# SOUTHERN CALIFORNIA EDISON Co: Form 10-Q for the period ended Sep 30, 2012

- Company: [SOUTHERN CALIFORNIA EDISON Co](/companies/sce-pg.md) (CIK 92103)
- Form: 10-Q
- Filed: 2012-11-01
- Accepted by EDGAR: Nov 1, 2012, 16:08 ET
- Period: 2012-09-30
- Accession: 0000092103-12-000049
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/92103/000009210312000049/sce2012q3.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/92103/000009210312000049/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2012-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Operating income | 3 months, 2012-07-01 to 2012-09-30 | $659.0m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2012-01-01 to 2012-09-30 | $1.49bn | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2012-07-01 to 2012-09-30 | $124.0m | us-gaap:InterestExpense |
| Interest expense | 9 months, 2012-01-01 to 2012-09-30 | $373.0m | us-gaap:InterestExpense |
| Income tax | 3 months, 2012-07-01 to 2012-09-30 | $176.0m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2012-01-01 to 2012-09-30 | $384.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2012-07-01 to 2012-09-30 | $363.0m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2012-01-01 to 2012-09-30 | $736.0m | us-gaap:NetIncomeLoss |
| Operating cash flow | 9 months, 2012-01-01 to 2012-09-30 | $2.66bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 9 months, 2012-01-01 to 2012-09-30 | $3.10bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2012-09-30 | $90.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2012-09-30 | $2.92bn | us-gaap:AssetsCurrent |
| Total assets | at 2012-09-30 | $43.06bn | us-gaap:Assets |
| Current liabilities | at 2012-09-30 | $3.23bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2012-09-30 | $32.00bn | us-gaap:Liabilities |
| Long-term debt | at 2012-09-30 | $8.83bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2012-09-30 | $380.0m | us-gaap:LongTermDebtCurrent |
| Short-term borrowings | at 2012-09-30 | $380.0m | us-gaap:ShortTermBorrowings |
| Shareholders' equity | at 2012-09-30 | $11.06bn | us-gaap:StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest |

## Management's discussion and analysis

As filed, 60,308 characters.

### 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 SCE's current expectations and projections about future events based on 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 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 SCE, include, but are not limited to:

- ability of SCE to recover its costs in a timely manner from its customers through regulated rates;
- decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions;
- possible customer bypass or departure due to technological advancements 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 nuclear and other power generating facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts;
- risk that Units 2 and/or Unit 3 at San Onofre may not recommence operations or may require extensive repairs or replacement of the steam generators; with the cost of the related outcome not being recoverable from SCE's supplier, insurance coverage or through regulatory processes;
- environmental laws and regulations, both at 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;
- cost of capital and the ability to borrow funds and access to capital markets on reasonable terms;
- the cost and availability of electricity including the ability to procure sufficient resources to meet expected customer needs to replace power that would have been provided by San Onofre but for the current outage or in the event of other power plant outages or significant counterparty defaults under power-purchase agreements;
- changes in the fair value of investments and other assets;
- changes in interest rates and rates of inflation, including those 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 Independent System Operators and Regional Transmission Organizations;
- 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 coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts;
- cost and availability of emission credits or allowances for emission credits;
- transmission congestion in and to each market area and the resulting differences in prices between delivery points;
- ability to provide sufficient collateral in support of hedging activities and power and fuel purchased;
- 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 SCE's 2011 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 2011 Form 10-K, and carefully consider the risks, uncertainties and other factors that affect SCE's business. Forward-looking statements speak only as of the date they are made and SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE with the U.S. Securities and Exchange Commission.

The MD&A for the three- and nine-month periods ended September 30, 2012 discusses material changes in the consolidated financial condition, results of operations and other developments of SCE since December 31, 2011 and as compared to the three- and nine-month periods ended September 30, 2011. This discussion presumes that the reader has read or has access to SCE's MD&A for the calendar year 2011 (the "year-ended 2011 MD&A"), which was included in the 2011 Form 10-K.

### MANAGEMENT OVERVIEW

### Highlights of Operating Results

*(in millions)*

|  | Three months ended September 30, 2012 | 2011 | Change | Nine months ended September 30, 2012 | 2011 | Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Core earnings | $363 | $406 | $(43) | $736 | $838 | $(102) |
| Non-core items | — | — | — | — | — | — |
| Net income available for common stock | $363 | $406 | $(43) | $736 | $838 | $(102) |

SCE's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings for financial planning and for analysis of performance. Core earnings are also used when communicating with analysts and investors regarding SCE's earnings results to facilitate comparisons of the performance from period to period. Core earnings are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to SCE less income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of certain tax, regulatory or legal matters or proceedings.

SCE's 2012 core earnings decreased $43 million and $102 million for the quarter and year-to-date, respectively. Core earnings in both periods decreased primarily due to a delay in the 2012 CPUC General Rate Case decision as higher depreciation and net interest expenses are not being recovered in currently authorized revenue, as well as higher costs at San Onofre. SCE has incurred $48 million and $96 million of incremental steam generator inspection and repair costs related to outages at San Onofre for the quarter and year-to-date periods in 2012, respectively, and $30 million in severance costs. These costs were partially offset by other operations and maintenance cost reductions in both periods. The revenue requirement ultimately adopted by the CPUC will be retroactive to January 1, 2012.

### 2012 CPUC General Rate Case

As discussed in the year-ended 2011 MD&A, SCE's 2012 GRC application, which requested a 2012 base rate revenue requirement of $6.29 billion, has been under submission to the CPUC.

On October 19, 2012, the CPUC assigned administrative law judge issued a proposed decision, which, if adopted, would result in a 2012 base rate revenue requirement of $5.69 billion, a decrease of $601 million from SCE's requested revenue requirement, primarily related to decreases in operations and maintenance expenses with some plant-related capital reductions, including potential disallowances of recorded capital investments for specific projects. The proposed decision, if adopted, would result in an increase of approximately $400 million over currently authorized revenue. The proposed decision approves San Onofre costs subject to refund and reasonableness review and includes a requirement to track those costs in a memorandum account. See “—San Onofre” below for further information. The proposed decision also accepts SCE's requested rate-making treatment of tax repair deductions. See "SCE Notes to Consolidated Financial Statements—Note 7. Income Taxes" for further discussion.

The proposed decision would allow a post-test year ratemaking methodology that escalates capital additions by 3.05% for 2013 and 2.93% for 2014. It would also allow operations and maintenance expense to be escalated for 2013 and 2014 through the use of various escalation factors for labor, non-labor and medical expenses. The methodology adopted in the proposed decision would result in a revenue requirement of $6.08 billion for 2013 and $6.43 billion for 2014.

SCE is currently recognizing revenue largely based on the 2011 authorized revenue requirement. The CPUC has authorized the establishment of a GRC memorandum account, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.

SCE is required to file comments within 20 days of receiving the proposed decision. The final CPUC decision could result in material changes to the proposed decision. A final CPUC decision is expected by year-end.

### 2013 Cost of Capital Application

In June 2012, the CPUC issued an order in the 2013 Cost of Capital proceeding consolidating SCE's 2013 application with the three other California investor-owned utilities' applications and splitting the proceeding into two phases. The first phase will address the 2013 ratemaking capital structure and cost of capital for the utilities and contemplates a final decision in December 2012. The second phase will consider whether the current multi-year mechanism should be continued or modified. A final decision for the second phase is expected in April 2013.

SCE's 2013 cost of capital application, which was filed in April 2012, requested a ratemaking capital structure of 43% long-term debt, 9% preferred equity and 48% common equity consistent with the current capital structure. In October 2012, SCE submitted an update to its requested cost of capital further reducing its current cost of capital as follows: cost of long-term debt from 6.22% to 5.49%, authorized cost of preferred equity from 6.01% to 5.79% and authorized return on common equity from 11.5% to 11.1%. The application also requested the continuation of the current multi-year mechanism, which would have retained the authorized capital structure through 2015 with annual adjustments of the cost components if certain thresholds are reached.

### San Onofre

### Outage, Inspection and Repair Issues

As discussed in the 2011 Form 10-K, four replacement steam generators were installed at San Onofre 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. Unit 3 was safely taken off-line. At the time, San Onofre Unit 2 was off-line for a planned outage when areas of unexpected wear in some of its heat transfer tubes 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 as described below.

#### Tube Leak and Repairs

The water leak in the Unit 3 steam generator was caused by excessive wear resulting from tube-to-tube contact in the area of the leak. During the inspection and testing of the Unit 3 steam generators, additional pressure tests of certain tubes were completed to determine the safety significance of the wear. Eight of the 129 tubes subjected to the additional tests failed the tests for structural integrity as a result of excessive wear, and the NRC was notified as required. The same areas were re-inspected in the Unit 2 steam generators using a more sensitive inspection method than had previously been employed, and similar wear from tube-to-tube contact was found on two tubes in one of the steam generators at wear levels below the detection capability of the initial inspection. Earlier tests performed on the Unit 2 steam generators during the planned outage additionally found levels of unexpected wear at points where some tubes were in contact with retainer bars of the tube support structure. Subsequent inspections on Unit 3 found similar tube-to-support structure wear.

As a result of these findings, SCE has plugged and removed from service all tubes showing excessive wear in each of the steam generators. In addition, SCE preventively plugged all tubes in contact with retainer bars or in the area of the tube bundles where tube-to-tube contact occurred. Each steam generator has over 9,700 heat transfer tubes and is designed to include sufficient tubes to accommodate a need to remove some from service for a variety of reasons, and the tubes that SCE has removed from service are within this margin.

A team of outside experts was assembled to assist SCE and Mitsubishi Heavy Industries, Inc. (“MHI”), the manufacturer of the steam generators, in the analysis of the causes of the tube-to-tube wear and potential remedial actions. As a result of their work, SCE understands that the tube-to-tube contact arises from excessive vibration of the tubes in certain areas of the steam generators. The excessive vibration that caused the tube-to-tube wear on Unit 3 resulted from a phenomenon called fluid elastic instability. This phenomenon arises from a combination of thermal hydraulic conditions (steam velocity and moisture content of the steam), and ineffectiveness of the tube supports in the areas where the vibration occurs. Unit 2 is susceptible to the same thermal hydraulic conditions as Unit 3, but the Unit 2 supports largely remained effective for the entire time that it operated as compared to Unit 3. This difference is likely the result of manufacturing differences between the pairs of steam generators in the two Units.

SCE's restart plans for Unit 2 and its response to the CAL are based on work done by engineering groups of three independent firms with expertise in steam generator design and manufacturing. Restart plans for only Unit 2 were submitted because of the extensive tube-to-tube wear in Unit 3, which was not experienced in Unit 2 (in which only one point of tube-to-tube wear between two tubes was identified). Using different methodologies, each independent outside engineering group concluded that it would be safe to restart Unit 2 and operate at a reduced power level (70%) for approximately five months, followed by a mid-cycle scheduled outage. The power level is being reduced to avoid the steam velocity and moisture content conditions that cause fluid elastic instability. The five month operating period is less than half the time Unit 3 operated and was validated by the independent experts as providing a safety margin to provide assurance of safe operation. In addition to these requirements, the restart plan covers repairs, corrective actions and operating parameters and also includes additional monitoring, detection and response activities.

Inasmuch as Unit 3 had much more tube-to-tube wear than Unit 2, it is not clear at this time whether Unit 3 will be able to restart without extensive additional repairs and corrective actions. Unit 3 will not restart this year and it is uncertain when or whether a restart plan will be submitted. The Unit 3 reactor is de-fueled and SCE is placing appropriate systems in a lay-up condition while analysis and testing continue. SCE is also engaged in the analysis of what repairs, if any, could be undertaken to restore the steam generators on both Units to their originally specified capabilities safely, but it has not determined what those repairs might be or whether the generators will need to be replaced for the Units to operate at their prior output levels. Each Unit will only be restarted when any necessary repairs and appropriate mitigation plans for that Unit are completed in accordance with the CAL, and the NRC and SCE are satisfied that it is safe to do so.

#### NRC Processes

The timing of restart of the Units will also be affected by the nature of and schedule for regulatory processes required by the NRC. There is no set or predetermined time period for approval of Unit 2's proposed restart, and, accordingly, there can be no assurance about the length of time the NRC may take to review SCE's request to restart or whether any such request would be granted in whole or in part.

The NRC will conduct one or more on-site inspections to verify that SCE has performed the actions described in the CAL response and will hold public meetings to discuss the CAL response as well as the results of the on-site inspections. There is no timeline for the NRC's review of the CAL response. It is also possible that one or more amendments to the NRC operating license for San Onofre might be required (whether or not as a prerequisite to return a Unit to safe operation). The NRC could also choose to impose additional processes and assessments that could result in significant costs or additional delay.

Following the failure of pressure tests on the eight tubes in Unit 3, the NRC launched an Augmented Inspection Team (“AIT”) to assess the tube failures and their causes, SCE's operation of the Units, and SCE's oversight of the design, fabrication, shipping, and construction process. In July 2012, the NRC issued a report providing the results of the AIT inspection. That report concluded that the replacement steam generators' design and configuration did not provide the necessary margin to prevent fluid elastic instability and that these deficiencies appear to be related to MHI's computer code used to model thermal hydraulic conditions in the steam generators. The report further stated that SCE was adequately pursuing the causes of the unexpected steam generator tube-to-tube degradation. The AIT report also identified a number of as-yet unresolved issues that are continuing to be examined. The unresolved issues include further evaluation of manufacturing differences between Unit 2 and Unit 3, with particular focus on the control of critical dimensions affecting the clearances between tubes and tube supports. The NRC will conduct subsequent inspections or reviews to determine what, if any, regulatory actions result from these unresolved items. Should the NRC find a deficiency in SCE's performance, SCE could be subject to additional NRC actions, and the findings could be taken into consideration in the CPUC regulatory proceedings described below.

#### CPUC Review

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 will provide such notice to the CPUC on November 1, 2012 for Unit 3 and expects to do so by 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. If, after investigation and hearings, the costs associated with a Unit are disallowed recovery because it is out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation.

In October 2012, in advance of SCE's required notification under Section 455.5, the CPUC issued an order instituting investigation that will consolidate all San Onofre issues in related regulatory proceedings and consider appropriate cost recovery for all San Onofre costs, including among other costs, the cost of the steam generator replacement project, market power costs, capital and 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. SCE will file its response to the order by November 26, 2012. SCE must also file testimony by December 10, 2012 detailing proposed rate adjustments due to the outages, including the amount of San Onofre costs in current rates, the amount to be removed, if any, the effective date, and related information. A pre-hearing conference will be scheduled early in 2013 after the issuance of a Scoping Memo by the Assigned Commissioner.

In parallel with the order instituting investigation, the 2012 GRC proposed decision would, if adopted, require SCE to track San Onofre-related costs in a memorandum account subject to refund, beginning January 1, 2012. SCE would be required by January 30, 2013 to file an application for reasonableness review of these costs and the proposed decision would allow that application to be consolidated with other proceedings. The 2012 GRC proposed decision also approves expenditures incurred through 2011 for the high pressure turbine project, but disallows recovery for post-2011 expenditures associated with the project and directs SCE to record those costs in either the memorandum account or seek future rate recovery in the next GRC. SCE anticipates that the inter-relationship between the Section 455.5 process and the issues to be reviewed in the investigation or pursuant to a final decision in the GRC will be addressed by the CPUC as it continues to develop the scope of the issues to be consolidated within the investigation.

In addition to the amounts for inspection and repair and market power costs discussed below, SCE has collected through customer rates an estimated $625 million of revenue through third quarter 2012 (based on current authorized revenue requirements) associated with the plant. SCE's total 2012 San Onofre annual revenue requirement, including the 2012 GRC proposed decision, is approximately $820 million, made up of $170 million in refueling outage, nuclear fuel and decommissioning costs and $650 million for its direct operating and maintenance costs, depreciation and return on its investment in San Onofre Unit 2, Unit 3 and related common plant. At September 30, 2012, SCE's rate base and net investment associated with San Onofre were as set forth in the following table:

*(in millions)*

| Net investment | Unit 2 | Unit 3 | Common Plant | Total |
| --- | ---: | ---: | ---: | ---: |
| Net plant in service | $593 | $418 | $261 | $1,272 |
| Materials and supplies | — | — | 99 | 99 |
| Construction work in progress | 77 | 141 | 76 | 294 |
| Nuclear fuel | 153 | 212 | 101 | 466 |
| Net investment | $823 | $771 | $537 | $2,131 |
| Rate base |  |  |  |  |
| Net plant in service | $593 | $418 | $261 | $1,272 |
| Materials and supplies | — | — | 99 | 99 |
| Accumulated deferred income taxes | (95) | (45) | (66) | (206) |
| Amounts in rate base | $498 | $373 | $294 | $1,165 |

In 2005, the CPUC authorized expenditures of approximately $525 million ($665 million after adjustment for inflation) for SCE's 78.21% share of San Onofre to purchase and install the four new steam generators in Units 2 and 3 and remove and dispose of their predecessors. SCE has spent $594 million through September 30, 2012 on the steam generator replacement project, including $95 million reflected in construction work in progress primarily related to the disposal of the replaced steam generators. Those expenditures remain subject to CPUC reasonableness review. Final costs for the project will not be known until after disposal of the original steam generators is completed.

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 costs through September 30, 2012 were approximately $221 million, net of avoided nuclear fuel costs, and are recoverable through the ERRA balancing account subject to CPUC reasonableness review. Because of the uncertainties associated with when and at what output levels the Units will or may be returned to service, total potential market power costs cannot be estimated at this time.

Through September 2012, SCE's share of incremental inspection and repair costs totaled $96 million for both Units. At September 30, 2012, the repairs to restart Unit 2 at the reduced power levels described above have been substantially completed. The costs for Unit 2 may increase following NRC review under the CAL and any new developments that may result from further analysis, testing and inspection, and there is no assurance that start-up of Unit 2 will occur as described above. Total incremental repair costs associated with returning Unit 3 to service, and returning both Units to service at originally specified capabilities safely, remain uncertain.

#### Contractual Matters

The steam generators were designed and supplied by 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. In September 2012, SCE submitted an invoice to MHI for costs paid through June 30, 2012 in the amount of $45 million for both SCE's and the other co-owners' share of steam generator repair costs. SCE expects to continue to invoice MHI for costs incurred. No amounts have been recognized in the financial statements as of September 30, 2012.

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. The property damage policy (including excess coverage) provides insurance for certain costs and expenses resulting from “Accidental Property Damage” with a $2.5 million deductible and a $2.75 billion limit of liability. After a twelve week deductible period, the outage policy provides insurance for an outage caused by “Accidental Property Damage” of up to $3.5 million per week for each Unit (or $2.8 million per Unit per week if both Units are out because of the same "Accident"), with a $490 million limit for each Unit ($392 million each if both Units are out because of the same "Accident"). The NEIL policies have a number of exclusions and limitations that may reduce or eliminate coverage. For instance, coverage may be reduced or excluded if it is determined that the outage resulted from any condition which develops, progresses or changes over time, or from wear and tear. Further, costs to "make good" faulty workmanship or design and amounts collectible from third parties are excluded from the property damage policy. Proof of loss must be submitted within 12 months of the Accidental Property Damage under the property damage insurance and within 12 months of the end of the outage under the outage policy. 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 further actions by NEIL. To the extent any costs are recovered under the outage policy, SCE expects to refund those amounts to ratepayers through the ERRA balancing account. For further information, see "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

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.

#### CAISO Summer Readiness Planning

In addition to providing up to 2,200 MW of electric power, San Onofre also provides significant reliability support to the electric grid, including support for grid voltage and stability. SCE continues to work with the CAISO to maintain grid reliability for summer 2013 and beyond while the San Onofre Units are out of service. SCE is supporting CAISO in its negotiations to obtain local grid voltage support. SCE has also accelerated certain transmission projects and will expand its demand response programs to help maintain grid reliability. The majority of these efforts are projects that are already included in SCE's capital expenditure plan, but their timing has been accelerated. In addition, SCE has proposed to the CAISO projects such as transmission line reconfiguration and installation of equipment to support voltage and stability. The projects, if approved could result in additional capital expenditures from $100 million to $125 million over the period 2013 – 2015.

### Workforce Reduction

In August 2012, SCE announced plans for downsizing to bring the San Onofre organization and cost structure in line with industry peers. SCE plans to reduce the San Onofre workforce by 730 employees to 1,500 employees beginning in the fourth quarter of 2012 and continuing in 2013. At September 30, 2012, SCE had recorded $30 million in estimated cash severance costs (SCE's share) related to the non-represented employee workforce reduction.

### Capital Program

During the first nine months of 2012, SCE's capital investment program focused on maintaining reliability and expanding the capability of SCE's transmission and distribution system; upgrading and constructing new transmission lines and substations; installing digital meters; and replacing generation asset equipment. Total capital expenditures (including accruals) were $2.6 billion during the first nine months of 2012 compared to $2.5 billion during the same period in 2011. SCE expects that 2012 capital expenditures will be below the lower end of the previously projected $4.4 billion to $5.0 billion range due to the delay in the GRC decision, the delay related to the Tehachapi Project and outages at San Onofre. However, SCE continues to project that 2012 – 2014 total capital expenditures will be in the range of $11.8 billion to $13.2 billion. 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; outcome of the San Onofre mitigation plans; and other factors.

### RESULTS OF OPERATIONS

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 revenues 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.

The following tables summarize SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities. Beginning in 2012, SCE classified revenues and costs related to programs that provide for recovery of actual costs plus a return on capital as utility earning activities. Previously, SCE classified the recovery of actual costs incurred under these programs as utility cost-recovery activities. The tables presented below reflect a reclassification of the revenues and costs for 2011 consistent with the presentation in 2012. The reclassification of revenues and costs had no impact on earnings.

During the first nine months of 2012, pending the outcome of the 2012 GRC, SCE recognized GRC-related revenue based on the 2011 authorized revenue requirement included in customer rates. This has resulted in a decrease in net income as higher depreciation and net interest expenses are not being recovered in currently authorized revenue. A GRC memorandum account has been established for SCE, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. Recognition of the revenue for the period January 1, 2012 through the date of a final decision, as well as any delays in certain expenditures and changes in authorized treatment of specific costs, will impact the timing of earnings in 2012 (see "Management Overview—2012 CPUC General Rate Case" for further discussion).

### Three Months Ended September 30, 2012 versus September 30, 2011

*(in millions)*

|  | Three months ended September 30, 2012 Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | Three months ended September 30, 2011 Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| **Operating revenue** | $1,754 | $1,977 | $3,731 | $1,759 | $1,627 | $3,386 |
| Fuel and purchased power | — | 1,694 | 1,694 | — | 1,374 | 1,374 |
| Operations and maintenance | 623 | 283 | 906 | 566 | 253 | 819 |
| Depreciation decommissioning and amortization | 399 | — | 399 | 358 | — | 358 |
| Property taxes and other | 73 | — | 73 | 71 | — | 71 |
| **Total operating expenses** | 1,095 | 1,977 | 3,072 | 995 | 1,627 | 2,622 |
| **Operating income** | 659 | — | 659 | 764 | — | 764 |
| Net interest expense and other | (95) | — | (95) | (98) | — | (98) |
| **Income before income taxes** | 564 | — | 564 | 666 | — | 666 |
| Income tax expense | 176 | — | 176 | 245 | — | 245 |
| **Net income** | 388 | — | 388 | 421 | — | 421 |
| Dividends on preferred and preference stock | 25 | — | 25 | 15 | — | 15 |
| Net income available for common stock | $363 | $— | $363 | $406 | $— | $406 |
| Core Earnings1 |  |  | $363 |  |  | $406 |
| Non-Core Earnings |  |  | — |  |  | — |
| Total SCE GAAP Earnings |  |  | $363 |  |  | $406 |

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:

- Higher operations and maintenance expense of $57 million was primarily due to increased costs at San Onofre, including $48 million related to the steam generator inspection and repair at San Onofre and $30 million of estimated cash severance costs related to the planned San Onofre reduction in workforce; partially offset by lower operations and maintenance expenses. These increases were partially offset by EdisonSmartConnect® benefits realized and other cost savings and timing of expenses.
- Higher depreciation, decommissioning and amortization expense of $41 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs.
- Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information.
- Higher preferred and preference stock dividends of $10 million related to new issuances in 2012.

### Utility Cost-Recovery Activities

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

- Higher fuel and purchased power expense of $320 million was primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below) and $104 million of market costs net of lower nuclear fuel costs related to the outage at San Onofre in 2012 (see "Management Overview—San Onofre" for further information). These increases were partially offset by lower power prices in 2012.
- Higher operations and maintenance expense of $30 million was primarily due to increased energy efficiency program costs.

### Nine Months Ended September 30, 2012 versus September 30, 2011

*(in millions)*

|  | Nine months ended September 30, 2012 Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | Nine months ended September 30, 2011 Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| **Operating revenue** | $4,670 | $4,124 | $8,794 | $4,596 | $3,467 | $8,063 |
| Fuel and purchased power | — | 3,269 | 3,269 | — | 2,691 | 2,691 |
| Operations and maintenance | 1,774 | 848 | 2,622 | 1,675 | 775 | 2,450 |
| Depreciation decommissioning and amortization | 1,187 | — | 1,187 | 1,058 | — | 1,058 |
| Property taxes and other | 227 | 2 | 229 | 216 | 1 | 217 |
| **Total operating expenses** | 3,188 | 4,119 | 7,307 | 2,949 | 3,467 | 6,416 |
| **Operating income** | 1,482 | 5 | 1,487 | 1,647 | — | 1,647 |
| Net interest expense and other | (296) | (5) | (301) | (269) | — | (269) |
| **Income before income taxes** | 1,186 | — | 1,186 | 1,378 | — | 1,378 |
| Income tax expense | 384 | — | 384 | 496 | — | 496 |
| **Net income** | 802 | — | 802 | 882 | — | 882 |
| Dividends on preferred and preference stock | 66 | — | 66 | 44 | — | 44 |
| Net income available for common stock | $736 | $— | $736 | $838 | $— | $838 |
| Core Earnings1 |  |  | $736 |  |  | $838 |
| Non-Core Earnings |  |  | — |  |  | — |
| Total SCE GAAP Earnings |  |  | $736 |  |  | $838 |

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:

- Higher operating revenue of $74 million was primarily due to $80 million of increased revenue related to authorized CPUC projects not included in SCE's GRC process, including the EdisonSmartConnect® project and the Solar Photovoltaic project (approximately $65 million primarily recovered operations and maintenance and depreciation expense associated with the related CPUC projects). The change in revenue also reflects revenue recognized in 2012 related to the San Onofre Unit 2 scheduled outage costs. In December 2011, the CPUC authorized revenue requirements for 2012 refueling outages for San Onofre. These increases were partially offset by decreases in other operating revenue.
- Higher operation and maintenance expense of $99 million was primarily due to increased costs at San Onofre, including $96 million of costs related to the steam generator inspection and repair as well as $35 million related to the 2012 San Onofre Unit 2 scheduled maintenance and refueling outage and $30 million of estimated cash severance costs related to the planned San Onofre reduction in workforce (see "Management Overview—San Onofre" for further information); partially offset by lower operations and maintenance expenses. These increases were partially offset by EdisonSmartConnect® benefits realized and other cost savings and timing of expenses.
- Higher depreciation, decommissioning and amortization expense of $129 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs and CPUC capital-related projects discussed above.
- Higher net interest expense and other of $27 million was primarily due to higher outstanding balances on long-term debt.
- Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information.
- Higher preferred and preference stock dividends of $22 million related to new issuances in 2012.

### Utility Cost-Recovery Activities

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

- Higher fuel and purchased power expense of $578 million was primarily driven by the cost to replace CDWR contracts that expired in 2011, which were not previously recorded as an SCE cost but which were included as a separate component on customer bills (see "—Supplemental Operating Revenue Information" below) and $221 million of market costs net of lower nuclear fuel costs related to the San Onofre outage in 2012 (see "Management Overview—San Onofre" for further information). These increases were partially offset by lower power prices in 2012.
- Higher operation and maintenance expense of $73 million was primarily due to increased pension contributions.

### Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $3.7 billion and $8.7 billion for the three- and nine-month periods ended September 30, 2012, respectively, compared to $3.3 billion and $7.8 billion for the respective periods in 2011. The increase in revenue reflects:

- A sales volume increase of $677 million and $1.4 billion for the three- and nine-month periods, respectively, primarily due to SCE providing power that was previously provided by CDWR contracts which expired in 2011. Prior to 2012, SCE remitted to CDWR and did not recognize as revenue the amounts that SCE billed and collected from its customers for the portion of electric power purchased and sold by the CDWR to SCE's customers.
- A rate decrease of $294 million and $502 million for the three- and nine-month periods, respectively, resulting from rate adjustments in June 2011 and August 2012, primarily reflecting lower forecasted fuel and purchased power costs and refunds to customers of overcollected fuel and power procurement-related costs.

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 2011 Form 10-K).

Due to warmer weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than other quarters.

### Income Taxes

The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.

*(in millions)*

|  | Three months ended September 30, 2012 | 2011 | Nine months ended September 30, 2012 | 2011 |
| --- | ---: | ---: | ---: | ---: |
| Income before income taxes | $564 | $666 | $1,186 | $1,378 |
| Provision for income tax at federal statutory rate of 35% | 197 | 233 | 415 | 482 |
| Increase (decrease) in income tax from: |  |  |  |  |
| State tax – net of federal benefit | 10 | 31 | 30 | 61 |
| Property-related | (19) | (18) | (39) | (38) |
| Other | (12) | (1) | (22) | (9) |
| Total income tax expense | $176 | $245 | $384 | $496 |
| Effective tax rate | 31% | 37% | 32% | 36% |

State income taxes were lower for both the three- and nine-month periods ended September 30, 2012 due to lower pre-tax income and higher benefits related to depreciation, cost of removal and repair deductions, including additional tax deductions reflected in SCE's 2011 tax returns.

For a discussion of the status of Edison International's income tax audits, see "SCE Notes to Consolidated Financial Statements—Note 7. Income Taxes."

### LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, fund capital expenditures, and implement its business strategy are 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 and dividend payments to investors, and the outcome of tax and regulatory matters.

SCE expects to fund its 2012 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 meet operating and capital requirements.

### Available Liquidity

During the second quarter of 2012, SCE replaced its existing credit facilities scheduled to mature in early 2013 with a new $2.75 billion five-year revolving credit facility that matures May 2017. The following table summarizes the status of the SCE credit facility at September 30, 2012:

*(in millions)*

|  | Credit Facilities |
| --- | ---: |
| Commitment | $2,750 |
| Outstanding commercial paper supported by credit facilities | (380) |
| Outstanding letters of credit | (196) |
| Amount available | $2,174 |

### Debt Covenant

SCE has a debt covenant in its credit facility that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At September 30, 2012, SCE's debt to total capitalization ratio was 0.46 to 1.

### Capital Investment Plan

### Transmission Projects - Tehachapi Project

As discussed in the year-ended 2011 MD&A, the CPUC requested that SCE provide information on potential new options for a portion of the Tehachapi Project, including traversing a state park, changing the nature of some of the towers and undergrounding lines. In July 2012, the Assigned Commissioner issued a ruling requesting SCE to further study and provide more detailed information by the end of February 2013 on two identified undergrounding options for a portion of the project. The ruling set forth a schedule for interested parties to also provide further information, briefing by all parties and evidentiary hearings. The order states that the construction of the affected portion of the project shall remain deferred until the CPUC makes a final determination regarding the options. Adoption of either of the two undergrounding options could create significant additional costs and delay the completion of the project. SCE is required to file revised cost estimates with the CPUC by the end of February 2013. As with all transmission investments, cost recovery will be subject to future rate proceedings.

### Regulatory Proceedings

### FERC Formula Rates

As discussed in the year-ended 2011 MD&A, the FERC has accepted, subject to refund and settlement procedures, SCE's request to implement formula rates as a means to determine SCE's FERC transmission revenue requirement effective January 1, 2012. SCE's request would result in a total 2012 FERC weighted average ROE of 11.1% including a base ROE of 9.93% and the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives.

In September 2012, SCE filed its proposed formula rate update with the FERC. SCE's proposed request would implement a 2013 transmission revenue requirement of $900 million, representing an increase of $178 million or 25% over the 2012 revenue requirement. The increase is primarily due to higher FERC rate base from transmission investments, including projects under construction. Consistent with SCE's proposed formula rate methodology, the proposed revenue requirement utilizes the 2012 FERC authorized base ROE discussed above, which remains subject to refund and the ongoing settlement negotiations.

The formula rate mechanism, including the base ROE, is subject to final resolution as part of the settlement process or, if a settlement is not achieved, to determination by FERC in a litigated process. SCE and the other parties to the proceeding continue to engage in settlement negotiations.

### Dividend Restrictions

The CPUC regulates SCE's capital structure which limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At September 30, 2012, SCE's 13-month weighted-average common equity component of total capitalization was 48.9% resulting in the capacity to pay $175 million in additional dividends to Edison International. During the first nine months of 2012, SCE made $349 million in dividend payments to its parent, Edison International.

### 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 September 30, 2012, 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 September 30, 2012.

*(in millions)*

|  |  |
| --- | ---: |
| Collateral posted as of September 30, 20121 | $249 |
| Incremental collateral requirements for power procurement contracts resulting from a potential downgrade of SCE's credit rating to below investment grade | 64 |
| Posted and potential collateral requirements2 | $313 |

1 Collateral provided to counterparties and other brokers consisted of $44 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $9 million of cash reflected in "Other current assets" on the consolidated balance sheets and $196 million in letters of credit.

2 Total posted and potential collateral requirements may increase by $14 million based on SCE's forward positions as of September 30, 2012 due to adverse market price movements over the remaining lives of the existing power procurement contracts using a 95% confidence level.

### Workers Compensation Self-Insurance Fund

For a discussion of potential collateral requirements related to its self-insured workers compensation plan, refer to "Liquidity and Capital Resources—Workers Compensation Self-Insurance Fund" in the year ended 2011 MD&A.

### Historical Consolidated Cash Flows

The table below sets forth condensed historical cash flow information for SCE.

*(in millions)*

|  | Nine months ended September 30, 2012 | 2011 |
| --- | ---: | ---: |
| Net cash provided by operating activities | $2,656 | $2,272 |
| Net cash provided by financing activities | 636 | 672 |
| Net cash used by investing activities | (3,259) | (3,136) |
| Net increase (decrease) in cash and cash equivalents | $33 | $(192) |

### Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $384 million in the first nine months of 2012 compared to the same period in 2011. The increase in cash flows provided by operating activities was primarily due to higher net tax receipts in 2012, the impact of higher costs at San Onofre and the timing of cash receipts and disbursements related to working capital items.

### Net Cash Provided by Financing Activities

The following table summarizes cash provided by financing activities for the nine months ended September 30, 2012 and 2011. Issuances of debt and preference stock are discussed in "SCE Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements—Long-Term Debt" and "Note 12. Preferred and Preference Stock."

*(in millions)*

|  | Nine months ended September 30, 2012 | 2011 |
| --- | ---: | ---: |
| Issuances of first and refunding mortgage bonds, net | $391 | $492 |
| Net issuances of commercial paper1 | (45) | 550 |
| Issuances of preference stock, net | 804 | 123 |
| Payments of common stock dividends to Edison International | (349) | (345) |
| Redemptions of preference stock | (75) | — |
| Bonds purchased | — | (86) |
| Payments of preferred and preference stock dividends | (62) | (43) |
| Other | (28) | (19) |
| Net cash provided by financing activities | $636 | $672 |

1 Issuances of commercial paper are supported by SCE's credit facility.

The timing and amount of SCE's financing activities are largely driven by its capital program.

### 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 $3.1 billion and $3.0 billion for the nine months ended September 30, 2012 and 2011, respectively (see "Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2011 MD&A for further information on capital expenditures). Net purchases of nuclear decommissioning trust investments and other were $164 million and $146 million for the nine months ended September 30, 2012 and 2011, respectively.

### Contractual Obligations and Contingencies

### Contractual Obligations

SCE has power purchase commitments which are discussed in "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

### Contingencies

SCE has contingencies related to the San Onofre Outage, Inspection and Repair Issues, CPSD Investigations, Four Corners New Source Review Litigation, Nuclear Insurance, Wildfire Insurance and Spent Nuclear Fuel, which are discussed in "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."

#### Environmental Remediation

As of September 30, 2012, SCE had identified 25 material sites for remediation and recorded an estimated minimum liability of $113 million. SCE expects to recover 90% of its remediation costs at certain sites. See "SCE Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" for further discussion.

### MARKET RISK EXPOSURES

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 for customers and SCE. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "SCE Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities" and "—Note 4. Fair Value Measurements."

### Commodity Price Risk

The fair value of outstanding derivative instruments used to mitigate SCE's exposure to commodity price risk was a net liability of $1.0 billion and $936 million at September 30, 2012 and December 31, 2011, respectively. To the extent San Onofre Unit 2 and Unit 3 are not operating, SCE may be exposed to market prices associated with replacement power costs. SCE's hedging program has taken this exposure into consideration and has entered into forward contracts to address projected market price variability. For further discussion of fair value measurements and the fair value hierarchy, see "SCE 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. As of September 30, 2012, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:

*(in millions)*

| S&P Credit Rating1 | September 30, 2012 Exposure2 | Collateral | Net Exposure |
| --- | ---: | ---: | ---: |
| A or higher | $101 | $— | $101 |
| Not rated3 | 5 | (1) | 4 |
| Total | $106 | $(1) | $105 |

1 SCE assigns a credit rating based on the lower of a counterparty's S&P or Moody's rating. For ease of reference, the above table uses the S&P classifications to summarize risk, but reflects the lower of the two credit ratings.

2 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.

3 The exposure in this category relates to long-term power purchase agreements. SCE's exposure is mitigated by regulatory treatment.

### CRITICAL ACCOUNTING ESTIMATES AND POLICIES

For a discussion of SCE's critical accounting estimates and policies, see "Critical Accounting Estimates and Policies" in the year ended 2011 MD&A.

### NEW ACCOUNTING GUIDANCE

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

## Market risk

As filed, 142 characters.

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

## Controls and procedures

As filed, 1,119 characters.

### Disclosure Controls and Procedures

SCE's management, under the supervision and with the participation of the company's President and Chief Financial Officer, has evaluated the effectiveness of 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 (the "Exchange Act")) as of the end of the third quarter of

2012\. Based on that evaluation, the President and Chief Financial Officer concluded that, as of the end of the third quarter of 2012, SCE's disclosure controls and procedures were effective.

### Changes in Internal Control Over Financial Reporting

There were no changes in SCE's internal control over financial reporting (as that term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the third quarter of 2012 that have materially affected, or are reasonably likely to materially affect, SCE's internal control over financial reporting.

### Jointly Owned Utility Plant

SCE's scope of evaluation of internal control over financial reporting includes its Jointly Owned Utility Projects.

Filed Nov 1, 2012.
Source: SEC EDGAR, the filing index for accession 0000092103-12-000049. Last ingested by Listed: Nov 12, 2026, 15:04 ET. No prices; not investment advice.