agreement SCE would remain responsible for its pro rata share of certain environmental liabilities, including penalties arising from environmental violations prior to the sale. SCE may also be responsible for certain other liabilities retained under the Co-Tenancy Agreement, in the event of a performance default by APS. SCE is unable to estimate a possible loss or range of loss associated with this matter.

Environmental Remediation

Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operation and maintenance, monitoring and site closure. Unless there is a single probable amount, Edison International records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.

At December 31, 2012, Edison International's recorded estimated minimum liability to remediate its 23 identified material sites (sites in which the upper end of the range of the costs is at least $1 million) at SCE was $103 million, including $75 million related to San Onofre. In addition to its identified material sites, SCE also has 35 immaterial sites for which the total minimum recorded liability was $3 million. Of the $106 million total environmental remediation liability for SCE, $103 million has been recorded as a regulatory asset. SCE expects to recover $24 million through an incentive mechanism that allows SCE to recover 90% of its environmental remediation costs at certain sites (SCE may request to include additional sites) and $79 million through a mechanism that allows SCE to recover 100% of the costs incurred at certain sites through customer rates. Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at the identified material sites and immaterial sites could exceed its recorded liability by up to $179 million and $7 million, respectively, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes.

SCE expects to clean up and mitigate its identified sites over a period of up to 30 years. Remediation costs in each of the next five years are expected to range from $6 million to $13 million. Costs incurred for the years ended December 31, 2012, 2011 and 2010 were $10 million, $16 million and $17 million, respectively.

Based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to estimates.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $12.6 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor licensees. If a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.

Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.

NEIL, a mutual insurance company owned by entities with nuclear facilities, issues primary property damage, decontamination and excess property damage and accidental outage insurance policies. At San Onofre and Palo Verde, property damage insurance covers losses up to $500 million, including decontamination costs. Decontamination liability and excess property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than the federal requirement of a minimum of approximately $1.1 billion. Property damage insurance also covers damages caused by acts of terrorism up to specified limits. Additional outage insurance covers part of replacement power expenses during an accident-related nuclear unit outage.

If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $49 million per year. Insurance premiums are charged to operating expense.

Wildfire Insurance

Severe wildfires in California have given rise to large damage claims against California utilities for fire-related losses alleged to be the result of the failure of electric and other utility equipment. Invoking a California Court of Appeal decision, plaintiffs pursuing these claims have relied on the doctrine of inverse condemnation, which can impose strict liability (including liability for a claimant's attorneys' fees) for property damage. On September 15, 2012, SCE's parent, Edison International, renewed its insurance coverage, which included coverage for SCE's wildfire liabilities up to a $550 million limit (with a self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in additional self-insured costs in the event of multiple wildfire occurrences during the policy period (September 15, 2012 to August 31, 2013). SCE may experience coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.

Spent Nuclear Fuel

Under federal law, the Department of Energy ("DOE") is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.

In June 2010, the United States Court of Federal Claims issued a decision granting SCE and the San Onofre co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. SCE received payment from the federal government in the amount of the damage award in November 2011. SCE has returned to the San Onofre co-owners their respective share of the damage award paid. SCE, as operating agent, filed a lawsuit on behalf of the San Onofre owners against the DOE in the Court of Federal Claims in December 2011 seeking damages of approximately $98 million for the period from January 1, 2006 to December 31, 2010 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel. Additional legal action would be necessary to recover damages incurred after December 31, 2010. Any damages recovered by SCE are subject to CPUC review as to how these amounts would be distributed among customers, shareholders, or to offset fuel decommissioning or storage costs.