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

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;
• 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;
• risks 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 six-month periods ended June 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 six-month periods ended June 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)

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 $20 million and $60 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. The revenue requirement ultimately adopted by the CPUC will be retroactive to January 1, 2012. SCE has incurred $29 million and $48 million of incremental steam generator inspection and repair costs related to outages at San Onofre for the quarter and year-to-date periods, respectively, which are currently being offset by other operation and maintenance cost reductions. The year-to-date variance also reflects a lower capitalization rate on funds used during construction.

2012 CPUC General Rate Case

As discussed in the year-ended 2011 MD&A, SCE filed its 2012 GRC application in November 2010. In October 2011, SCE submitted updated testimony, which changed SCE's requested 2012 base rate revenue requirement to $6.3 billion. The Division of Ratepayer Advocates, The Utility Reform Network and other intervenors recommended substantially less than the amount requested by SCE. Intervenors have also recommended changes to SCE's proposed post-test year ratemaking methodology to be used for 2013 and 2014 as well as limiting the recovery amount of SCE's pension costs. A decision on the GRC is expected in the second half of 2012. SCE is currently recognizing revenue largely based on the 2011 authorized revenue requirement, however, 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.

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 four 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. The schedule for the second phase is to be set by the end of 2012.

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 addition, SCE proposed reducing its current cost of capital as follows: cost of long-term debt from 6.22% to 5.53%, authorized cost of preferred equity from 6.01% to 5.86% and authorized return on common equity from 11.5% to 11.1%. SCE's application included a revenue requirement reduction estimate of $128 million for 2013. The application also requested the continuation of the current multi-year mechanism, which would have retained the authorized capital structure through 2015 subject to annual adjustments 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 remain off-line for ongoing, extensive inspections, testing and analysis of their steam generators, and will be restarted only when 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 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 high levels of unexpected wear in some tubes that were in contact with retainer bars of the tube support structure. As a result, all such tubes in contact with retainer bars in both Unit 2 steam generators were preventively removed from service through plugging. Subsequent inspections on Unit 3 found similar tube-to-support structure wear, and the Unit 3 tubes in contact with the retainer bars have also been plugged preventively. 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 preventively removed from service are within this margin.

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 is caused, at least in substantial part, by a phenomenon called fluid elastic instability which results from the interaction of a combination of factors, including steam velocity, moisture content of the steam, and effectiveness of the supports in the areas where the vibration occurs. A team of outside experts has been 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.

Any remedial action that will permit restart of one or both of the Units will need to address the interaction of factors giving rise to the fluid elastic instability. Until further actions are completed, including the NRC processes discussed below, the schedule to restart these Units cannot be determined. Because Unit 2 experienced considerably less tube-to-tube wear, it is currently anticipated that it could restart in advance of Unit 3; however, in order to do so, it is expected that pending further repairs and analysis, it would operate at reduced power levels and with mid-cycle scheduled outages to provide assurance of safe operation. 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, meaning that it would be less likely to restart this year. The current plan for Unit 3 is to de-fuel the reactor and place appropriate systems in a lay up condition while analysis and testing continue given the uncertain timing of the likely repairs and restart. SCE is engaged in the analysis of what repairs, if any, could be undertaken to restore the steam generators 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.

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.

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. On July 19, 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 thermal hydraulic code. The report further states that SCE is 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 regulatory action by the NRC, and the findings could be taken into consideration in the CPUC regulatory proceedings described below.

In March 2012, the NRC issued a Confirmatory Action Letter that required NRC permission to restart Unit 2 and Unit 3 and outlined actions SCE must complete before permission to restart either Unit may be sought. The NRC could also choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. SCE is continuing to evaluate repairs and mitigation plans. Each Unit will only be restarted when the repairs and appropriate mitigation plans for that Unit are completed in accordance with the NRC's letter, and SCE is satisfied that it is safe to do so. Should SCE seek NRC approval to restart a Unit, the NRC may employ other procedures, including holding one or more public meetings, before making any determination about whether to grant permission pursuant to the terms of the Confirmatory Action Letter. 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). There is no set or predetermined time period for such processes, and, accordingly, there can be no assurance about the length of time the NRC may take to review any request to restart submitted by SCE under the Confirmatory Action Letter or whether any such request would be granted in whole or in part.

CPUC Review

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 $593 million through June 30, 2012 on the steam generator replacement project. Those expenditures remain subject to CPUC reasonableness review upon submission of SCE's final costs for the overall project.

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 on behalf of customers (commencing on February 1 for Unit 3 and March 5 for Unit 2). Market costs through June 30, 2012 were approximately $117 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. Costs for power are likely to be higher during the summer months.

Through June 2012, SCE's share of incremental inspection and repair costs totaled $48 million for both Units. Subject to NRC review under the Confirmatory Action Letter and any new developments that may result from further analysis, testing and inspection, SCE's share of further incremental costs to commence start-up of Unit 2 at the reduced power levels described above are expected to be approximately $25 million, although there is no assurance that start-up of Unit 2 will occur as described above. SCE's estimated share of the 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's 2012 annual revenue requirement request for its direct operating and maintenance costs, depreciation and return on its investment in San Onofre Unit 2, Unit 3 and related common plant is approximately $650 million. At June 30, 2012, San Onofre rate base was $1.2 billion and the net investment and related inventory associated with San Onofre was $2.0 billion. Under California Public Utilities Code Section 455.5, SCE will be required to notify the CPUC if either of the San Onofre Units has been out of service for nine consecutive months, or November 2012 for Unit 3 and December 2012 for Unit 2 (not including preplanned outages). In that event, 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 all of the 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. Notwithstanding the requirements of Section 455.5, the CPUC may institute other proceedings relating to the impact of the extended outage at San Onofre and its potential effects on rates, and there is currently pending before the CPUC a proposal to initiate an Order Instituting Investigation regarding such impacts.

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 $137 million and excludes consequential damages, defined to include "the cost of replacement power." Such limitations in the contract are subject to applicable exceptions.

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 potentially 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. For further information, see "Southern California Edison Company 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.

Capital Program

During the first six 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 $1.73 billion during the first six months of 2012 compared to $1.6 billion during the same period in 2011. SCE expects that 2012 capital expenditures will be at or 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 resolution of the San Onofre issues. 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.

Environmental Developments

For a discussion of environmental developments, see "SCE Notes to Consolidated Financial Statements—Note 10. Environmental Developments."

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 six 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. 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 June 30, 2012 versus June 30, 2011

(in millions)

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

• Higher operating revenue of $28 million, primarily due to:
• $20 million increase primarily due to revenue related to authorized CPUC projects not included in SCE's GRC process including the EdisonSmartConnect® project and the Solar Photovoltaic project.
• Operations and maintenance expense reflects $29 million of costs related to the steam generator inspection and repair at San Onofre (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information) offset by EdisonSmartConnect® benefits realized and other cost savings and timing of expenses.
• Higher depreciation, decommissioning and amortization expense of $43 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs.
• Higher net interest expense and other of $14 million was primarily due to higher outstanding balances on long-term debt. For details of other income and expenses, see "SCE Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses."
• Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information.
• Higher preferred and preference stock dividends of $8 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 $151 million was primarily driven by $83 million of market costs net of lower nuclear fuel costs related to the outage at San Onofre in 2012 (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information). The increase was also due to 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). These increases were partially offset by lower power prices in 2012.
• Higher operations and maintenance expense of $21 million was primarily due to increased pension contributions partially offset by lower transmission access charges.

Six Months Ended June 30, 2012 versus June 30, 2011

(in millions)

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

Utility Earning Activities

Utility earning activities were primarily affected by the following:

• SCE had higher operating revenue of $79 million, primarily due to the following:
• $60 million increase was primarily due to revenue related to authorized CPUC projects not included in SCE's GRC process including the EdisonSmartConnect® project and the Solar Photovoltaic project.
• 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.
• Higher operation and maintenance expense of $43 million was primarily due to $48 million of costs related to the steam generator inspection and repair at San Onofre (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information) as well as $35 million related to the 2012 San Onofre Unit 2 scheduled maintenance and refueling outage. These increases were partially offset by EdisonSmartConnect® benefits realized and other cost savings and timing of expenses.
• Higher depreciation, decommissioning and amortization expense of $88 million was primarily related to increased generation, transmission and distribution investments, including capitalized software costs.
• Higher net interest expense and other of $29 million was primarily due to higher outstanding balances on long-term debt and a lower AFUDC capitalization rate in 2012 mainly driven by lower cost of financing resulting from an increase in the use of short-term debt. For details of other income and expenses, see "SCE Notes to Consolidated Financial Statements—Note 15. Other Income and Expenses."
• Lower income taxes due to lower pre-tax income. See "—Income Taxes" below for more information.
• Higher preferred and preference stock dividends of $12 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 $258 million was primarily driven by $117 million of market costs net of lower nuclear fuel costs related to the San Onofre outage in 2012 (see "Management Overview—San Onofre Outage, Inspection and Repair Issues" for further information). The increase was also due to 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). These increases were partially offset by lower power prices in 2012.
• Higher operation and maintenance expense of $43 million was primarily due to increased pension contributions partially offset by lower spending for public purpose programs.

Supplemental Operating Revenue Information

SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $2.7 billion and $5.0 billion for the three- and six-month periods ended June 30, 2012, respectively, compared to $2.4 billion and $4.5 billion for the respective periods in 2011. The increase in revenue reflects:

• A sales volume increase of $417 million and $701 million for the three- and six-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 $110 million and $211 million for the three- and six-month periods, respectively, resulting from a rate adjustment beginning on June 1, 2011, primarily reflecting the refund 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).

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)

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 June 30, 2012:

(in millions)

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 June 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 additional costs and delay the completion of the project. SCE is required to file revised cost estimates with the CPUC. 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. 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.

In June 2012, SCE provided its preliminary 2013 forecasted revenue requirement to interested parties. Consistent with SCE's proposed formula rate methodology, the application of the formula rate results in an increase in SCE's revenue requirement of $172 million, or 24%. The increase is primarily due to higher FERC rate base from transmission investments, including projects under construction. SCE expects to file its 2013 forecasted revenue requirement with the FERC by September 15, 2012, with the proposed rates effective from October 1, 2012 through September 30, 2013.

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 June 30, 2012, SCE's 13- month weighted-average common equity component of total capitalization was 49.4% resulting in the capacity to pay $261 million in additional dividends to Edison International.

During the first six months of 2012, SCE made $233 million in dividend payments to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the level of capital expenditures, operating cash flows and earnings.

Margin and Collateral Deposits

Certain derivative instruments, power procurement contracts and other contractual arrangements contain collateral requirements. Future collateral requirements may differ from the requirements at June 30, 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 June 30, 2012.

(in millions)

1 Collateral provided to counterparties and other brokers consisted of $66 million of cash which was offset against net derivative liabilities on the consolidated balance sheets, $25 million of cash reflected in "Other current assets" on the consolidated balance sheets and $63 million in letters of credit.

2 There would be no increase to SCE's total posted and potential collateral requirements based on SCE's forward positions as of June 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)

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased $126 million in the first six months of 2012 compared to the same period in 2011. The increase in cash flows provided by operating activities was primarily due to the timing of cash receipts and disbursements related to working capital items, partially offset by lower net tax receipts in 2012.

Net Cash Provided by Financing Activities

The following table summarizes cash provided by financing activities for the six months ended June 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)

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 $2.1 billion and $2.0 billion for the six months ended June 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 $125 million and $84 million for the six months ended June 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 June 30, 2012, SCE had identified 25 material sites for remediation and recorded an estimated minimum liability of $43 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 $865 million and $936 million at June 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 June 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)

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."

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

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 second quarter of 2012. Based on that evaluation, the President and Chief Financial Officer concluded that, as of the end of the second 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 second 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.