# SOUTHERN CALIFORNIA EDISON Co: Form 10-K for the period ended Dec 31, 2009

- Company: [SOUTHERN CALIFORNIA EDISON Co](/companies/sce-pg.md) (CIK 92103)
- Form: 10-K
- Filed: 2010-03-01
- Accepted by EDGAR: Mar 1, 2010, 09:09 ET
- Period: 2009-12-31
- Accession: 0001047469-10-001605
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/92103/000104746910001605/a2196050z10-k.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/92103/000104746910001605/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2009-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Operating income | 12 months, 2009-01-01 to 2009-12-31 | $1.92bn | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2009-01-01 to 2009-12-31 | $420.0m | us-gaap:InterestExpense |
| Income tax | 12 months, 2009-01-01 to 2009-12-31 | $249.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2009-01-01 to 2009-12-31 | $1.23bn | us-gaap:NetIncomeLoss |
| Operating cash flow | 12 months, 2009-01-01 to 2009-12-31 | $4.07bn | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 12 months, 2009-01-01 to 2009-12-31 | $3.00bn | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2009-12-31 | $462.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2009-12-31 | $2.33bn | us-gaap:AssetsCurrent |
| Total assets | at 2009-12-31 | $32.47bn | us-gaap:Assets |
| Current liabilities | at 2009-12-31 | $3.05bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2009-12-31 | $23.76bn | us-gaap:Liabilities |
| Long-term debt | at 2009-12-31 | $6.49bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2009-12-31 | $250.0m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2009-12-31 | $8.71bn | us-gaap:StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest |

## Business

As filed, 55,875 characters.

SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to a 50,000-square-mile area of central, coastal and southern California, excluding the City of Los Angeles and certain other cities. This SCE service territory includes over 400 cities and communities with a collective population of more than 13 million people. In 2009, SCE's total operating revenue was derived as follows: 42% commercial customers, 39% residential customers, 6% industrial customers, 2% resale sales, 6% public authorities, and 5% agricultural and other customers. SCE had 17,348 full-time employees at December 31, 2009.

SCE makes available, free of charge on *www.edisoninvestor.com*, its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after SCE electronically files such material with, or furnishes it to, the SEC. Such reports are also available on the SEC's internet website, *www.sec.gov*. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.

### Financial Information About Geographic Areas

All of SCE's revenue for the last three fiscal years is attributed to SCE's country of domicile, the United States. All of SCE's assets are located in the United States.

### Regulation

### CPUC

SCE's retail operations are subject to regulation by the California Public Utilities Commission ("CPUC"). The CPUC has the authority to regulate, among other things, retail rates, energy purchases on behalf of retail customers, rate of return, rates of depreciation, issuance of securities, disposition of utility assets and facilities, oversight of nuclear decommissioning, and aspects of the construction, planning and project site identification of the electricity transmission system.

#### Resource Adequacy Requirements

The CPUC has established resource adequacy requirements, which require SCE to procure adequate electricity to meet its expected customer needs on both a system-wide and a local basis. SCE would be subject to penalties if it failed to meet the requirements. SCE complied with the resource adequacy requirements in 2009 and expects to comply in 2010.

#### Procurement of Renewable Resources

California law requires SCE to increase its procurement of energy from renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010. Under the

CPUC's current rules, the maximum penalty for inability to achieve renewable procurement targets is $25 million per year. SCE's ability to meet the RPS target depends largely on the ability of third parties to meet contractual obligations to deliver power to SCE. Flexible compliance rules, such as banking of past surplus and earmarking of future deliveries from executed contracts, are also available. SCE does not believe it will be assessed penalties for 2009 or the prior years and cannot predict whether it will be assessed penalties for future years.

### FERC

SCE's wholesale operations (including sales of electricity into the wholesale markets) are subject to regulation by the Federal Energy Regulatory Commission ("FERC"). The FERC has the authority to regulate wholesale rates as well as other matters, including unbundled transmission service pricing, accounting practices, and licensing of hydroelectric projects.

#### Reliability Standards

On July 20, 2006, the FERC certified the North American Electric Reliability Corporation ("NERC") as its Electric Reliability Organization to establish and enforce reliability standards for the bulk power system. Compliance with these standards became mandatory on June 18, 2007. SCE believes it has taken appropriate steps to be compliant with current NERC reliability standards that apply to its operations.

### CEC

The construction, planning, and project site identification of SCE's power plants within California are subject to the jurisdiction of the California Energy Commission ("CEC") (for plants 50 MW or greater). The CEC is responsible for forecasting future energy needs. These forecasts are used by the CPUC in determining the adequacy of SCE's electricity procurement plans. California law prohibits the CEC from siting or permitting a new nuclear power plant in California until it finds a federally approved and demonstrated method for the disposal of nuclear waste.

### Nuclear Power Plant Regulation

SCE is subject to the jurisdiction of the U.S. Nuclear Regulatory Commission ("NRC") with respect to San Onofre and Palo Verde Nuclear Generating Stations. NRC requirements govern the granting, amendment, and extension of licenses for the construction and operation of nuclear power plants and subject those power plants to continuing oversight, inspection, and performance assessment with respect to plant operation and related activities.

San Onofre is currently addressing a number of regulatory and performance issues. The NRC is requiring SCE to take actions to provide greater assurance of compliance by San Onofre personnel with applicable NRC requirements and procedures. SCE is currently implementing plans to address the identified issues. The NRC has continued to affirm that San Onofre has been operated and is being operated safely; however, the cumulative impact of these regulatory and performance issues is an increase in management focus and other resources applied at San Onofre.

Information about nuclear decommissioning can be found in "Item 8. SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies and Note 6. Commitments and Contingencies." Information about nuclear insurance can be found in "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies."

### Transmission and Substation Facilities Regulation

The construction, planning and project site identification of SCE's transmission lines and substation facilities require the approval of many governmental agencies and compliance with various laws. These agencies include utility regulatory commissions such as the CPUC and other state regulatory agencies depending on the project location; the Independent System Operator ("ISO"), and other environmental, land management and resource agencies such as the Bureau of Land Management, the U.S. Forest Service, and the California Department of Fish and Game; and Regional Water Quality Control Boards. In addition, to the extent that SCE transmission line projects pass through lands owned or controlled by Native American tribes, consent and approval from the affected tribes and the Bureau of Indian Affairs will also be necessary for the project to proceed.

### Relationship with Certain Affiliated Companies

SCE is subject to CPUC affiliate transaction rules and compliance plans governing the relationship between SCE and its affiliates.

### Overview of Ratemaking Mechanisms

SCE sells electricity to retail customers at rates authorized by the CPUC. SCE sells transmission service and wholesale power at rates authorized by the FERC.

### Base Rates

Base rates authorized by the CPUC and the FERC are intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution facilities (or "rate base"). These base rates provide for recovery of operations and maintenance costs, capital-related carrying costs (depreciation, taxes and interest) and a return or profit, on a forecast basis.

#### CPUC Base Rates

Base rates for SCE's generation and distribution functions are authorized by the CPUC through triennial General Rate Case ("GRC") proceedings. The CPUC sets an annual revenue requirement for the base year which is made up of the carrying cost on capital investment (depreciation, return and taxes), plus the authorized level of operation and maintenance expense. The return is established by multiplying an authorized rate of return, determined in the separate cost of capital proceedings (as discussed below), by the generation and distribution rate base. In the GRC proceedings, the CPUC also approves capital spending on a forecast basis. Adjustments to the revenue requirement for the remaining two years of a typical three-year GRC cycle are requested, based on criteria established in the GRC proceeding, which generally include annual allowances for escalation in operation and maintenance costs, forecasted changes in capital-related investments and the timing and number of expected nuclear refueling outages. SCE's most recent GRC decision for the 2009-2011 period was issued in March 2009 and was effective as of January 1, 2009. SCE expects to begin proceedings for the 2012 GRC in the third quarter of 2010. As part of the GRC, the CPUC has authorized a revenue decoupling mechanism, which allows for the difference between the revenue authorized and the actual volume of electricity sales to be collected from or refunded to ratepayers. Accordingly, SCE does not bear the volumetric risk related to electricity sales.

The CPUC regulates SCE's capital structure and authorized rate of return. SCE's current authorized capital structure is 48% common equity, 43% long-term debt and 9% preferred equity. SCE's current authorized cost of capital consists of: cost of long-term debt of 6.22%, authorized cost of preferred equity of 6.01% and authorized return on common equity of 11.5%. In 2008, the CPUC approved a multi-year cost of capital mechanism, which allows for annual adjustments if certain thresholds are reached. SCE's earnings may be impacted when actual financing costs are above or below its authorized costs for long-term debt and preferred equity financings.

#### FERC Base Rates

Base rates for SCE's transmission functions provide a rate of return and are authorized by the FERC, in periodic proceedings that are similar to the CPUC GRC proceeding. Requested rate changes at the FERC are generally implemented before final approval of the application, with revenue collected prior to a final FERC decision being subject to refund. FERC-approved base rate revenues that vary from forecast are not subject to balancing account mechanisms or otherwise recoverable or refundable and therefore will impact earnings.

### Cost-Recovery Rates

Cost-recovery mechanisms allow SCE to recover its costs, but do not allow a return or profit. These mechanisms are used to recover SCE's costs of fuel, purchased-power, demand-side management programs, nuclear decommissioning, public purpose programs, certain operation and maintenance expenses, and depreciation expense related to certain projects. Although the CPUC authorizes balancing account mechanisms for such costs to refund or recover any differences between forecasted and actual costs, under- or over-collections in these balancing accounts do impact cash flows and can build rapidly.

The CPUC also uses a mechanism known as a "balancing account" to eliminate the effect on earnings that differences in revenue resulting from actual and forecast electricity sales may have. Under this mechanism, the difference in revenue between the actual and the forecast electricity sales is recovered from or refunded to ratepayers and therefore does not impact SCE's earnings.

SCE's balancing account for fuel and power procurement-related costs is established under the Energy Resource Recovery Account ("ERRA") Mechanism. SCE files annual forecasts of the costs that it expects to incur during the following year and sets rates using forecasts. The CPUC has established a "trigger" mechanism for the ERRA balancing account that allows for a rate adjustment if the balancing account over-collection or under-collection exceeds 5% of SCE's prior year's generation revenue.

The majority of costs eligible for recovery through cost-recovery rates are subject to CPUC reasonableness reviews, and thus could negatively impact earnings and cash flows if found to be unreasonable and disallowed.

### Energy Efficiency Shareholder Risk/Reward Incentive Mechanism

The CPUC has adopted an Energy Efficiency Risk/Reward Incentive Mechanism, which allows for both financial incentives and economic penalties based on SCE's performance toward meeting goals set for it by the CPUC for energy efficiency. Under this mechanism, SCE has the opportunity to earn an incentive if it achieves 85% or more of its energy efficiency goals for the three year period. Economic penalties would be imposed in the event SCE achieves less than 65% of its goals. The mechanism allows for two annual progress payments, subject to holdback percentages, for progress towards meeting the goals and a third payment for final performance on the goals, which includes the payment of any holdbacks. SCE may retain the first and second progress payments as long as it meets a minimum of 65% of the goals. If SCE does not meet the 65% level, the amount of the progress payments and economic penalties would be deducted from future incentive payments. Both incentives and economic penalties for each three-year period are capped at $200 million.

In January 2009, the CPUC issued a new rulemaking intended to review the framework of the Energy Efficiency Risk/Reward Incentive Mechanism. The CPUC has yet to release a Decision on a new framework.

### CDWR-Related Rates

As a result of the California energy crisis, in 2001 the California Department of Water Resources ("CDWR") entered into contracts to purchase power for sale at cost directly to SCE's retail customers and issued bonds to finance those power purchases. The CDWR's total statewide power charge and bond charge revenue requirements are allocated by the CPUC among the customers of the Investor-Owned Utilities. SCE bills and collects from its customers the costs of power purchased and sold by the CDWR, CDWR bond-related charges and direct access exit fees. The CDWR-related charges and a portion of direct access exit fees that are remitted directly to the CDWR are not recognized as electric utility revenue by SCE and therefore have no impact on SCE's earnings; however, they do impact customer rates.

### Competition

Because SCE is an electric utility company operating within a defined service territory pursuant to authority from the CPUC, SCE faces competition only to the extent that federal and California laws permit other entities to provide electricity and related services to customers within SCE's service territory. While California law provides only limited opportunities for customers to choose to purchase power directly from an energy service provider other than SCE, a California law was adopted in 2009 that permits a limited, phased-in expansion of customer choice (direct access) for nonresidential customers. SCE also faces some competition from cities and municipal districts that create municipal utilities or community choice aggregators. In addition, customers may install their own on-site power generation facilities.

Competition with SCE is conducted mainly on the basis of price, as customers seek the lowest cost power available. The effect of competition on SCE generally is to reduce the number of customers purchasing power from SCE, but those customers typically continue to utilize and pay for SCE's transmission and distribution services.

In the area of transmission infrastructure, SCE may experience increased competition from merchant transmission providers.

### Purchased Power and Fuel Supply

SCE obtains the power needed to serve its customers from its generating facilities and from purchases from qualifying facilities ("QFs"), independent power producers, renewable power producers, the CAISO, and other utilities. In addition, power is provided to SCE's customers through purchases by the CDWR under contracts with third parties. Sources of power to serve SCE's customers during 2009 were approximately: 44% purchased power; 23% CDWR; and 33% SCE-owned generation.

### Natural Gas Supply

SCE requires natural gas to meet contractual obligations for power tolling agreements (power contracts in which SCE has agreed to provide the natural gas needed for generation under those power contracts) and to serve demand for gas at Mountainview and SCE's peaker plants, which are supplemental plants that only operate when demand for power is high. All of the physical gas purchased by SCE in 2009 was purchased through competitive bidding.

### Nuclear Fuel Supply

For San Onofre Units 2 and 3, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below:

|  |  |
| --- | --- |
| Uranium concentrates | 2020 |
| Conversion | 2020 |
| Enrichment | 2020 |
| Fabrication | 2015 |

For Palo Verde, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below:

|  |  |
| --- | --- |
| Uranium concentrates | 2011 |
| Conversion | 2010 |
| Enrichment | 2013 |
| Fabrication | 2016 |

### Spent Nuclear Fuel

Information about Spent Nuclear Fuel appears in "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies."

### Coal Supply

On January 1, 2005, SCE and the other Four Corners participants entered into a Restated and Amended Four Corners Fuel Agreement with the BHP Navajo Coal Company, under which coal will be supplied to Four Corners Units 4 and 5 until July 6, 2016. The Restated and Amended Agreement contains an option to extend for not less than five additional years or more than 15 years.

### CAISO Wholesale Energy Market

In California and other states, wholesale energy markets exist through which competing electricity generators offer their electricity output to electricity retailers. Each state's wholesale electricity market is generally operated by its state ISO or a regional RTO. California's wholesale electricity market is operated by the CAISO. In 2006, the California Independent System Operator ("CAISO") began its Market Redesign and Technology Upgrade ("MRTU") program to redesign and upgrade the wholesale energy market across its controlled grid. The MRTU market design allows the CAISO to schedule power in hourly increments with hourly prices through a real-time and day-ahead market that combines energy, ancillary services, unit commitment and congestion management. These MRTU features became effective in March 2009 and SCE began participating in the day-ahead and real-time markets for the sale of its generation and purchases of its load requirements.

The MRTU structure uses a nodal locational pricing model, which sets wholesale electricity prices at 3,000 different system points (nodes) that reflect local generation and delivery costs, as opposed to the previous system of three broad zonal prices. Generally, SCE schedules its electricity generation assets to serve its load but when it has excess generation or the market price of power is more economic than its own generation, SCE may sell power from utility-owned generation assets and existing power procurement contracts on, or buy generation and/or ancillary services to meet its load requirements from, the IFM. SCE will offer to buy its generation at nodes near the source of the generation, but will take delivery at nodes throughout SCE's service territory. Congestion may occur when available energy cannot be delivered to all loads due to transmission constraints capacity, which results in transmission congestion charges and differences in prices at various nodes. The CAISO also offers congestion revenue rights or CRRs, a commodity that entitles the holder to receive (or pay) the value of transmission congestion between specific nodes, acting as an economic hedge against transmission congestion charges.

### Properties

SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, which are located primarily in California but also in Nevada and Arizona, deliver power from generating sources to the distribution network and consist of 33 kV, 55 kV, 66 kV, 115 kV, and 161 kV lines; 220 kV and 500 kV lines; and 893 substations. SCE's distribution system, which takes power from substations to customers, includes over 70,000 circuit miles of overhead lines, 43,500 circuit miles of underground lines, 1.46 million poles, over 720 distribution substations, approximately 715,600 transformers, and 813,000 area lights and streetlights, all of which are located in California.

SCE owns the following generating facilities (and operates all of these facilities except Palo Verde and Four Corners, which are operated by Arizona Public Service Company ("APS")):

| Generating Facility | Location CA, unless otherwise noted | Fuel Type | SCE's Ownership Interest (%) | Net Physical Capacity (in MW) | SCE's Capacity pro rata share (in MW) |
| --- | --- | --- | ---: | ---: | ---: |
| San Onofre Nuclear Generating Station | South San Clemente | Nuclear | 78.21% | 2,150 | 1,760 |
| Hydroelectric Plants (36) | Various | Hydroelectric | 100% | 1,176 | 1,176 |
| Pebbly Beach Generating Station | Catalina Island | Diesel | 100% | 9 | 9 |
| Mountainview | Redlands | Natural Gas | 100% | 1,050 | 1,050 |
| Center Peaker | Norwalk | Gas fueled Combustion Turbine | 100% | 49 | 49 |
| Mira Loma Peaker | Ontario | Gas fueled Combustion Turbine | 100% | 49 | 49 |
| Grapeland Peaker | Rancho Cucamonga | Gas fueled Combustion Turbine | 100% | 49 | 49 |
| Barre Peaker | Stanton | Gas fueled Combustion Turbine | 100% | 49 | 49 |
| Palo Verde Nuclear Generating Station | Phoenix, AZ | Nuclear | 15.8% | 3,739 | 591 |
| Four Corners Units 4 and 5 | Farmington, NM | Coal-fired | 48% | 1,500 | 720 |
| Total |  |  |  | 9,820 | 5,502 |

San Onofre, Four Corners, certain of SCE's substations, and portions of its transmission, distribution and communication systems are located on lands owned by the United States or others under licenses, permits, easements or leases, or on public streets or highways pursuant to franchises. Certain of the documents evidencing such rights obligate SCE, under specified circumstances and at its expense, to relocate such transmission, distribution, and communication facilities located on lands owned or controlled by federal, state, or local governments.

Thirty-one of SCE's 36 hydroelectric plants (some with related reservoirs) are located in whole or in part on U.S.-owned lands pursuant to 30- to 50-year FERC licenses that expire at various times between 2010 and 2040. Such licenses impose numerous restrictions and obligations on SCE, including the right of the United States to acquire projects upon payment of specified compensation. When existing licenses expire, the FERC has the authority to issue new licenses to third parties that have filed competing license applications, but only if their license application is superior to SCE's and then only upon payment of specified compensation to SCE. New licenses issued to SCE are expected to contain more restrictions and obligations than the expired licenses because laws enacted since the existing licenses were issued require the FERC to give environmental objectives greater consideration in the licensing process.

Substantially all of SCE's properties are subject to the lien of a trust indenture securing first and refunding mortgage bonds, of which approximately $6.40 billion in principal amount was outstanding on February 26, 2010.

SCE's rights in Four Corners, which is located on land of the Navajo Nation under an easement from the United States and a lease from the Navajo Nation, may be subject to possible defects. These defects include possible conflicting grants or encumbrances not ascertainable because of the absence of, or inadequacies in, the applicable recording law and record systems of the Bureau of Indian Affairs and the Navajo Nation, the possible inability of SCE to resort to legal process to enforce its rights against the Navajo Nation without Congressional consent, the possible impairment or termination under certain circumstances of the easement and lease by the Navajo Nation, Congress, or the Secretary of the Interior, and the possible invalidity of the trust indenture lien against SCE's interest in the easement, lease, and improvements on Four Corners.

### Insurance

SCE has property and casualty insurance policies, which include excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations.

Severe wildfires in California have given rise to large damage claims against California utilities. Additionally, California law includes a doctrine of inverse condemnation that imposes strict liability (including liability for a claimant's attorneys' fees) for fire damage caused to private property by a utility's electric facilities that serve the public. These damage claims and the related doctrine may affect SCE's liability insurance levels and cost. On September 1, 2009, SCE renewed its insurance coverage, which included coverage for wildfire liabilities up to a reduced limit of $500 million (with an increased self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in substantially higher self-insured costs in the event of multiple wildfire occurrences during the policy period (September 1, 2009 to August 31, 2010). SCE may experience further coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.

### Seasonality

For a discussion of seasonality of SCE's revenues, see "Electric Utility Results of Operations—Supplemental Operating Revenue Information" in the MD&A.

### Environmental Matters

SCE is subject to environmental regulation by federal, state and local authorities in the jurisdictions in which it operates. This regulation, including in the areas of air and water pollution, waste management, hazardous chemical use, noise abatement, land use, aesthetics, nuclear control and climate change, continues to result in the imposition of numerous restrictions on SCE's operation of existing facilities, on the timing, cost, location, design, construction, and operation by SCE of new facilities, and on the cost of mitigating the effect of past operations on the environment.

SCE's projected environmental capital expenditures and additional information about environmental matters affecting SCE appear in the MD&A under the heading "Liquidity and Capital Resources—Capital Investment Plan" and in "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Environmental Remediation."

### Climate Change

There have been a number of efforts at both the federal and state legislative and regulatory levels to adopt or enact regulations to reduce green house gas emissions. Any climate change regulation or other legal obligation that would require substantial reductions in emissions of greenhouse gases or that would impose additional costs or charges for the emission of greenhouse gases could significantly increase the cost of generating electricity from fossil fuels, especially coal, as well as the cost of purchased power, which could adversely affect SCE's business.

#### Federal Legislative/Regulatory Developments

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act. The bill, which was endorsed by SCE's parent company, Edison International, would establish a cap-and-trade system for greenhouse gas emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate greenhouse gas emissions from all covered entities would be established and decline over time. Emitters of greenhouse gases would be required to have allowances for their greenhouse gas emissions during a relevant measurement period. The bill would provide for stated portions of required allowances to be allocated free of charge in declining amounts over time. Emitters of greenhouse gases would have to purchase the remainder of their required allowances in the open market, although a portion may be provided by so-called offset credits (for alternative greenhouse gas emission reduction efforts). Similar legislation was introduced in the U.S. Senate in September 2009. SCE cannot predict whether legislation imposing limits on greenhouse gas emissions in the U.S. will be passed in 2010 and the timing, content and potential effects on SCE of any legislation that may be enacted remain uncertain.

Even if Congress does not pass legislation mandating greenhouse gas emissions reductions, regulatory developments under the Clean Air Act ("CAA") may also result in greenhouse gas emissions requirements that could affect SCE. In April 2007, the U.S. Supreme Court held, in *Massachusetts, et al v. Environmental Protection Agency*, that greenhouse gases are "air pollutants" under the CAA and that that the US EPA has a duty to determine whether greenhouse gas emissions from new motor vehicles contribute to climate change or offer a reasoned explanation for its failure to make such a determination. In response to this decision, in December 2009, the US EPA issued a finding that certain greenhouse gases, including carbon dioxide, endanger the public health and welfare, which enables the US EPA to establish greenhouse gas emissions limits for new light-duty vehicles. It is expected that the US EPA will issue the final light-duty vehicle emissions limits in March 2010.

The December 2009 endangerment finding will trigger future regulation of stationary sources of greenhouse gases, such as power plants, which the US EPA plans to phase in beginning in 2011. In addition, when the regulation of greenhouse gases from light-duty vehicles is finalized, greenhouse gas emissions will become subject to review under the CAA's Prevention of Significant Deterioration ("PSD") (construction or modification of major sources) permit program. Sources subject to a PSD review for greenhouse gases would be required to use best available control technology ("BACT") to control greenhouse gas emissions. Because carbon dioxide is emitted in greater quantities than other CAA-regulated pollutants, regulating it under the PSD Program would cover a large number of sources. To avoid the regulatory and enforcement consequences of such an outcome, in November 2009 the US EPA proposed a regulation, known as the "greenhouse gas tailoring rule." The greenhouse gas tailoring rule would redefine the PSD program to increase the threshold emission limit of carbon dioxide equivalents in a year from 250 tons to 25,000 metric tons. Whether or not this regulation is finalized, it is likely that SCE's fossil-fueled generating facilities would be major sources for purposes of the PSD programs. However, because the current PSD proposal affects only new or modified sources, it is not expected to have an immediate effect on SCE's existing generating plants. If SCE is required to install pollution controls in the future or otherwise modify its operations in order to reduce carbon dioxide emissions, the impact will depend on the nature and timing of the controls to be applied, both of which remain uncertain. SCE does not believe that currently there are commercially and technically feasible, full scale methods to control greenhouse gas emissions from its existing fossil-fueled generating facilities.

#### State Legislative/Regulatory Developments

California has enacted two laws regarding greenhouse gas emissions. The first law, the California Global Warming Solutions Act of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce greenhouse gas emissions. AB 32 requires the California Air Resources Board ("CARB") to develop regulations, potentially including market-based compliance mechanisms, to reduce California's greenhouse gas emissions to 1990 levels by 2020. The CARB's mandatory program will commence in 2012 and will implement incremental reductions aimed at reducing greenhouse gas emissions to 1990 levels by 2020. The CARB has released preliminary draft regulations establishing a California cap-and-trade program, which include revisions to the CARB's mandatory greenhouse gas emissions reporting regulation and are expected to be finalized by the CARB in October 2010.

The second law, SB 1368, required the CPUC and the California Energy Commission ("CEC") to adopt greenhouse gas emission performance standards that restrict the ability of investor owned and publicly owned utilities, respectively to enter into long-term arrangements for the purchase of electricity. These standards must equal the performance of a combined-cycle gas turbine generator. The standards that have been adopted prohibit California load-serving entities, including SCE, from entering into long-term financial commitments with generators that emit more than 1,100 pounds of CO2 per MWh, which includes most coal-fired plants. SB 1368 also affects the ability of utilities to make long-term capital investments in generators that do not meet the emission performance standards. SB 1368 may prohibit SCE from making emission control expenditures at Four Corners.

California law also requires SCE to increase its procurement of electricity generated from renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from such resources by no later than December 31, 2010 or such later date as flexible compliance requirements permit. In addition, in September 2009, Governor Schwarzenegger issued an executive order directing the CARB to adopt a regulation consistent with 33% of retail sellers' annual electricity sales being obtained from renewable energy sources by 2020. The executive order provides that the regulation may accelerate or expand the timeframe for compliance as well as increase the targeted percentage of annual electricity sales to be obtained from renewable resources, based on a thorough assessment of relevant factors.

#### Regional Initiatives

There are a number of regional initiatives relating to greenhouse gas emissions. Implementing regulations for such regional initiatives are likely to vary from state to state and may be more stringent and costly than federal legislative proposals currently being debated in Congress. It cannot yet be determined whether or to what extent any federal legislation would preempt regional or state initiatives, since these initiatives are in varying stages of development and implementation, although such preemption could simplify compliance by reducing regulatory duplication. If state and/or regional initiatives remain in effect after federal legislation is enacted, generators could be required to satisfy them in addition to federal standards.

Arizona, California, Montana, New Mexico, Oregon, Utah, Washington, and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec launched the Western Climate Initiative to develop strategies to reduce greenhouse gas emissions in the region to 15% below 2005 levels by 2020. In September 2008, the partners released recommendations for the regional cap-and-trade program to help achieve that reduction goal. In February 2010, Arizona gave notice that it would not take part in the Western Climate Initiative's cap-and-trade program.

#### Litigation Developments

In 2009, three courts issued decisions in cases involving the question of whether emissions of greenhouse gases from power plants and other large sources could constitute a public nuisance, making the sources potentially liable for damages or other remedies.

In October 2009, a California federal district court dismissed the complaint that had been filed by a native Alaskan village and the Kivalina Tribe in February 2008 against 24 defendants, including Edison International, who directly or indirectly engaged in the electric generating, oil and gas, or coal mining lines of business. Plaintiffs had alleged greenhouse gas emissions from the defendants' business activities contributed to global warming impacts that are melting the Arctic sea ice that protects the village from winter storms and that the village would soon need to be abandoned or relocated at a cost of between $95 million and $400 million. The court dismissed the plaintiffs' federal nuisance claims stating that they were inappropriate for judicial resolution because they required policy choices that were reserved to the legislative or executive branches of the government (the "political question doctrine"). The court also held that the plaintiffs did not have standing under federal law to bring the case, in part because of the lack of connection between the defendants' conduct and the harm that plaintiffs alleged was occurring. The court also dismissed plaintiffs' state law nuisance claims, but without prejudice to those claims being re-filed in state court. The plaintiffs have appealed the dismissal order to the Ninth Circuit Court of Appeals.

In contrast to the district court decision in Kivalina, the U.S. Court of Appeals for the Second Circuit, in September 2009, and the U.S. Court of Appeals for the Fifth Circuit, in October 2009, reversed and remanded lower court decisions that had dismissed complaints (filed in New York and Mississippi, respectively), against electric utilities and others, for injunctive relief and/or damages allegedly arising as a result of greenhouse gas emissions. These courts held that plaintiffs had standing and that their claims (sounding in various common law theories, including public nuisance in the New York case and public nuisance, private nuisance, trespass and negligence in the Mississippi case) were not barred by the political question doctrine. Neither Edison International nor its subsidiaries was named as a defendant in the New York case. At the time the action was dismissed by the court in Mississippi, the plaintiffs were seeking to amend their complaint to include Edison International and several affiliates of Edison International, including SCE, as defendants.

Each of these differing rulings remains subject to appeal, rehearing, or potential review by the U.S. Supreme Court, and thus the ultimate impact of these cases remains uncertain. In addition, SCE cannot predict whether the appellate decisions will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts for these sorts of claims.

#### Emissions Data Reporting

SCE's independently certified greenhouse gas emission data for 2007, as reported to the California Climate Action Registry, showed that SCE emitted approximately 6.8 million metric tons from SCE-owned generation. SCE's reported emissions are pro-rated to its ownership interests in the emitting facilities. Beginning with 2008 data, SCE will be reporting to TCR (as described below) and to the CARB. SCE will begin reporting 2010 data to the US EPA in 2011. SCE reported 2008 greenhouse gas emission data to the CARB in June 2009. The CARB reporting is done in three parts: greenhouse gas emissions from SCE-owned generation, sulfur hexafluoride (SF6) emissions from SCE-owned or -operated equipment, and transaction reporting of MWhs purchased and resource types (from which the CARB calculates total greenhouse gas emissions). The CARB has not yet published its calculations on SCE's 2008 data.

Edison International, SCE's parent holding company, became a founding reporter to TCR, formed in May 2008. The Climate Registry "(TCR") is a multi-national organization, which allows organizations to voluntarily inventory, verify, and publicly report their greenhouse gas emissions. As part of Edison International's reporting, SCE filed initial emissions data for 2008 in September 2009 with TCR. This information did not cover all of SCE-owned generation, as allowed under the TCR transitional reporter rules that apply for the first two years that an entity reports its emissions with TCR. Verified emissions data for Edison International, including data for SCE, are expected to be released publicly by TCR at the end of the second quarter of 2010.

In September 2009, the US EPA issued its Final Mandatory Greenhouse Gas Reporting Rule, which requires all energy sources within specified categories, including electric generation facilities, to begin monitoring GHG emissions in January 2010, and to submit annual reports to the US EPA by March 31 of each year, with the first report due on March 31, 2011.

#### Responses to Energy Demands and Future Greenhouse Gas Emission Constraints

Irrespective of the outcome of current federal or state legislative deliberations, SCE believes that regulation of greenhouse gas emissions is likely to develop, through increased costs, mandatory emission limits or other mechanisms, and that demand for energy from renewable sources will also continue to increase. As a result, SCE is creating a generation profile, from wind, solar, geothermal, biomass and small hydro plants, that will be adaptable to a variety of regulatory and energy use environments. Its renewables portfolio of owned and procured sources currently consists of: 1,583 MW from wind, 956 MW from geothermal, 360 MW from solar, 178 MW from biomass, and 200 MW from small hydro.

SCE has developed and promoted several energy efficiency and demand response initiatives in the residential market, including an ongoing meter replacement program to help reduce peak energy demand; a rebate program to encourage customers to invest in more efficient appliances; subsidies for purchases of energy efficient lighting products; appliance recycling programs; widely publicized tips to customers for saving energy; and a voluntary demand response which offers customers financial incentives to reduce their electricity use. SCE is also replacing its electro-mechanical grid control systems with computerized devices that allow more effective grid management.

#### Corporate Governance Processes

SCE's Board of Directors regularly receives reports regarding environmental issues that affect SCE, including climate change issues.

### Air Quality

The CAA establishes a comprehensive program to protect and improve the nation's air quality by regulating certain air emissions from mobile and stationary sources. The states implement and administer many of these programs and may impose additional or more stringent requirements under the CAA scheme. The federal CAA, state clean air acts, and federal and state regulations implementing such statutes apply to plants owned by SCE, as well as to plants from which SCE may purchase power, but have their largest impact on the operation of coal-fired plants. The federal environmental regulations require states to adopt implementation plans for certain pollutants, known as SIPs, which are equal to or more stringent than the federal requirements. These plans detail how the state will attain the standards that are mandated by the relevant law or regulation.

The CAA requires the US EPA to review the available scientific data for six criteria pollutants and establish a concentration level in the ambient air for those substances that is adequate to protect public health and welfare. These concentration levels are known as national ambient air quality standards, or NAAQS. The six criteria pollutants are carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and sulfur dioxide.

Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas), and must develop a SIP both to bring non-attainment areas into compliance with the NAAQS and to maintain good air quality in attainment areas. All SIPs are submitted to the US EPA for approval. If a state fails to develop adequate plans, the US EPA will develop and implement a plan. The attainment status of areas can change, and states may be required to develop new SIPs that address these changes. Many of SCE's facilities are located in counties that have not attained NAAQS for ozone and fine particulate matter. NOx emissions from power plants impact ambient air ozone levels and SO2 emissions from power plants impact ambient air fine particulate matter levels.

#### Nitrogen Oxide and Sulfur Dioxide

Proposed NAAQS for Sulfur Dioxide

In November 2009, the US EPA proposed a new 1-hour NAAQS for SO2. The new standard is proposed to be between 50 and 100 parts per billion. The US EPA is required by a consent decree to take final action by June 2, 2010. The proposed rule would require states to submit SIPs in 2014, with compliance by 2017.

#### Mercury – Clean Air Mercury Rule

Until new federal standards are developed to replace the CAMR, SCE will not be able to determine whether it will be necessary to undertake mercury emission control measures beyond those required by state regulations. The CAMR was established by the US EPA as an attempt to reduce mercury emissions from existing coal-fired power plants using a cap-and-trade program. SCE's coal-fired electric generating facility (SCE currently has a 48% ownership interest in Units 4 and 5 of Four Corners) emit mercury and other regulated emissions. As a result of the decision by the U.S. Court of Appeals for the D.C. Circuit in February 2007 that rejected both the CAMR and the related decision by the US EPA to remove oil- and coal-fired plants from the list of sources to be regulated under Section 112 of the CAA, until CAMR is replaced by a new mercury rule, mercury regulation will come from state regulatory bodies.

#### Ozone and Particulates

National Ambient Air Quality Standards

In September 2006, the US EPA issued a final rule that would significantly reduce the 24-hour fine particulate standard (from 65 ug/m3 to 35 ug/m3), but in February 2009, the U.S. Court of Appeals for the D.C. Circuit remanded the annual fine particulate matter standard to the US EPA for further review.

#### Regional Haze

The regional haze rules under the CAA are designed to prevent impairment of visibility in certain federally designated areas. The goal of the rules is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions by 2064. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install BART or implement other control strategies to meet regional haze control requirements. The US EPA issued a final rulemaking on regional haze in 2005 requiring emission controls that constitute BART for industrial facilities that emit air pollutants which reduce visibility by causing or contributing to regional haze. These amendments required states to develop implementation plans to comply with BART by December 2007, to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions, and then to set BART emissions limits for those facilities. Failure to do so results in a federal implementation plan.

In relation to Four Corners, the US EPA requested that APS perform a regional haze BART analysis for Four Corners. The US EPA responded to APS' analysis, which proposed the installation of certain combustion control equipment, by issuing an advanced notice of proposed rulemaking that implied that post-combustion controls in the form of selective catalytic reduction (SCR) pollution control equipment would be BART for Four Corners. A final EPA determination on this matter is expected in late 2010. Until the final determination is issued, SCE cannot predict what pollution control equipment will be required at Four Corners and thus cannot accurately estimate the expenditures that would be necessary for such equipment. In any case, due to the investment constraints of SB 1368, the California law on greenhouse gas emission performance standards discussed above in "—Climate Change—State Legislative/Regulatory Developments," SCE does not expect to be able to participate in any investment in SCR post-combustion controls or combustion controls at Four Corners. SCE thus does not expect to enter into any long-term ownership arrangements for its share of Four Corners Units 4 and 5 after the 2016 expiration of the current participant agreements due to the investment constraints of SB 1368.

#### New Source Review Requirements ("NSR")

The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made to air emissions sources at the facility. Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address CAA compliance issues at the nation's coal-fired power plants. The strategy has included both the filing of suits against a number of power plant owners, and the issuance of administrative notices of violation ("NOVs") to a number of power plant owners alleging NSR violations.

In April 2009, APS, as operating agent of Four Corners, received a US EPA request pursuant to Section 114 of the CAA for information about Four Corners. The US EPA requested information about Four Corners and its operations, including information about Four Corners capital projects from 1990 to the present. APS has responded to the US EPA request. SCE understands that in other cases the US EPA has utilized similar Section 114 letters for examining whether power plants have triggered NSR requirements under the CAA and are therefore potentially subject to more stringent air pollution control requirements. No NSR enforcement-related proceedings have been initiated by the US EPA with respect to Four Corners. SCE cannot predict the outcome of this inquiry.

### Water Quality

#### Clean Water Act

Regulations under the federal Clean Water Act require permits for the discharge of pollutants into United States waters and permits for the discharge of storm water flows from certain facilities. The Clean Water Act also regulates the temperature of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities. California has a US EPA-approved program to issue individual or group (general) permits for the regulation of Clean Water Act discharges. California also regulates certain discharges not regulated by the US EPA.

In January 2007, the U.S. Court of Appeals for the Second Circuit rejected the US EPA rule on cooling water intake structures and remanded it to the US EPA. Among the key provisions remanded by the court were the use of cost-benefit analysis for determining the best technology available and the use of restoration to achieve compliance with the rule. On July 2007, the US EPA suspended the requirements for cooling water intake structures, pending further rulemaking. In April 2009, the U.S. Supreme Court reversed the Second Circuit and held that the US EPA may consider, but is not required to use, cost-benefit analysis in formulating regulations under Clean Water Act Section 316(b). The Court did not review the Second Circuit's rejection of the use of restoration as compliance with Section 316(b), which means the Second Circuit decision on this issue remains valid.

The US EPA is currently rewriting its rule, and it is unknown whether the revised regulations will use cost-benefit analysis. Because there are no defined compliance targets absent a new rule, SCE is reviewing a wide range of possible control technologies. Although the new rule could have a material impact on SCE, until the final compliance criteria have been published, SCE can not reasonably determine the financial impact.

#### Prohibition on the Use of Ocean-Based Once-Through Cooling

In June 2009 the California State Water Resources Control Board issued a draft "Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling." The Policy would establish closed-cycle wet cooling as the best technology available for retrofitting existing "once through" cooled plants such as SCE's San Onofre, which use ocean water for cooling purposes. If the draft policy is adopted, it may significantly impact both operations at San Onofre and SCE's ability to procure timely generating capacity from fossil-fuel plants that use ocean water in once-through cooling systems. It may also impact system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations. The Policy has the potential to adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory.

### Hazardous Substances and Hazardous Waste

Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable for property damage, personal injury, natural resource damages, and investigation and remediation costs incurred by governmental entities and third parties in connection with these releases or threatened releases. Many of these laws, including the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, ("CERCLA"), impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several.

In connection with the ownership and operation of its facilities, SCE may be liable for costs associated with hazardous waste compliance and remediation required by laws and regulations. Through an incentive mechanism, the CPUC allows SCE to recover in retail rates paid by its customers some of the environmental remediation costs at certain sites. Additional information about these laws and regulations appears in "Item 8. SCE Notes to Consolidated Financial Statements—Note 6 .Commitments and Contingencies."

#### Coal Combustion Wastes

US EPA regulations currently classify coal combustion wastes as solid wastes that are exempt from hazardous waste requirements. The exemption applies to fly ash, bottom ash, slag, and flue gas emission control wastes generated from the combustion of coal or other fossil fuels. The US EPA has studied coal combustion wastes extensively and in 2000 concluded that fossil fuel combustion wastes do not warrant regulation as a hazardous waste. The current classification of coal combustion wastes as exempt from hazardous waste requirements enables beneficial uses of coal combustion wastes, such as for cement production and fill materials.

The US EPA is expected to publish proposed regulations relating to coal combustion waste in 2010. Additional regulation of the storage, disposal and beneficial reuse of coal combustion waste could affect the management of such wastes and could require SCE to incur additional capital and operating costs with no assurance that the additional costs could be recovered. Additionally, SCE may be prohibited from making such expenditures under SB 1368, the California law on greenhouse gas emission performance standards (see "—Climate Change—State Legislative/Regulatory Developments" above for a description of SB 1368).

## Risk factors

As filed, 12,432 characters.

### Regulatory Risks

***SCE's financial viability depends upon its ability to recover its costs in a timely manner from its customers through regulated rates.***

SCE is a regulated entity subject to CPUC and FERC jurisdiction in almost all aspects of its business, including the rates, terms and conditions of its services, procurement of electricity for its customers, issuance of securities, dispositions of utility assets and facilities and aspects of the siting and operations of its electricity distribution systems. SCE's ongoing financial viability depends on its ability to recover from its customers in a timely manner its costs, including the costs of electricity purchased for its customers, through the rates it charges its customers, as approved by the CPUC, and its ability to pass through to its customers in rates its FERC-authorized revenue requirements. SCE's financial viability also depends on its ability to recover through the rates it is allowed to charge an adequate return on capital, including long-term debt and equity. If SCE is unable to recover material amounts of its costs in rates in a timely manner or recover an adequate return on capital, its financial condition and results of operations could be materially adversely affected.

***SCE's energy procurement activities are subject to regulatory and market risks that could adversely affect its financial condition and liquidity.***

SCE obtains energy, capacity, renewable attributes, and ancillary services needed to serve its customers from its own generating plants, as well as through contracts with energy producers and sellers. California law and CPUC decisions allow SCE to recover through the rates it is allowed to charge its customers reasonable procurement costs incurred in compliance with an approved procurement plan. Nonetheless, SCE's cash flows remain subject to volatility resulting from its procurement activities. In addition, SCE is subject to the risks of unfavorable or untimely CPUC decisions about the compliance of procurement activities with SCE's procurement plan and the reasonableness of certain procurement-related costs.

Many of SCE's power purchase contracts are tied to market prices for natural gas. Some of its contracts also are subject to volatility in market prices for electricity. SCE seeks to hedge its market price exposure to the extent authorized by the CPUC. SCE may not be able to hedge its risk for commodities on favorable terms or fully recover the costs of hedges through the rates it is allowed to charge its customers, which could adversely affect SCE's liquidity and results of operation.

In its power purchase contracts and other procurement arrangements, SCE is exposed to risks from changes in the credit quality of its counterparties, many of whom may be adversely affected by the conditions in the financial markets. If a counterparty were to default on its obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power and this could have a material adverse effect on SCE's liquidity and financial condition if such costs cannot be recovered in a timely manner.

***SCE is subject to extensive regulation and the risk of adverse regulatory decisions and changes in applicable regulations or legislation.***

SCE operates in a highly regulated environment. SCE's business is subject to extensive federal, state and local energy, environmental and other laws and regulations. The CPUC regulates SCE's retail operations, and the FERC regulates SCE's wholesale operations. The Nuclear Regulatory Commission regulates SCE's nuclear power plants. The construction, planning, and project site identification of SCE's power plants and transmission lines in California are also subject to the jurisdiction of the California Energy Commission (for plants 50 MW or greater), and the CPUC. The construction, planning and project site identification of transmission lines that are outside of California are subject to the regulation of the relevant state agency.

SCE must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective orders. Should SCE be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on SCE, SCE's business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to SCE or SCE's facilities in a manner that may have a detrimental effect on SCE's business or result in significant additional costs because of SCE's need to comply with those requirements.

### Environmental Risks

***SCE is subject to numerous environmental laws and regulations with respect to operation of its facilities. New laws and regulations could adversely affect SCE.***

SCE is subject to extensive environmental regulations and permitting requirements that involve significant and increasing costs. SCE devotes significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with existing and anticipated environmental regulatory requirements. However, the current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. The U.S. Congress is considering several competing proposals to regulate greenhouse gas emissions. The U.S. Environmental Protection Agency has issued a finding that certain GHGs endanger the public health and welfare and are air pollutants that are subject to the Clean Air Act. In addition, the attorneys general of several states, including California, certain environmental advocacy groups, and numerous state regulatory agencies in the United States have been focusing considerable attention on greenhouse gas emissions from coal-fired power plants and their potential role in climate change. The adoption of laws and regulations to implement greenhouse act controls could adversely affect operations, particularly of the coal-fired plants.

The continued operation of SCE facilities, particularly the coal-fired facilities, may require substantial capital expenditures for environmental controls. In addition, future environmental laws and regulations, and future enforcement proceedings that may be taken by environmental authorities, could affect the costs and the manner in which SCE conducts business.

Furthermore, changing environmental regulations could make some units uneconomical to maintain or operate. If the affected subsidiaries cannot comply with all applicable regulations, they could be required to retire or suspend operations at such facilities, or to restrict or modify the operations of these facilities, and their business, results of operations and financial condition could be adversely affected.

### Operating Risks

***SCE's financial condition and results of operations could be materially adversely affected if it is unable to successfully manage the risks inherent in operating and improving its facilities.***

SCE owns and operates extensive electricity facilities that are interconnected to the United States western electricity grid. SCE is also undertaking large-scale new infrastructure construction, which involves risks related to permitting, governmental approvals, and construction delays. The operation of SCE's facilities and the facilities of third parties on which it relies involves numerous risks, including:

operating limitations that may be imposed by environmental or other regulatory requirements;

imposition of operational performance standards by agencies with regulatory oversight of SCE's facilities;

environmental and personal injury liabilities caused by the operation of SCE's facilities;

interruptions in fuel supply;

blackouts;

employee work force factors, including strikes, work stoppages or labor disputes;

weather, storms, earthquakes, fires, floods or other natural disasters;

acts of terrorism; and

explosions, accidents, mechanical breakdowns and other events that affect demand, result in power outages, reduce generating output or cause damage to SCE's assets or operations or those of third parties on which it relies.

The occurrence of any of these events could result in lower revenues or increased expenses and liabilities, or both, which may not be fully recovered through insurance, rates or other means in a timely manner or at all.

***There are inherent risks associated with operating nuclear power generating facilities.***

*Spent fuel storage capacity could be insufficient to permit long-term operation of SCE's nuclear plants.*

SCE operates and is majority owner of San Onofre Nuclear Generating Station and is part owner of Palo Verde Nuclear Generating Station. The U.S. Department of Energy has defaulted on its obligation to begin accepting spent nuclear fuel from commercial nuclear industry participants by January 31, 1998. If SCE or the operator of Palo Verde were unable to arrange and maintain sufficient capacity for interim spent-fuel storage now or in the future, it could hinder the operation of the plants and impair the value of SCE's ownership interests until storage could be obtained, each of which may have a material adverse effect on SCE.

*Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.*

Federal law limits public liability claims from a nuclear incident to the amount of available financial protection which is currently approximately $12.6 billion. SCE and other owners of the San Onofre and Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance available of $375 million per site. If this public liability limit is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further revenue. If this were to occur, tension could exist between the federal government's attempt to impose revenue-raising measures upon SCE and the CPUC's willingness to allow SCE to pass this liability along to its customers, resulting in under-collection of SCE's costs. There can be no assurance of SCE's ability to recover uninsured costs in the event federal appropriations are insufficient.

***SCE's insurance coverage may not be sufficient under all circumstances and SCE may not be able to obtain sufficient insurance.***

SCE's insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A loss for which SCE is not fully insured could materially and adversely affect SCE's financial condition and results of operations. Further, due to rising insurance costs and changes in the insurance markets, insurance coverage may not continue to be available at all or at rates or on terms similar to those presently available to SCE.

### Financing Risks

***SCE relies on access to the capital markets. If SCE were unable to access capital markets or the cost of capital was to substantially increase, its liquidity and operations could be adversely affected.***

SCE's ability to fund operations and planned capital expenditure projects, as well as its ability to refinance debt and make scheduled payments of principal and interest, including to Edison International, depends on its cash flow and access to the capital markets. SCE's ability to arrange financing and the costs of such capital are dependent on numerous factors, including SCE's levels of indebtedness, maintenance of acceptable credit ratings, its financial performance, liquidity and cash flow, and other market conditions. Market conditions which could adversely affect SCE's financing costs and availability include:

current state and liquidity of financial markets;

market prices for electricity or gas;

changes in interest rates and rates of inflation;

terrorist attacks or the threat of terrorist attacks on SCE's facilities or unrelated energy companies; and

the overall health of the utility industry.

SCE may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on SCE's liquidity and operations.

## Legal proceedings

As filed, 4,450 characters.

### Catalina South Coast Air Quality Management District Potential Environmental Proceeding

During the period 2006-2008, the South Coast Air Quality Management District (SCAQMD) issued five NOVs alleging violations of the NOx emission limits and related Regional Clean Air Incentives Market (RECLAIM) trading credit (to offset NOx emissions) requirements by certain of SCE's diesel generation units on Catalina Island. A settlement agreement, which resolves all of the NOVs, was fully executed in April 2009 and requires SCE to install new equipment by December 31, 2011 or pay a $3 million fine if the equipment is not installed by that date.

### Navajo Nation Litigation

Information about the Navajo Nation litigation appears in the "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies."

#### Pursuant to Form 10-K's General Instruction G(3), the following information is included as an additional item in Part I:

### EXECUTIVE OFFICERS OF THE REGISTRANT

| Executive Officer1 | Age at December 31, 2009 | Company Position |
| --- | ---: | --- |
| Alan J. Fohrer | 59 | Chairman of the Board and Chief Executive Officer |
| John R. Fielder | 64 | President |
| Pedro J. Pizarro | 44 | Executive Vice President, Power Operations |
| Stephen E. Pickett | 59 | Senior Vice President and General Counsel |
| Ross Ridenoure | 55 | Senior Vice President and Chief Nuclear Officer |
| Linda G. Sullivan | 46 | Senior Vice President, Chief Financial Officer and Acting Controller |
| Lynda L. Ziegler | 57 | Senior Vice President, Customer Service |

1

The term "Executive Officers" is defined by Rule 3b-7 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended.

None of SCE's executive officers is related to each other by blood or marriage. As set forth in Article IV of SCE's Bylaws, the elected officers of SCE are chosen annually by, and serve at the pleasure of, SCE's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the above officers have been actively engaged in the business of SCE and/or Edison International for more than five years, except for Mr. Ridenoure, and have served in their present positions for the periods stated below. Additionally, those officers who have had other or additional principal positions in the past five years had the following business experience during that period:

| Executive Officer | Company Position | Effective Dates |
| --- | --- | --- |
| Alan J. Fohrer | Chairman of the Board and Chief Executive Officer, SCE | June 2007 to present |
|  | Chief Executive Officer, SCE | January 2002 to June 2007 |
| John R. Fielder | President, SCE | October 2005 to present |
|  | Senior Vice President, Regulatory Policy and Affairs, SCE | February 1998 to October 2005 |
| Pedro J. Pizarro | Executive Vice President, Power Operations, SCE | April 2008 to present |
|  | Senior Vice President, Power Procurement, SCE | May 2005 to March 2008 |
|  | Vice President, Power Procurement, SCE | January 2004 to May 2005 |
| Stephen E. Pickett | Senior Vice President and General Counsel, SCE | January 2002 to present |
| Ross Ridenoure | Senior Vice President and Chief Nuclear Officer, SCE | June 2008 to present |
|  | Vice President and Site Manager, SONGS, SCE | December 2007 to May 2008 |
|  | Vice President and Chief Nuclear Officer, Omaha Public Power District1 | December 2003 to November 2007 |
| Linda G. Sullivan | Senior Vice President, Chief Financial Officer and Acting Controller, SCE | July 2009 to present |
|  | Vice President and Controller, Edison International | June 2005 to August 2009 |
|  | Vice President and Controller, SCE | June 2005 to June 2009 |
|  | Assistant Controller, SCE | March 2005 to May 2005 |
|  | Assistant Controller, Edison International | May 2002 to May 2005 |
| Lynda L. Ziegler | Senior Vice President, Customer Service, SCE | March 2006 to present |
|  | Vice President, Customer Programs and Services Division, SCE | May 2005 to February 2006 |
|  | Director, Customer Programs and Services Division, SCE | January 1999 to April 2005 |

1

Omaha Public Power District is a public electric utility in the State of Nebraska and is not a parent, subsidiary or affiliate of Edison International. Mr. Ridenoure served as Vice President and Chief Nuclear Officer.

## Management's discussion and analysis

As filed, 87,804 characters.

### MANAGEMENT OVERVIEW

### Introduction

This overview is presented in three sections:

Highlights of operating results;

SCE's capital investment plan to maintain reliability and expand the capability of its distribution and transmission infrastructure, support initiatives in California to increase renewable energy, construct and replace generating assets and deploy advanced metering capability; and

Environmental developments, including regulatory and legal developments related to greenhouse gases and once-through cooling.

### Highlights of Operating Results

*(in millions)*

|  | 2009 | 2008 | Change | 2007 |
| --- | ---: | ---: | ---: | ---: |
| Net income available for common stock | $1,226 | $683 | $543 | $707 |
| Non-Core Items |  |  |  |  |
| SCE Regulatory Items | 46 | (49) | 95 | 31 |
| Global Settlement | 306 | — | 306 | — |
| Total non-core items | 352 | (49) | 401 | 31 |
| Core Earnings | $874 | $732 | $142 | $676 |

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 our earnings results to facilitate comparisons of SCE's performance from period to period. Core earnings is 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 prior year tax liabilities and non-recurring regulatory or legal proceedings.

SCE's 2009 core earnings increased from 2008 primarily due to higher operating income associated with the CPUC and FERC 2009 general rate case decisions, partially offset by higher income taxes. In addition, core earnings were favorably impacted from lower than planned financings during the year, primarily from cash received for tax-related timing differences and other benefits.

During 2009, SCE received general rate case decisions from the CPUC and FERC, as follows:

The CPUC issued a decision in SCE's 2009 GRC, authorizing a $4.83 billion revenue requirement for 2009, an increase of $512 million from SCE's 2008 revenue requirement, effective January 1, 2009. The CPUC also authorized a methodology that would result in an approximate revenue requirement of $5.04 billion in 2010 and $5.25 billion in 2011.

The FERC approved a settlement to the 2009 rate case effective March 1, 2009. The settlement provides for a transmission revenue requirement of $448 million, an increase of $136 million over the previously authorized amount.

Changes in non-core items include the following:

An after-tax earnings benefit of $306 million in 2009 resulted from the Global Settlement with the Internal Revenue Service, including a $5 million tax benefit recorded in the fourth quarter from a revised estimate of federal interest related to the settlement. The Global Settlement resolved all outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002.

An after-tax non-cash benefit of $46 million was recorded in 2009 from the transfer of the Mountainview power plant to utility rate base pursuant to approvals by the CPUC and FERC.

An after-tax charge of $49 million in 2008 from a decision by the CPUC disallowing certain amounts and imposing penalties under its performance-based ratemaking program for the period 1997 – 2003.

See "Results of Operations" for discussion of SCE results of operations, including a comparison of 2008 results to 2007.

### SCE Capital Program

SCE's capital program is focused primarily in five areas:

Upgrading and constructing new transmission lines to expand capacity to utilize renewable energy, including the Tehachapi, Devers-Colorado River and Eldorado-Ivanpah projects;

Maintaining reliability and expanding capability of SCE's transmission and distribution system;

Developing and installing up to 250 MW of utility-owned solar photovoltaic generating facilities (generally ranging in size from 1 to 2 MW each) on commercial and industrial rooftops and other space in SCE's service territory;

Replacing steam generators at San Onofre intended to enable operations until at least the end of its initial license period in 2022; and

Installing "smart" meters in approximately 5.3 million households and small businesses referred to as Edison SmartConnect™.

SCE plans to utilize much of the cash currently generated from its operations and issuance of additional debt and preferred stock for its capital program. SCE's capital expenditures in 2009 totaled $2.9 billion. SCE projects that capital expenditures will be in the range of $3.3 billion to $4.0 billion in 2010 and that the 2010 – 2014 total capital investment plan will be in the range of $18 billion to $21.5 billion. The rate of actual capital spending will be affected by permitting, regulatory, market and other factors as discussed further under "Liquidity and Capital Resources—Capital Investment Plan."

### Environmental Developments

### Greenhouse Gas Regulation Developments

The nature of future environmental regulation and legislation will have a substantial impact on SCE. SCE believes that resolution of current uncertainties about the future, through well-balanced and appropriately flexible regulation and legislation, is needed to support the necessary evolution of the electric industry into using cleaner, more efficient infrastructure and to attract the capital ultimately needed for this effort. Legislative, regulatory, and legal developments related to potential controls over greenhouse gas emissions in the United States are ongoing. Actions to limit or reduce greenhouse gas emissions could significantly increase the cost of generating electricity from fossil fuels as well as the cost of purchased power. In the case of utilities, like SCE, these costs are generally borne by customers.

Recent significant developments include the following:

Legislation to regulate greenhouse gas emissions continues to be considered by Congress; however, the timing, content, and potential effects on SCE of any greenhouse gas legislation that may be enacted remain uncertain.

In December 2009, the US EPA issued a final finding that certain greenhouse gases, including carbon dioxide, threaten the public health and welfare. The US EPA has issued a proposed rule, known as the "greenhouse gas tailoring rule," under which all new and major modifications of existing stationary sources emitting 25,000 metric tons of carbon dioxide equivalents annually, including power plants, would be required to include BACT to minimize their greenhouse gas emissions. Since the current proposal affects only new or modified sources, it is not expected to have any immediate effect, if adopted, on SCE's existing fossil-fuel generating stations, but it could affect the cost of new construction or modifications. US EPA could also use its authority in the future to regulate existing sources of greenhouse gas emissions. If controls are required to be installed at SCE's facilities in the future in order to reduce greenhouse gas emissions pursuant to regulations issued by the US EPA or others, the potential impact will depend on the nature of the controls applied, which remains uncertain.

Three recent court cases addressed the question of whether power plants that emit greenhouse gases constituted public nuisances that could be held liable for damages or other remedies. In one case (in which Edison International, the parent company of SCE, is a named defendant): a California federal district court dismissed the plaintiffs' claims. In the other two, federal courts of appeals permitted the suits to go forward. Each of these differing results remains subject to appeal and thus the ultimate impact of these cases remains uncertain. SCE cannot predict whether these recent decisions will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts for these sorts of claims.

Governor Schwarzenegger issued an executive order to increase California's renewable energy goals from 20% to 33% and has directed the CARB to adopt a regulation consistent with 33% of retail sellers annual electricity sales being obtained from renewable energy sources by 2020. Achieving a 33% renewables portfolio standard in this timeframe is highly ambitious, given the magnitude of the infrastructure build-out required and the slow pace of transmission permitting and approvals. The CARB is also considering a number of direct regulations to reduce greenhouse gases in California, which requirements could go beyond those ultimately imposed by Congress or the US EPA.

### Once-Through Cooling

Last year, the California State Water Resources Board released a draft policy, which would establish closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like San Onofre and many of the existing gas-fired power plants along the California coast. If the policy is adopted by the Board, it may result in significant capital expenditures at San Onofre and may affect its operations. It may also significantly impact SCE's ability to procure generating capacity from fossil-fuel plants that use ocean water in once-through cooling systems. It may also impact system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations. The policy has the potential to adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined, in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory.

### RESULTS OF OPERATIONS

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

Utility earning activities, which mainly represent CPUC and FERC-authorized base rates, which allow a reasonable return, and CPUC-authorized incentive mechanisms; and

Utility cost-recovery activities, which mainly represent CPUC-authorized balancing accounts, which allow recovery of costs incurred or provide mechanisms to track and recover or refund differences in forecasted and actual amounts. Balancing accounts do not allow for a return.

Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest, taxes and a return, including the return on capital projects recovered through balancing account mechanisms. Differences between authorized and actual results impact earnings. Also, included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.

Utility cost-recovery activities include rates which provide for recovery, subject to reasonableness review, of fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), nuclear decommissioning expense, certain operation and maintenance expenses, and depreciation expense related to certain projects. There is no return for cost-recovery expenses.

### Electric Utility Results of Operations

The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities (including Big 4).

*(in millions)*

|  | 2009 Utility Earning Activities | Utility Cost- Recovery Activities1 | Total Consolidated | 2008 Utility Earning Activities | Utility Cost- Recovery Activities1 | Total Consolidated | 2007 Utility Earning Activities | Utility Cost- Recovery Activities1 | Total Consolidated |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| **Operating revenue** | $5,242 | $4,723 | $9,965 | $4,728 | $6,520 | $11,248 | $4,439 | $5,794 | $10,233 |
| Fuel and purchased power | — | 3,472 | 3,472 | — | 5,245 | 5,245 | — | 4,426 | 4,426 |
| Operations and maintenance | 2,091 | 1,063 | 3,154 | 2,031 | 982 | 3,013 | 1,877 | 961 | 2,838 |
| Depreciation, decommissioning and amortization | 1,113 | 65 | 1,178 | 1,033 | 81 | 1,114 | 938 | 73 | 1,011 |
| Property taxes and other | 240 | 4 | 244 | 225 | 7 | 232 | 209 | 8 | 217 |
| Gain on sale of assets | — | (1) | (1) | — | (9) | (9) | — | — | — |
| **Total operating expenses** | 3,444 | 4,603 | 8,047 | 3,289 | 6,306 | 9,595 | 3,024 | 5,468 | 8,492 |
| **Operating income** | 1,798 | 120 | 1,918 | 1,439 | 214 | 1,653 | 1,415 | 326 | 1,741 |
| Net interest expense and other | (297) | (1) | (298) | (415) | 8 | (407) | (359) | 18 | (341) |
| **Income before income taxes** | 1,501 | 119 | 1,620 | 1,024 | 222 | 1,246 | 1,056 | 344 | 1,400 |
| Income tax expense | 224 | 25 | 249 | 290 | 52 | 342 | 298 | 39 | 337 |
| **Net income** | 1,277 | 94 | 1,371 | 734 | 170 | 904 | 758 | 305 | 1,063 |
| Net income attributable to noncontrolling interest | — | 94 | 94 | — | 170 | 170 | — | 305 | 305 |
| Dividends on preferred and preference stock not subject to mandatory redemption | 51 | — | 51 | 51 | — | 51 | 51 | — | 51 |
| **Net income available for common stock** | $1,226 | $— | $1,226 | $683 | $— | $683 | $707 | $— | $707 |
| Core Earnings2 |  |  | $874 |  |  | $732 |  |  | $676 |
| Non-Core Earnings: |  |  |  |  |  |  |  |  |  |
| Regulatory items |  |  | 46 |  |  | (49) |  |  | 31 |
| Global tax settlement |  |  | 306 |  |  | — |  |  | — |
| Total SCE GAAP Earnings |  |  | $1,226 |  |  | $683 |  |  | $707 |

1

SCE has contracts with certain QFs that contain variable contract provisions based on the price of natural gas. Four of these contracts are with entities that are partnerships owned in part by EME. The QFs sell electricity to SCE and steam to nonrelated parties. In accordance with authoritative accounting guidance which requires consolidation of certain variable interest entities, SCE consolidates these Big 4 projects. SCE does not derive any income or cash flows from these entities.

2

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

### Utility Earning Activities

#### 2009 vs. 2008

Utility earning activities were primarily affected by:

Higher operating revenue of $514 million primarily due to the following:

$485 million increase resulting from the implementation of SCE's 2009 CPUC GRC decision, which authorized an increase of $512 million ($27 million of which is reflected in utility cost-recovery activities) from SCE's 2008 revenue requirement effective January 1, 2009.

$114 million increase resulting from the 2009 FERC approved rate case settlement effective March 1, 2009.

$85 million decrease primarily due to the revenue requirements for medical, dental, and vision expenses and SCE's share of Palo Verde operation and maintenance expenses, which beginning in 2009 are reflected in utility cost recovery activities.

In December 2009, the CPUC approved a payment of $26 million (compared to a $25 million payment in 2008) on SCE's 2006-2008 energy efficiency risk/reward incentive mechanism. SCE expects to recognize a final payment of approximately $27 million in 2010. The final payment, if any, may be reduced as a result of the final verification and review of the entire program cycle savings.

Higher operation and maintenance expenses of $60 million primarily due to:

$105 million of higher transmission and distribution expenses primarily due to higher costs to support system reliability and infrastructure projects, increases in preventive maintenance work, as well as engineering costs;

$50 million of higher expenses related to regulatory and performance issues including the NRC requiring SCE to take action to provide greater assurance of compliance by San Onofre personnel with applicable NRC requirements and procedures. SCE is currently implementing plans to address the identified issues (see "Item 1. Business—Regulation—Nuclear Power Plant Regulation" for further discussion);

$50 million of higher expenses associated with new information technology system requirements and facility maintenance to support company growth programs;

$30 million of higher expenses resulting from the transfer of the Mountainview plant to utility rate base in July 2009, previously recognized in cost-recovery activities; partially offset by

$175 million of expenses which, beginning in 2009, are recovered through balancing accounts and are reflected in 2009 cost-recovery activities. SCE's 2009 GRC decision authorized balancing account treatment for medical, dental and vision expenses and SCE's share of Palo Verde operations and maintenance expenses.

Higher depreciation expense of $80 million primarily resulting from increased capital investments including capitalized software costs.

Lower net interest expense and other of $118 million primarily due to:

Lower other expenses of $71 million primarily due to a final charge of $60 million ($49 million after-tax)recorded in 2008 resulting from the CPUC decision on SCE's PBR mechanism as well as a $14 million decrease in civic, political and related activity expenditures, primarily related to spending on Proposition 7 in 2008, partially offset by a $8 million increase in donations. See "Item 8. SCE

Notes to Consolidated Financial Statements—Note 12. Other Income and Expenses" for further detail of other expenses.

Higher other income of $63 million due to an increase in AFUDC – equity earnings primarily resulting from:

$50 million increase in AFUDC – equity earnings in the third quarter of 2009 related to the transfer of the Mountainview power plant to utility rate base. The 2009 CPUC GRC decision granted the authority to transfer the assets and liabilities of Mountainview Power Company, LLC to SCE, which was subsequently approved by the FERC and transferred in July 2009.

$12 million increase in AFUDC – equity earnings resulting from an increase in construction work in progress related to SCE's capital investment program.

See "Item 8. SCE Notes to Consolidated Financial Statements—Note 12. Other Income and Expenses" for further detail of other income.

Higher interest expense of $8 million primarily due to higher outstanding balances on long-term debt partially offset by lower interest expense on short-term borrowings. Due to an increase in cash flow from operations, including the positive cash impact from the Global Settlement and other tax timing differences, SCE was able to defer some of its expected financings in 2009 to support its growth programs.

Lower income tax expense primarily due to an interest benefit related to the Global Settlement, partially offset by higher pre-tax income, higher 2008 software deductions resulting from the implementation of SAP, and lower property-related tax benefits in 2009.

#### 2008 vs. 2007

Utility earning activities were primarily affected by:

Higher operating revenue of $289 million primarily due to rate base related revenue growth, and authorized energy efficiency incentives. SCE recorded $25 million of energy efficiency revenues in 2008 in connection with the energy efficiency risk/reward incentive mechanism.

Higher operation and maintenance expenses of $154 million primarily due to $60 million of higher generation expenses related to maintenance and refueling outage expenses at San Onofre and higher overhaul and outage costs at Four Corners and Palo Verde and $50 million of higher customer service expenses and administrative and general expenses primarily related to higher labor costs, increased uncollectible accounts and higher franchise fees and higher maintenance costs.

Higher depreciation expense of $95 million primarily resulting from increased capital investments, including capitalized software costs, and a $17 million cumulative depreciation rate adjustment recorded in the second quarter of 2008.

Higher net interest expense and other of $56 million primarily due to:

Higher other expenses of $79 million primarily due to a final charge of $60 million ($49 million after-tax) recorded in 2008 related to a decision received regarding

SCE incentives claimed under a CPUC-approved PBR mechanism. The 2008 variance was also due to an increase of $8 million for civic, political and related activity expenditures primarily related to spending on Proposition 7.

Higher other income of $24 million primarily due to $10 million of proceeds received for corporate-owned life insurance policies and an $8 million increase in AFUDC – equity earnings resulting from an increase in construction work in progress related to SCE's capital investment program.

Lower interest expense of $21 million primarily due to lower balancing account over-collections and lower interest rates applied to those over-collections. This decrease was partially offset by higher interest expense resulting from higher outstanding balances on long-term debt.

Lower interest income of $22 million primarily due to lower balancing account under-collections and lower interest rates in 2008 compared to 2007 partially offset by higher interest income due to higher cash and equivalents and short-term investment balances.

### Utility Cost-Recovery Activities

#### 2009 vs. 2008

Utility cost-recovery activities were primarily affected by:

Lower purchased power expense of $1.1 billion primarily due to: lower bilateral energy and QF purchases of $1.3 billion primarily due to lower natural gas prices and decreased kWh purchases; and lower firm transmission rights costs of $65 million due to implementation of the MRTU market. Realized losses on economic hedging activities were $344 million in 2009 and $60 million in 2008. Changes in realized losses on economic hedging activities were primarily due to settled natural gas prices being significantly lower than average fixed prices.

Lower fuel expense of $679 million primarily due to lower costs at the Mountainview plant of $230 million and lower costs for the SCE Big 4 projects of $445 million, both resulting from lower natural gas costs in 2009 compared to 2008.

Higher operation and maintenance expense of $81 million primarily related to $185 million of expenses which beginning in 2009 are recovered through balancing accounts and are reflected in 2009 cost recovery activities. SCE's 2009 GRC decision authorized balancing account treatment for medical, dental, and vision expenses and its share of Palo Verde operation and maintenance expenses. In addition, SCE recorded higher pension and PBOP expenses of $60 million due to the volatile market conditions experienced in 2008. These increases were partially offset by $50 million of lower energy efficiency costs, $85 million of lower transmission access and reliability service charges and $30 million of lower Mountainview expenses resulting from the transfer of the Mountainview plant to utility rate base in July 2009.

#### 2008 vs. 2007

Utility cost-recovery activities were primarily affected by:

Higher purchased power expense of $610 million due to: higher bilateral energy and QF purchases of $495 million, primarily due to higher natural gas prices and increased kWh purchases and higher ISO-related energy costs of $165 million. These increases were partially offset by $30 million of lower firm transmission rights costs. Realized losses on economic hedging were $60 million in 2008 and $132 million in 2007. Changes in realized losses on economic hedging activities were primarily due to significant decreases in forward natural gas prices in 2008 compared to 2007.

Higher fuel expense of $209 million primarily due to higher costs at SCE's Mountainview plant of $85 million and higher costs at SCE's VIEs of $104 million, both resulting from higher natural gas prices in 2008 compared to 2007.

### Supplemental Operating Revenue Information

SCE's total consolidated operating revenue was $10 billion, $11.2 billion and $10.2 billion for the year-ended December 31, 2009, 2008, and 2007, respectively, of which $9.5 billion, $9.3 billion and $9.2 billion related to retail billed and unbilled revenue (excluding wholesale sales) for the same respective periods. In 2009, retail billed and unbilled revenue increased $184 million compared to the same period in 2008. The increase reflects a rate increase (including impact of a tiered rate structure) of $564 million and a sales volume decrease of $380 million. Effective April 4, 2009, SCE's overall system average rate increased to 14.1¢ per-kWh due to the implementation of both revenue allocation and rate design changes authorized in Phase 2 of the 2009 GRC and the FERC transmission rate changes authorized in the 2009 FERC rate case. The sales volume decrease was due to the economic downturn as well as the impact of milder weather experienced in 2009 compared to the same period in 2008. Retail billed and unbilled revenue increased $94 million in 2008, compared to the same period in 2007. The increase reflects a rate increase (including impact of tiered rate structure) of $92 million and a sales volume increase of $2 million. The rate increase was due to minor variations of usage by rate class.

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.

Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWR and are not recognized as revenue by SCE. The amounts collected and remitted to CDWR were $1.8 billion, $2.2 billion and $2.3 billion for the years ended December 31, 2009, 2008 and 2007, respectively.

### Effective Income Tax Rates

SCE's effective income tax rate was 16.3% in 2009 compared to 31.8% in 2008. The effective tax rate decreased due to 2009 benefits related to both the Global Settlement and recognition of additional AFUDC – equity resulting from the transfer of the Mountainview power plant to utility rate base. Partially off-setting these items was an increase from higher 2008 software deductions related to the implementation of SAP and lower property-related tax benefits in 2009. The effective tax rate for both periods was lower than the federal statutory rate primarily due to these items as well as other property related flow-through items and state income expense. The CPUC requires flow-through rate-making treatment for the current tax benefit arising from certain property-related and other temporary differences, which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.

SCE's effective income tax rate was 31.8% in 2008 compared to 30.8% in 2007. The 2008 effective tax rate included tax benefits from higher software deductions related to the implementation of SAP. The 2007 effective tax rate included tax benefits from reductions in liabilities for uncertain tax positions to reflect both the progress made in an administrative appeals process with the IRS related to the income tax treatment of certain costs associated with environmental remediation and to reflect a settlement of state tax audit issues. The effective tax rate for both periods was lower than the federal statutory rate primarily due to these items as well as other property related flow-through items and state income tax expense. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 4. Income Taxes."

### LIQUIDITY AND CAPITAL RESOURCES

SCE's ability to operate its business, complete planned capital projects, and implement its business strategy is dependent upon its cash flow and access to the capital markets to finance its business. 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, dividend payments made to Edison International, and the outcome of tax and regulatory matters.

SCE's continuing obligations and projected capital investments, both for 2010, are expected to be funded through cash and equivalents on hand, operating cash flows and incremental capital market financings of debt and preferred equity. SCE expects that it would also be able to draw on the remaining availability of its credit facilities and access capital markets if additional funding and liquidity are necessary to meet operating and capital requirements.

### Available Liquidity

As of December 31, 2009, SCE had approximately $3.3 billion of available liquidity comprised of cash and equivalents and short-term investments and $2.9 billion available under credit facilities. As of December 31, 2009, SCE's long-term debt, including current maturities of long-term debt, was $6.7 billion.

The following table summarizes the status of SCE's credit facilities at December 31, 2009:

*(in millions)*

|  | Credit Facilities1 |
| --- | ---: |
| Commitment | $2,894 |
| Outstanding borrowings | — |
| Outstanding letters of credit | (12) |
| Amount available | $2,882 |

1

SCE has two credit facilities with various banks. A $2.4 billion five-year credit facility that matures in February 2013, with four one-year options to extend by mutual consent and a $500 million 364-day revolving credit facility terminating on March 16, 2010.

### Debt Covenant

SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At December 31, 2009, SCE's debt to total capitalization ratio was 0.45 to 1.

### Capital Investment Plan

SCE's capital investment plan for 2010 – 2014 includes a capital forecast of $21.5 billion. The 2010 – 2011 planned capital investments for projects under CPUC jurisdiction are recovered through the authorized revenue requirement in SCE's 2009 GRC or through other CPUC-authorized mechanisms. Recovery of planned capital investments for projects under CPUC jurisdiction beyond 2011 and not already approved through other CPUC-authorized mechanisms, is subject to the outcome of future CPUC GRCs or other CPUC approvals. Recovery of the 2010 planned capital investments for projects under FERC jurisdiction has been requested in the 2010 FERC Rate Case. Recovery of the 2011 – 2014 planned capital investments under FERC jurisdiction will be requested in future FERC transmission filings, as appropriate.

The completion of the projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, weather and other unforeseen conditions.

SCE capital investments (including accruals) related to its 2009 capital plan were $2.9 billion. SCE's capital investments for 2009 were approximately 15% less than the original forecast, primarily due to timing delays resulting from a later than expected 2009 GRC decision and delays in other regulatory approvals. The estimated capital investments for the next five years may vary from SCE's current forecast in a range of $18 billion to $21.5 billion based on the average variability experienced in 2008 and 2009 of 16.5%. Applying the two-year historical average variability to the current forecast, the estimated capital investments for the next five years would vary in the range of: 2010 – $3.3 billion to $4.0 billion; 2011 – $3.7 billion to $4.4 billion; 2012 – $3.9 billion to $4.6 billion; 2013 – $3.6 billion to $4.3 billion; and 2014 –

$3.5 billion to $4.2 billion. SCE's 2009 capital spending and 2010 – 2014 capital spending forecast is set forth in the following table:

*(in millions)*

|  | 2009 Actual | 2010 | 2011 | 2012 | 2013 | 2014 |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Distribution | $1,732 | $1,855 | $1,906 | $2,387 | $2,324 | $2,446 |
| Transmission | 490 | 652 | 1,300 | 1,391 | 1,179 | 1,020 |
| Generation | 585 | 789 | 528 | 580 | 548 | 538 |
| EdisonSmartConnectTM | 123 | 496 | 491 | 74 | 34 | 15 |
| Solar Rooftop Program | 8 | 191 | 197 | 203 | 209 | 150 |
| Total Estimated Capital Investments1 | $2,938 | $3,983 | $4,422 | $4,635 | $4,294 | $4,169 |

1

Included in SCE's capital investment plan are projected environmental capital expenditures of $510 million in 2010 and approximately $2.8 billion for the period 2011 through 2014. The projected environmental capital expenditures are to comply with laws, regulations, and other nondiscretionary requirements.

### Distribution Projects

Distribution investments include projects and programs to meet customer load growth requirements, reliability and infrastructure replacement needs, information and other technology and related facility requirements for 2010 – 2014. Of the total investments, $3.8 billion are recovered through rates authorized in SCE's 2009 CPUC GRC decision, and $7.1 billion are subject to review and approval in the 2012 CPUC GRC proceeding.

### Transmission Projects

SCE's has planned the following significant transmission projects:

Tehachapi Transmission Project – An eleven segment project consisting of new and upgraded transmission lines and associated substations built primarily to enable the development of renewable energy generated primarily by wind farms in remote areas of eastern Kern County, California. Tehachapi segments one, two and a portion of segment three were completed and placed in service in 2009. The remainder of segment three is under construction and expected to be placed in service over the period 2011 – 2013. SCE continues to seek the necessary licensing permits for Tehachapi segments four through eleven, which are expected to be placed in service between 2011 and 2015, subject to receipt of licensing and regulatory approvals. SCE expects to invest $1.7 billion over the period 2010 – 2014 on this project. In November 2007, the FERC approved a 125 basis point ROE project adder, a 50 basis point incentive for CAISO participation, recovery of ROE and incentive adders during the CWIP phase, and recovery of abandoned plant costs (if any) on this project. SCE's requested 100% CWIP cost recovery is still pending FERC approval.

Devers-Colorado River Project – A transmission project, also known as the California portion of the DPV2 project, involving the installation of a high voltage (500 kV) transmission line from Romoland, California to the Colorado River switchyard west of Blythe, California. The project is currently expected to be placed in service in 2013, subject to final licensing and regulatory approvals. Over the period 2010 – 2014, SCE expects to invest $658 million for this project in California. The DPV2 project includes the transmission line through a portion of western Arizona, although SCE has deferred the Arizona portion while it continues to evaluate its transmission needs in western Arizona. In November 2007, the FERC approved a 125 basis point ROE project adder, a 50 basis point incentive for CAISO participation, recovery of ROE and incentive adders during the CWIP phase, and recovery of abandoned plant costs (if any) on the DPV2 project. Various parties have challenged SCE's ability to receive the DPV2 incentives.

Eldorado-Ivanpah Transmission Project – A proposed 220/115 kV substation near Primm, Nevada and an upgrade of a 35-mile portion of an existing transmission line connecting the new substation to the Eldorado Substation, near Boulder City, Nevada. The project is currently expected to be placed in service in 2013, subject to necessary licensing and regulatory approvals. SCE expects to invest $469 million over the period 2010 – 2014 on this project. In December 2009, the FERC granted conditional approval of incentives on the project which included a 100 basis point ROE project adder, a 50 basis point incentive for CAISO participation, recovery of the ROE and incentive adders during the CWIP phase, and recovery of abandoned plant costs (if any) on this project. The approval was conditioned upon the approval of the CAISO and its finding that the project ensures reliability or reduces the cost of delivered power.

Other capital investments consisting of $2.7 billion for other transmission to maintain reliability and expand capability of its infrastructure over the period 2010 – 2014. Included in these capital investments are other renewable projects in support of the 33% renewable procurement target.

### Generation Projects

San Onofre Steam Generator Replacement Project – In February 2010, SCE installed and placed in service the first two of the four planned steam generators. San Onofre Unit 2 is expected to be back online in March 2010. The steam generator replacement project is intended to enable San Onofre to operate until the end of its initial license period in 2022, and beyond if license renewal proves feasible. SCE expects to spend $270 million over the period 2010 – 2011 on this project.

### EdisonSmartConnectTM

SCE's EdisonSmartConnectTM project involves installing state-of-the-art "smart" meters in approximately 5.3 million households and small businesses through its service territory. In March 2008, SCE was authorized by the CPUC to recover $1.63 billion in customer rates for the deployment phase of EdisonSmartConnectTM. In 2009, SCE began full deployment of meters to all residential and small business customers under 200 kW and anticipates completion of the deployment in 2012. SCE expects to spend $1.1 billion over the period 2010 – 2014 on this project, with expenditures in 2013 and 2014 primarily related to post-deployment customer additions.

### Solar Rooftop Program

In June 2009, the CPUC approved SCE's Solar Photovoltaic Program to develop up to 250 MW of utility-owned Solar Photovoltaic generating facilities generally ranging in size from

1 to 2 MW each, on commercial and industrial rooftops and other space in SCE's service territory. The decision allows SCE to recover its reasonable costs in customer rates and its CPUC-authorized rate of return on its investment. SCE expects to spend $1.0 billion over the period 2010 – 2014 on this project.

### Regulatory Proceedings

### Cost of Capital Mechanism

In 2009, the CPUC granted SCE's request to forgo an expected 2010 cost of capital increase under the annual adjustment provision and extended SCE's existing capital structure and authorized rate of return of 11.5% through December 2012, absent any future potential annual adjustments. The revised mechanism will be subject to CPUC review in 2012 for the cost of capital set for 2013 and beyond.

### 2010 FERC Rate Case

On September 30, 2009, FERC issued an order allowing SCE to implement its proposed 2010 rates, subject to refund and settlement procedures, effective March 1, 2010. The proposed rates would increase SCE's revenue requirement by $107 million, or 24%, over the 2009 revenue requirement primarily due to an increase in transmission rate base and would result in an approximate 1% increase to SCE's overall system average rate. SCE is currently in settlement negotiations with the FERC staff and multiple intervenors.

### Dividend Restrictions

The CPUC regulates SCE's capital structure and 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 December 31, 2009, SCE's 13-month weighted-average common equity component of total capitalization was 49.8% resulting in the capacity to pay $271 million in additional dividends.

During 2009, SCE made a total of $300 million of dividend payments to its parent, Edison International and declared a $100 million dividend to Edison International which was paid in January 2010. Future dividend amounts and timing of distributions are dependent upon several factors including the actual level of capital investments, operating cash flows and earnings.

### Income Tax Matters

SCE is included in the consolidated federal and combined state income tax returns of Edison International and participates in tax-allocation payments with other subsidiaries of Edison International in accordance with the terms of intercompany tax allocation agreements among the Edison International affiliated companies. Significant activities occurred during 2009 that will have an impact on SCE's future cash flows.

### Global Settlement

On May 5, 2009, Edison International and the IRS finalized the terms of a Global Settlement that resolved all of SCE's federal income tax disputes and affirmative claims through tax year 2002. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 4. Income Taxes" for further discussion.

SCE expects that the Global Settlement will result in a positive cash impact over time. The following table provides the approximate cash flow expected over time:

*(in millions)*

|  |  |
| --- | ---: |
| Taxes settled through December 31, 2009 | $875 |
| Estimated future net tax payments | (229) |
| Cash flow expected over time | $646 |

### Repair Deductions

During the fourth quarter of 2009, Edison International made a voluntary election to change its tax accounting method for certain repair costs incurred on SCE's transmission, distribution and generation assets. The change in tax accounting method resulted in an initial $192 million cash benefit realized in the fourth quarter of 2009. This benefit was based primarily on an estimated cumulative catch-up deduction for certain repair costs that were previously capitalized and depreciated over the tax depreciable life of the property. Additional information and analysis is required to determine the actual deduction that will ultimately be reflected on the 2009 income tax return (due to be filed in September 2010) which may result in additional cash benefits. The current income tax benefit from the change in accounting for repair costs represents a timing difference which will reverse over the remaining tax life of the assets. This method change did not impact SCE's 2009 results of operations. Recovery of the future increase in income taxes related to this matter is expected to be addressed in SCE's 2012 GRC. Due to the uncertainty over this recovery, SCE did not recognize an earnings benefit or regulatory asset in 2009.

### Margin and Collateral Deposits

Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. Collateral requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments, and other factors. Future collateral requirements may be higher (or lower) than requirements at December 31, 2009, 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.

Certain of these power contracts contain a provision that requires 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 illustrates the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of December 31, 2009.

*(in millions)*

|  |  |
| --- | ---: |
| Collateral posted as of December 31, 20091 | $18 |
| Incremental collateral requirements resulting from a potential downgrade of SCE's credit rating to below investment grade | 265 |
| Total posted and potential collateral requirements2 | $283 |

1

Collateral posted consisted of $6 million in cash reflected in "Margin and collateral deposits" on the consolidated balance sheets and $12 million in letters of credit.

2

Total posted and potential collateral requirements may increase by an additional $62 million, based on SCE's forward position as of December 31, 2009, due to adverse market price movements over the remaining life of the existing contracts using a 95% confidence level.

In the table above, there was zero collateral posted as of December 31, 2009 related to derivative liabilities, and $4 million of incremental collateral requirements related to derivative liabilities.

SCE's incremental collateral requirements are expected to be met from liquidity available from cash on hand and available capacity under SCE's credit facilities, discussed above.

### Historical Consolidated Cash Flow

This section discusses consolidated cash flows from operating, financing and investing activities.

### Condensed Consolidated Statement of Cash Flows

*(in millions)*

|  | 2009 | 2008 | 2007 |
| --- | ---: | ---: | ---: |
| Cash flows provided by operating activities | $4,069 | $1,622 | $2,973 |
| Cash flows provided (used) by financing activities | (1,999) | 2,024 | (438) |
| Net cash used by investing activities | (3,219) | (2,287) | (2,366) |
| Net increase (decrease) in cash and equivalents | $(1,149) | $1,359 | $169 |

#### Cash Flows Provided by Operating Activities

The $2.4 billion increase in 2009 cash flows provided by operating activities over 2008 was primarily due to the following:

$875 million cash inflow due to the receipt of tax-allocation payments due to Global Settlement related to the settlement of affirmative claims; a portion of which is timing and will be payable in future periods (See "Item 8. SCE Notes to Consolidated Financial Statements—Note 4. Income Taxes" for further discussion).

$468 million net cash inflow due to the increase in balancing account cash flows comprised of:

$1.3 billion net cash inflow due to the increase in ERRA balancing account cash flows (collections of approximately $450 million in 2009, compared to refunds of approximately $840 million in 2008). The ERRA balancing account was over-collected by $46 million, under-collected by $406 million and over-collected by $433 million at December 31, 2009, 2008, and 2007, respectively; partially offset by

$820 million net cash outflow related to all other regulatory balancing accounts which was primarily due to increased spending in 2009 compared to 2008 for public purpose and solar initiative programs and increased pension and PBOP contributions. In addition, a $200 million refund payment was received in 2008 related to public purpose programs.

$250 million cash inflow benefit related to the American Recovery and Reinvestment Act of 2009 50% bonus depreciation provision.

$192 million cash inflow benefit related to the change in its tax accounting method for certain repair costs incurred on SCE's transmission, distribution and generation assets.

Higher cash inflow due to the increase in pre-tax income primarily driven by higher authorized revenue requirements resulting from the implementation of the 2009 CPUC and FERC GRC decisions.

Timing of cash receipts and disbursements related to working capital items.

The $1.3 billion decrease in 2008 cash flows provided by operating activities over 2007 was primarily due to the following:

$295 million net cash outflow due to the decrease in balancing account cash flows comprised of:

$745 million net cash outflow due to the decrease in ERRA balancing account cash flows (refunds of approximately $840 million in 2008, compared to refunds of approximately $95 million in 2007). The ERRA balancing account was under-collected by $406 million, over-collected by $433 million, and over-collected by $526 million at December 31, 2008, 2007, and 2006, respectively; partially offset by

$450 million net cash inflow related to all other regulatory balancing accounts which was primarily due a $200 million refund payment received in 2008 related to public purpose programs, $100 million refunded to ratepayers as a result of SCE's PBR decision, and a net $150 million in other balancing account overcollections.

$240 million cash outflow due to the elimination of amounts collected in 2008 for the repayment of SCE rate reduction bonds. These bonds were fully repaid in December 2007. The bond payment is reflected in financing activities.

Timing of cash receipts and disbursements related to working capital items, including tax-related items.

#### Cash Flows Provided (Used) by Financing Activities

Cash provided (used) by financing activities mainly consisted of net repayments of short-term debt and long-term debt issuances (payments).

Cash used by financing activities for 2009 was $2.0 billion consisting of the following significant events:

Repaid a net $1.9 billion of short-term debt, primarily due to the improvement in economic conditions that occurred during the second half of 2008.

Paid $300 million in dividends to Edison International.

Purchased $219 million of two issues of tax-exempt pollution control bonds and converted the issues to a variable rate structure. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

Repaid $150 million of first and refunding mortgage bonds.

Issued $500 million of first refunding mortgage bonds due in 2039 and $250 million of first and refunding mortgage bonds due in 2014. The bond proceeds were used for general corporate purposes and to finance fuel inventories.

Cash provided by financing activities for 2008 was $2.0 billion consisting of the following significant events:

Borrowed $1.4 billion under the line of credit to increase SCE's cash position to meet working capital requirements, if needed, during uncertainty over economic conditions during the second half of 2008.

Issued $600 million of first refunding mortgage bonds due in 2038. The proceeds were used to repay SCE's outstanding commercial paper of approximately $426 million and for general corporate purposes.

Issued $500 million of 5.75% first and refunding mortgage bonds due in 2014. The proceeds were used for general corporate purposes.

Issued $400 million of 5.50% first and refunding mortgage bonds due in 2018. The proceeds were used to repay SCE's outstanding commercial paper of approximately $110 million and borrowings under the credit facility of $200 million, as well as for general corporate purposes.

Paid $325 million in dividends to Edison International.

Purchased $212 million of its auction rate bonds, converted the issue to a variable rate structure, and terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled.

Paid $36 million for the purchase and delivery of outstanding common stock for settlement of stock based awards (facilitated by a third party).

Cash used by financing activities in 2007 was $438 million consisting of the following significant events:

Repaid $246 million of the remaining outstanding balance of its rate reduction bonds.

Paid $135 million in dividends to Edison International.

Paid $135 million for the purchase and delivery of outstanding common stock for settlement of stock based awards (facilitated by a third party).

Issued $500 million of short-term debt to fund interim working capital requirements.

#### Net Cash Used by Investing Activities

Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $3.0 billion, $2.3 billion and $2.3 billion for 2009, 2008 and 2007, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $199 million, $7 million and $133 million for 2009, 2008 and 2007, respectively.

### Contractual Obligations and Contingencies

### Contractual Obligations

SCE's contractual obligations as of December 31, 2009, for the years 2010 through 2014 and thereafter are estimated below.

*(in millions)*

|  | Total | Less than 1 year | 1 to 3 years | 3 to 5 years | More than 5 years |
| --- | ---: | ---: | ---: | ---: | ---: |
| Long-term debt maturities and interest1 | $13,487 | $604 | $708 | $1,716 | $10,459 |
| Operating lease obligations2 | 12,076 | 779 | 1,550 | 1,557 | 8,190 |
| Capital lease obligations3 | 235 | 8 | 11 | 13 | 203 |
| Purchase obligations4: |  |  |  |  |  |
| Fuel supply contract payments | 1,384 | 180 | 322 | 291 | 591 |
| Purchased-power capacity payments | 6,837 | 395 | 1,024 | 1,384 | 4,034 |
| Other commitments | 45 | 6 | 12 | 13 | 14 |
| Employee benefit plans contributions5 | 124 | 124 | — | — | — |
| Total6,7 | $34,188 | $2,096 | $3,627 | $4,974 | $23,491 |

1

For additional details, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 3. Liabilities and Lines of Credit." Amount includes interest payments totaling $7 billion over applicable period of the debt.

2

At December 31, 2009, minimum operating lease payments were primarily related to power contracts, vehicles, office space and other equipment. For further discussion, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies."

3

At December 31, 2009, minimum capital lease payments were primarily related to power purchased contracts that meet the requirements for capital leases. For further discussion, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies."

4

For additional details, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies."

5

Amount includes estimated contributions to the pension and PBOP plans. The estimated contributions for SCE are not available beyond 2010. Due to the volatile market conditions experienced in 2008 and the decline in value of SCE's trusts, SCE's contributions increased in 2009. Based on pension and PBOP plan assets at December 31, 2009 SCE expects a decrease in contributions in 2010 but cannot predict or estimate contributions beyond 2010. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 5. Compensation and Benefit Plans" for further information.

6

At December 31, 2009, SCE had a total net liability recorded for uncertain tax positions of $458 million, which is excluded from the table. SCE cannot make reliable estimates of the cash flows by period due to uncertainty surrounding the timing of resolving these open tax issues with the IRS.

7

The contractual obligations table does not include derivative obligations and asset retirement obligations, which are discussed in "Item 8. SCE Notes to Consolidated Financial Statements—Note 2. Derivative Instruments and Hedging Activities," and "Item 8. SCE Notes to Consolidated Financial Statements—Note 8. Property and Plant," respectively.

### Contingencies

SCE has contingencies related to FERC transmission incentives and CWIP proceedings, the Navajo Nation Litigation, nuclear insurance, and spent nuclear fuel, which are discussed in "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies."

#### Environmental Remediation

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

As of December 31, 2009, SCE identified 23 sites for remediation and recorded an estimated minimum liability of $39 million of which $5 million was related to San Onofre. SCE expects to recover 90% of its remediation costs at certain sites. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. 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. SCE uses derivative financial instruments, as appropriate, to manage its market risks.

### Interest Rate Risk

SCE is exposed to changes in interest rates primarily as a result of its financing and short-term investing activities used for liquidity purposes, to fund business operations and to fund capital investments. The nature and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. In addition, SCE's authorized return on common equity (11.5% for 2010, 2009 and 2008), which is established in SCE's cost of capital proceeding, is set on the basis of forecasts of interest rates and other factors. Variances in actual financing costs compared to authorized financing costs impact earnings either positively or negatively.

At December 31, 2009, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $7.2 billion, compared to a carrying value of $6.7 billion. A 10% increase in market interest rates would have resulted in a $345 million decrease in the fair market value of SCE's long-term debt. A 10% decrease in market interest rates would have resulted in a $380 million increase in the fair market value of SCE's long-term debt.

### Commodity Price Risk

SCE is exposed to commodity price risk which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces ratepayer exposure to variability in market prices related to SCE's power and gas activities. SCE recovers its related hedging costs, through the ERRA balancing account, subject to reasonableness review, and as a result, exposure to commodity price is not expected to impact earnings, but may impact cash flows.

Electricity price exposure arises from the following activities:

Energy purchased and sold in the MRTU market as a result of differences between SCE's load requirements versus the amount of energy delivered from SCE's generating facilities, existing bilateral contracts, and CDWR contracts allocated to SCE. In March 2009, SCE began participating in the MRTU day-ahead and real-time markets which uses nodal locational marginal prices and is subject to price caps. The volume purchased in the MRTU market may vary due to outages at SCE's generating facilities, new or expired bilateral contracts and changes in customer demand resulting from, among other things, growth or decline in customer base and weather.

Natural gas price exposure arises from the following activities:

Natural gas purchased for generation at Mountainview and peaker plants. The volume purchased may vary due to outages and dispatch based on SCE's management of its load requirements.

Bilateral contracts where pricing is based on natural gas prices. Contract energy prices for some QFs are based on the monthly index price of natural gas delivered at the Southern California border. Approximately 37% of SCE's purchased power supply is subject to natural gas price volatility.

Power contracts in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements. Volume may vary due to dispatch based on SCE's management of its load requirements or if the existing CDWR power contracts, which have related natural gas supply contracts, are novated or replaced and SCE becomes a party to such contracts. SCE is currently unable to predict which or how many existing CDWR contracts will be novated or replaced. However, due to the expected recovery through regulatory mechanisms these power procurement expenses are not expected to affect earnings.

### Natural Gas and Electricity Price Risk

SCE's hedging program reduces ratepayer exposure to variability in market prices. As a part of this program, SCE enters into energy options, swaps, forward arrangements, tolling arrangements, and congestion revenue rights (CRRs). The transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. In addition, SCE's risk management committee monitors exposure related to these instruments.

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale or are classified as VIEs or leases. The derivative instrument fair values are marked to market at each reporting period. Any fair value changes are expected to be recovered from or refunded to customers through regulatory mechanisms and therefore, SCE's fair value changes have no impact on purchased-power expense or earnings. SCE does not use hedge accounting for these transactions due to this regulatory accounting treatment.

#### Fair Value of Derivative Instruments

SCE follows the authoritative accounting guidance for fair value measurements. For further discussion see "Item 8. SCE Notes to Consolidated Financial Statements—Note 10. Fair Value Measurements." The following table summarizes the fair values of outstanding derivative instruments used at SCE to mitigate its exposure to spot market prices:

*(in millions)*

|  | December 31, 2009 Assets | Liabilities | December 31, 2008 Assets | Liabilities |
| --- | ---: | ---: | ---: | ---: |
| Electricity options, swaps and forward arrangements | $1 | $25 | $7 | $15 |
| Natural gas options, swaps and forward arrangements | 86 | 171 | 80 | 304 |
| Congestion revenue rights and firm transmission rights1 | 217 | — | 81 | — |
| Tolling arrangements2 | 43 | 402 | 63 | 647 |
| Netting and collateral | — | — | — | (72) |
| Total | $347 | $598 | $231 | $894 |

1

The CAISO created a commodity, CRRs, which entitles the holder to receive (or pay) the value to transmission congestion between specific nodes, acting as an economic hedge against transmission congestion charges. In September 2007 and November 2008, the CAISO allocated CRRs for the period April 2009 through December 2017 based on SCE's load requirements. In addition, SCE participated in CAISO auctions for the procurement of additional CRRs. The CRRs meet the definition of a derivative.

2

In compliance with a CPUC mandate, SCE held an open, competitive solicitation that produced agreements with different project developers who have agreed to construct new southern California generating resources. The contracts provide for fixed capacity payments as well as pricing for energy delivered based on a heat rate and contractual operation and maintenance prices. However, due to uncertainty regarding the availability of required emission credits, some of the generating resources may not be constructed and the contracts associated with these resources could therefore terminate, at which time SCE would no longer account for these contracts as derivatives.

*(in millions)*

|  |  |
| --- | ---: |
| Fair value of derivative contracts, net at January 1, 2009 | $(663) |
| Total realized/unrealized net gains: |  |
| Included in regulatory assets and liabilities1 | 126 |
| Purchases and settlements, net | 358 |
| Netting and collateral | (72) |
| Fair value of derivative contracts, net at December 31, 2009 | $(251) |

1

Due to regulatory mechanisms, SCE's realized and unrealized gains and losses are recorded as regulatory assets and liabilities.

SCE recognizes realized gains and losses on derivative instruments as purchased power expense and recovers these costs from ratepayers. As a result, realized gains and losses do not affect earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are deferred and are not recognized as purchased power expense, and therefore do not affect earnings. Realized losses on economic hedging activities were primarily due to settled natural gas prices being significantly lower than transactional average fixed prices. Unrealized gains on economic hedging activities were primarily due to changes in the expected forward prices of the CRRs, the rising volatilities related to SCE's contracts from the new generation contracts, and settlement of gas contracts during the period.

The following table summarizes the increase or decrease to the fair values of outstanding derivative financial instruments as of December 31, 2009, if the electricity prices or gas prices were changed while leaving all other assumptions constant:

*(in millions)*

|  | Increase in electricity prices by 10% | Decrease in electricity prices by 10% | Increase in gas prices by 10% | Decrease in gas prices by 10% |
| --- | ---: | ---: | ---: | ---: |
| Electricity options, swaps and forward arrangements | $49 | $(57) | $(28) | $43 |
| Natural gas options, swaps and forward arrangements | — | — | 113 | (97) |
| Congestion revenue rights and firm transmission rights | 8 | (6) | — | — |
| Tolling arrangements | 475 | (385) | (207) | 288 |

### Credit Risk

As part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments. However, all of the contracts that SCE has entered into with counterparties are either entered into under SCE's short-term or long-term procurement plan which has been approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may temporarily affect cash flows.

To manage credit risk, SCE looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. SCE measures, monitors and mitigates credit risk to the extent possible. SCE manages the credit risk on the portfolio 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. SCE's risk management committee regularly reviews and evaluates procurement credit exposure and approves credit limits for transacting with counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate. SCE anticipates future delivery of energy by counterparties, but given the current market condition, SCE cannot predict whether the counterparties will be able to continue operations and deliver energy under the contractual agreements.

The 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 balance sheet. 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.

As of December 31, 2009, 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 | December 31, 2009 Exposure2 | Collateral | Net Exposure |
| --- | ---: | ---: | ---: |
| A or higher | $83 | $(4) | $79 |
| A- | 221 | — | 221 |
| BBB+ | 1 | — | 1 |
| BBB | 1 | — | 1 |
| BBB- | — | — | — |
| Below investment grade and not rated | — | — | — |
| Total | $306 | $(4) | $302 |

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 purchase and sales and non- derivative contractual commitments that are not recorded on the consolidated balance sheet, except for any related net accounts receivable.

The credit risk exposure set forth in the above table is comprised of $7 million of net account receivables and $299 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.

The CAISO comprises 72% of the total net exposure above and is mainly related to the CRRs' fair value (see "—Commodity Price Risk" for further information).

### CRITICAL ACCOUNTING ESTIMATES AND POLICIES

The accounting policies described below are considered critical to obtaining an understanding of SCE's consolidated financial statements because their application requires the use of significant estimates and judgments by management in preparing SCE's consolidated financial statements. Management estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the estimate requires significant assumptions and changes in the estimate or if different estimates that could have been selected had been used could have a material impact on SCE's results of operations or financial position. For more information on SCE's accounting policies, see "Item 8. SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies."

### Rate Regulated Enterprises

*Nature of Estimate Required.* SCE follows the accounting principles for rate-regulated enterprises which are required for entities whose rates are set by regulators at levels intended to recover the estimated costs of providing service, plus a return on net investment, or rate base. Regulators may also impose certain penalties or grant certain incentives. Due to timing and other differences in the collection of revenue, these principles allow a cost that would otherwise be charged as an expense by a unregulated entity to be capitalized as a regulatory asset if it is probable that such cost is recoverable through future rates; conversely the principles allow creation of a regulatory liability for amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred.

*Key Assumptions and Approach Used.* SCE's management assesses at the end of each reporting period whether regulatory assets are probable of future recovery by considering factors such as the current regulatory environment, the issuance of rate orders on recovery of the specific or a similar incurred cost to SCE or other rate-regulated entities in California, and other factors that would indicate that the regulator will treat an incurred cost as allowable for rate-making purposes. Using these factors, management has determined that existing regulatory assets and liabilities are probable of future recovery or settlement. This determination reflects the current regulatory climate in California and is subject to change in the future.

*Effect if Different Assumption Used.* Significant management judgment is required to evaluate the anticipated recovery of regulatory assets, the recognition of incentives and revenue subject to refund, as well as the anticipated cost of regulatory liabilities or penalties. If future recovery of costs ceases to be probable, all or part of the regulatory assets and liabilities would have to be written off against current period earnings. At December 31, 2009, the consolidated balance sheets included regulatory assets of $4.3 billion and regulatory liabilities of $3.7 billion. If different judgments were reached on recovery of costs and timing of income recognition, SCE's earnings and cash flows may vary from the amounts reported.

### Income Taxes

*Nature of Estimates Required.* As part of the process of preparing its consolidated financial statements, SCE is required to estimate its income taxes for each jurisdiction in which it operates. This process involves estimating actual current period tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within SCE's consolidated balance sheet.

SCE takes certain tax positions it believes are applied in accordance with the applicable tax laws. However, these tax positions are subject to interpretation by the IRS, state tax authorities and the courts. SCE determines its uncertain tax positions in accordance with the authoritative guidance.

*Key Assumptions and Approach Used.* Accounting for tax obligations requires management judgment. Management uses judgment in determining whether the evidence indicates it is more likely than not, based solely on the technical merits, that a tax position will be sustained, and to determine the amount of tax benefits to be recognized. Judgment is also used in determining the likelihood a tax position will be settled and possible settlement outcomes. In assessing its uncertain tax positions SCE considers, among others, the following factors: the facts and circumstances of the position, regulations, rulings, and case law, opinions or views of legal counsel and other advisers, and the experience gained from similar tax positions. Management evaluates uncertain tax positions at the end of each reporting period and makes adjustments when warranted based on changes in fact or law.

*Effect if Different Assumptions Used.* Actual income taxes may differ from the estimated amounts which could have a significant impact on the liabilities, revenue and expenses recorded in the financial statements. Edison International continues to be under audit or subject to audit for multiple years in various jurisdictions. Significant judgment is required to determine the tax treatment of particular tax positions that involve interpretations of complex tax laws. A tax liability has been recorded with respect to tax positions in which the outcome is uncertain and the effect is estimable. Such liabilities are based on judgment and a final determination could take many years from the time the liability is recorded. Furthermore, settlement of tax positions included in open tax years may be resolved by compromises of tax positions based on current factors and business considerations that may result in material adjustments to income taxes previously estimated. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 4. Income Taxes" for a further discussion on income taxes.

### Nuclear Decommissioning – ARO

*Nature of Estimate Required.* Regulations by the NRC require SCE to decommission its nuclear power plants which is expected to begin after the plants' operating licenses expire. In accordance with authoritative guidance, SCE is required to record an obligation to decommission its nuclear facilities. Nuclear decommissioning costs are recovered in utility rates through contributions that are reviewed every three years by the CPUC. Due to regulatory accounting treatment, nuclear decommissioning activities are not expected to affect SCE earnings.

*Key Assumptions and Approach Used.* The liability to decommission SCE's nuclear power facilities is based on site-specific studies performed in 2005 which estimate that SCE will spend approximately $11.5 billion through 2049 to decommission its active nuclear facilities. Decommissioning cost estimates are updated in each Nuclear Decommissioning Triennial Proceeding. A site-specific study was performed in 2008 which is currently awaiting CPUC approval. Once a CPUC decision is rendered the updated cost estimate is established and accreted over the lives of San Onofre and Palo Verde. The current estimate is based on the following assumptions from the 2005 site-specific study:

Decommissioning Costs. The estimated costs for labor, dismantling and disposal costs, energy and miscellaneous costs.

Escalation Rates. Annual escalation rates are used to convert the decommissioning cost estimates in base year dollars to decommissioning cost estimates in future-year dollars. Escalation rates are primarily used for labor, material, equipment, and low level radioactive waste burial costs. SCE's current estimate is based on SCE's decommissioning cost methodology used for ratemaking purposes, escalated at rates ranging from 1.7% to 7.5% (depending on the cost element) annually.

Timing. Cost estimates are based on an assumption that decommissioning will commence promptly after the current NRC operating licensees expire. The operating licenses currently expire in 2022 for San Onofre Units 2 and 3, and in 2024, 2025 and 2027 for the Palo Verde units.

Spent Fuel Dry Storage Costs. Cost estimates are based on an assumption that the DOE will begin to take spent fuel in 2015, and will remove the last spent fuel from the San Onofre and Palo Verde sites by 2045 and 2047, respectively. Costs for spent fuel monitoring are included until 2045 and 2047, respectively.

Changes in decommissioning technology, regulation, and economics. The current cost studies assume the use of current technologies under current regulations and at current cost levels.

*Effect if Different Assumptions Used.* The ARO for decommissioning SCE's active nuclear facilities was $3.1 billion and $2.9 billion at December 31, 2009 and 2008, respectively. Changes in the estimated costs or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission these facilities which could have a material affect on the recorded liability and related regulatory asset. The following table illustrates the increase to the ARO and regulatory asset if the escalation rate or discount rate was adjusted while leaving all other assumptions constant:

*(in millions)*

|  | Increase to ARO and regulatory asset at December 31, 2009 |
| --- | ---: |
| Uniform increase in escalation rate of 25 basis points | $20 |
| Decrease in discount rate of 25 basis points | $2 |

58

### Pensions and Postretirement Benefits Other than Pensions

*Nature of Estimate Required.* Authoritative accounting guidance requires companies to recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets and liabilities in the balance sheet; the assets and/or liabilities are normally offset through other comprehensive income (loss). In accordance with authoritative guidance for rate-regulated enterprises, regulatory assets and liabilities are recorded instead of charges and credits to other comprehensive income (loss) for its postretirement benefit plans that are recoverable in utility rates. SCE has a fiscal year-end measurement date for all of its postretirement plans.

*Key Assumptions of Approach Used.* Pension and other postretirement obligations and the related effects on results of operations are calculated using actuarial models. Two critical assumptions, discount rate and expected return on assets, are important elements of plan expense and liability measurement. Additionally, health care cost trend rates are critical assumptions for postretirement health care plans. These critical assumptions are evaluated at least annually. Other assumptions, which require management judgment, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

As of December 31, 2009, SCE's pension plans had a $3.4 billion benefit obligation and total expense for these plans was $107 million for 2009. As of December 31, 2009, SCE's PBOP plans had a $2.0 billion benefit obligation and total expense for these plans was $75 million for 2009. The following are critical assumptions used to determine expense for pension and other postretirement benefit obligations as of December 31, 2009:

*(in millions)*

|  | Pension Plans | Postretirement Benefits Other than Pensions |
| --- | ---: | ---: |
| Discount rate1 | 6.25% | 6.25% |
| Expected long-term return on plan assets2 | 7.5% | 7.0% |
| Assumed health care cost trend rates3 | — | 8.75% |

1

The discount rate enables SCE to state expected future cash flows at a present value on the measurement date. SCE selects its discount rate by performing a yield curve analysis. This analysis determines the equivalent discount rate on projected cash flows, matching the timing and amount of expected benefit payments. Two corporate yield curves were considered, Citigroup and AON.

2

To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations are considered, as well as historical and expected returns on plan assets. A portion of PBOP trusts asset returns are subject to taxation, so the 7.0% rate of return on plan assets above is determined on an after-tax basis. Actual time-weighted, annualized returns on the pension plan assets were 24.4%, 3.7% and 4.1% for the one-year, five-year and ten-year periods ended December 31, 2009, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 23.6%, 1.9%, and 1.5% over these same periods. Accounting principles provide that differences between expected and actual returns are recognized over the average future service of employees.

3

The health care cost trend rate is 8.75% for 2009, gradually declining to 5.5% for 2016 and beyond.

Pension expense is recorded for SCE based on the amount funded to the trusts, as calculated using an actuarial method required for rate-making purposes, in which the impact of market volatility on plan assets is recognized in earnings on a more gradual basis. Any difference between pension expense calculated in accordance with rate-making methods and pension expense calculated in accordance with authoritative accounting guidance for pension is accumulated as a regulatory asset or liability, and will, over time, be recovered from or returned to customers. As of December 31, 2009, this cumulative difference amounted to a regulatory asset of $24 million, meaning that the accounting method has recognized $24 million more in expense than the rate-making method since implementation of authoritative guidance for employers' accounting for pensions in 1987.

SCE's pension and PBOP plans are subject to limits established for federal tax deductibility. SCE funds its pension and PBOP plans in accordance with amounts allowed by the CPUC. Executive pension plans have no plan assets.

*Effect if Different Assumptions Used.* Changes in the estimated costs or timing of pension and other postretirement benefit obligations, or in the assumptions and judgments used by management underlying these estimates, could have a material affect on the recorded expenses and liabilities. SCE's total annual contributions are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to SCE's total annual expense.

A one percentage point increase in the discount rate would decrease the projected benefit obligation for pension by $262 million. A one percentage point decrease in the discount rate would increase the projected benefit obligation for pension by $267 million. A one percentage point increase in the expected rate of return on pension plan assets would decrease the expense by $22 million.

A one percentage point increase in the discount rate for PBOP would decrease the projected benefit obligation by $225 million. A one percentage point decrease in the discount rate for the PBOP would increase the projected benefit obligation by $254 million. A one percentage point increase in the expected rate of return on PBOP plan assets would decrease the expense by $12 million. Increasing the health care cost trend rate by one percentage point would increase the accumulated benefit obligation as of December 31, 2009 by $211 million and annual aggregate service and interest costs by $14 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated benefit obligation as of December 31, 2009 by $193 million and annual aggregate service and interest costs by $13 million.

### Accounting for Contingencies

*Nature of Estimates Required.* SCE records loss contingencies when it determines that the chance of a future event occurring is probable and when the amount of the loss can be reasonably estimated. Gain contingencies are recognized in the financial statements when they are realized.

*Key Assumptions and Approach Used.* The determination of a reserve for a loss contingency is based on management judgment and estimates with respect to the likely outcome of the matter, including the analysis of different scenarios. Liabilities are recorded or adjusted, when events or circumstances cause these judgments or estimates to change. In assessing whether a loss is a reasonable possibility, SCE may consider the following factors, among others: the nature of the litigation, claim or assessment, available information, opinions or views of legal counsel and other advisers, and the experience gained from similar cases. SCE provides disclosure for material contingencies when there is a reasonable possibility that a loss or an additional loss may be incurred.

*Effect if Different Assumptions Are Used.* Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and could have a significant impact on the liabilities, revenue and expenses recorded in the financial statements. See "Item 8. SCE Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies" for a discussion of contingencies.

### NEW ACCOUNTING GUIDANCE

New accounting guidance are discussed in "Item 8. SCE Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."

## Controls and procedures

As filed, 3,612 characters.

### Disclosure Controls and Procedures

SCE's management, under the supervision and with the participation of the company's Chief Executive Officer 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 Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, SCE's disclosure and procedures are effective.

SCE's management is responsible for establishing and maintaining adequate internal control over financial reporting (as that term is defined in Rule 13a-15(f) under the Exchange Act) for SCE. Under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, SCE's management conducted an evaluation of the effectiveness of SCE's internal control over financial reporting based on the framework set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under the COSO framework, SCE's management concluded that SCE's internal control over financial reporting was effective as of December 31, 2009.

### Change 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 13(a)-15(f) or 15(d)-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, SCE's internal control over financial reporting.

### Variable Interest Entities

SCE consolidates four variable interest entities under authoritative accounting guidance issued by the FASB, but does not control the operating activities of these entities or have the ability to dictate or modify the controls of these entities. Accordingly, the scope of evaluation of internal control over financial reporting does not include an evaluation of internal control over financial reporting for these variable interest entities. A summary of the key sub-totals of these entities is set forth in the following table (in millions):

| At December 31, | 2009 |
| --- | ---: |
| Total Assets | $398 |
| For the year ended December 31, |  |
| Revenue | $219 |
| Operating Expenses | $125 |
| Net Income Available for Common Stock | $— |

Accordingly, the conclusion regarding the effectiveness of internal control over financial reporting does not extend to the internal controls of such variable interest entities.

### Jointly Owned Utility Plant

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

### Management's Report on Internal Control Over Financial Reporting

SCE's management is responsible for establishing and maintaining adequate internal control over financial reporting (as that term is defined in Rule 13a-15(f) under the Exchange Act) for SCE. Under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, SCE's management conducted an evaluation of the effectiveness of SCE's internal control over financial reporting based on the framework set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on its evaluation under the COSO framework, SCE's management concluded that SCE's internal control over financial reporting was effective as of December 31, 2009.

Filed Mar 1, 2010.
Source: SEC EDGAR, the filing index for accession 0001047469-10-001605. Last ingested by Listed: Nov 7, 2026, 07:12 ET. No prices; not investment advice.