ML061210453

Annual Certified Financial Statement

ML061210453
Person / Time
Site:	Palo Verde, San Onofre
Issue date:	04/24/2006
From:	Scherer A Southern California Edison Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML061210453 (126)

Text

I SOUTHERN CALIFORNIA A. Edward Sciherer EDISON t Manager of Nuclear Regulatory Affairs An Dso\ I\'TERNATlOVAL' Company April 24, 2006 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D. C. 20555

Subject:

Docket Nos. 50-361, 50-362, 50-528, 50-529, and 50-530 Annual Certified Financial Statement San Onofre Nuclear Generating Station Units 2 and 3 Palo Verde Nuclear Generating Station Units 1, 2, and 3 Gentlemen:

SouthErn California Edison (SCE), as agent for the owners of the San Onofre Nuclear Generating Station Units 2 and 3 and SCE's 15.8% ownership share of Palo Verde Units 1, 2, and 3, submits the following documents in accordance with 10 CFR 140.21(e):

• 2006 Cash Flow statement which is from the consolidated financial statements included in SCE's 2005 Annual Report P SCE's Annual Report for the fiscal year ending December 31, 2005 He SCE's Annual Report to the Securities and Exchange Commission (Form 1OK) for the fiscal year ending December 31, 2005 If you have any questions or require further information about these documents, please contact me or Mr. Jack Rainsberry at 949-368-7420.

Sincerely, Enclosures (3) cc: B3. S. Mallett, Regional Administrator, NRC Region IV 4.Kalyanam, NRC Project Manager, San Onofre Units 2 and 3 C. C. Osterholtz, NRC Senior Resident Inspector, San Onofre Units 2 and 3 P.O. Bcx 128 San Clemente, CA 92672 949-363-7501 Fax 94S-368-7575 NoN

SOUTHERN CALIFORNIA EDISON COMPANY 2006 Internal Cash Flow Projection (Dollars in Millions) 2005 2006 Actual Projected Net Income After Taxes $749(

Dividends Paid $234 Rctained Earnings $515 ()

Adjustments:

Dcpreciation & Decommissioning $915 $1,079 NOt Deferred Taxes & ITC $34 $'264 Allowance for Funds Used During Construction ($39) f;42)

Total Adjustments $910 $1,:301 Internal Caish Flow $1,425 (1 Average Quarterly Cash Flow $356 (1 Percentage Ownership in All Nuclear Units:

San Onofre Nuclear Generating Station Units 2 & 3 o Southern California Edison Company 75.05%

o San Diego Gas & Electric Company 20.00%

o City of Anaheim 3.16%

o City of Riverside 1.79%

Palo Verde Nuclear Generating Station Units 1, 2 & 3 15.80%

Maximumrotal Contingent Liability for 2006:

San Onofre Nuclear Generating Station Unit 2 $15.00 (2)

San Onofre Nuclear Generating Station Unit 3 $15.00 (2)

Palo Verde Nuclear Generating Station Unit 1 $2.37 (3)

Palo Verde Nuclear Generating Station Unit 2 $2.37 (3)

Palo Verde Nuclear Generating Station Unit 3 $2.37 (3)

Total $37.11 (1) Company policy prohibits disclosure of financial data which will enable unauthorized persons to forecast earnings or dividends, unless assured confidentiality.

(2) The value represents 100% of the SONGS Annual Per Incident Contingent Liability.

(3) The value represents 15.8% (SCE's Share) of the Palo Verde Annual Per Incident Contingent Liability.

Southern California Edison Company Southern California Edison Company (SCE) is one of the nation's largest investor-owned electric utilities. Headquartered in Rosemead, California, SCE is a subsidiary of Edison International.

SCE, a 120-year-old electric utility, serves a 50,000-square-mile area of central, coastal and southern California.

Table of Contents 1 Management's Discussion and Analysis of Financial Condition and Results of Operations 36 Report of Independent Registered Public Accounting Firm 37 Consolidated Statements of Income 37 Consolidated Statements of Comprehensive Income 38 Consolidated Balance Sheets 40 Consolidated Statements of Cash Flows 41 Consolidated Statements of Changes in Common Shareholder's Equity 42 Notes to Consolidated Financial Statements 80 Quarterly Financial Data 81 Selected Financial and Operating Data: 2001 - 2005 82 Board of Directors 83 Management Team IBC Shareholder Information

Management's Discussion and Analysis of Financial Condition and Results of Operations -

.:;INTRODUCTION -

This MEanagement's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) contains "forward-looking statements".within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Southern California Edison Company's (SCE) current V expectal ions and projections about future events based on SCE's knowledge of present facts and ; ;

circumstances and assumptions about future events and include any statement that does not directly relate to a.historical or current fact. Other information distributed by SCE that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans,"

"probable,"."may," "will," "could," "wvould,' "should," and variations of such words and similar >.

expressions, or discussions of strategy or of plans, are intended to identify forvard-looking statements;.

Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact SCE, include, but are not limited to:

• the ability of SCE to recover its costs in a timely manner from its customers through regulated rates; decisions and other actions by the California Public Utilities Commission (CPUC) and other regulatory authorities'and delays in regulatory actions;

• market risks affecting SCE's energy procurement activities; ,

access to capital markets and the cost of capital;. . .

• changes in interest rates and rates of inflation;

• governmental, statutory, regulatory or administrative changes or initiatives affecting the'electricit-'

industry, including the market structure rules applicable to each market and environmental regulations that could require additional expenditures or otherwise affect the cost and manner of doing business; -  :

• . risks associated with operating nuclear and other power generating facilities, including operating risks, nuclear fuel storage, equipment failure, availability, heat rate and output;

• the availability of labor, equipment and materials;.

the 'ibility to obtain sufficient insurance, including insurance relating'to SCE's nuclair facilities;.

• effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards;  : - -  ::

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• the cost and availability of coal, natural gas, and fuel oil, nuclear fuel, and associated transportation;

• the a.bility to provide sufficient collateral in support of hedging activities and purchased power and fuel;  : - i .

general political, economic and business conditions; .;; . . ;

• weather conditions, natural disasters aild other unforeseen events; and '-

• changes in the fair value of investments and otherassets accounted for using fair valtue accounting.

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Additional information about risks and uncertainties, including more detail about the factors described above, alie discussed throughout this MD&A'and the "Risk Factors" section included in Part 1,Item LiA of SCE's annual report on Form 10-K. Readers are urged to read this entire annual report, including the information incorporated by reference,'and carefully consider the risks, uncertainties and other factors that'affect'SCE's business. Forvard-looking statements speak only as of the date they are made and SCE

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Management's Discussion and Analysis of Financial Condition and Results of Operations. -

is not obligated to publicly update or revise for vard-looking statements. Readers should review future reports filed by SCE with the Securities and Exchange Commission.

The MD&A is presented in l I major sections: (1) Management overview; (2) Liquidity; (3) Regulatory Matters; (4) Other'Developments; (5) Market Risk Exposures; (6) Results of Operations and Historical:

Cash Flow Analysis; (7) Dispositions and Discontinued Operations; (8) Acquisition; (9) Critical l..

Accounting Estimates; (10) New Accounting Principles; and (11) Commitments and Indemnities. -

MANAGEMENT OVERVIEW - .

In 2005, SCE's focus was on effective execution of Edison International's strategic plan. That plan, C announced in October of 2004, set forth a balanced approach for growth, dividends and balance sheet strength. In 2005, SCE met and in some cases exceeded what was set out in the strategic plan as it related to SCE. Principal objectives achieved in 2005 are summarized below: , -

• Managed growth - In 2005, SCE met all transmission and distribution investment targets, as well as key milestones on future transmission projects.-In addition, SCE continued to focus on ensuring adequate generation resources to support customer demand and completed construction of its 1,054 megawatt (MW) Mountainview project and obtained 'a CPUC decision authorizing the San Onofre Nuclear Generating Station (San Onofre) steam generator replacement project.

• Balance sheet strength - In 2005, SCE took steps to'rebalance its capital structure. Liquidity was also enhanced through strong cash flow generation. In addition, credit ratings improved and credit facilities to support hedging and liquidity needs were expanded.

SCE also took significant steps to strengthen the ethics and compliance programs, building a high-,

priority program to uphold its commitment to integrity and compliance with all regulatory. requirements.

In 2006, SCE's primary focus includes:

• Implementation of SCE's capital investment plan to ensure system reliability. SCE plans to undertake new projects to expand its transmission and distribution systems, increase maintenance activities on its electric grid, and begin implementation of a comprehensive, integrated software system to support the majority of its critical business processes. The proposed decision in SCE's 2006 General Rate Case (GRC) would authorize $4.9 billion of capital expenditures for 2006 -. 2008, including $2.2 billion in 2006. See "Liquidity-Capital Expenditures" for further discussion of SCE's capital expenditures.

• Progression toward a set of market rules that permit SCE to procure power efficiently ensuring adequate resources are available and creating a downward pressure on customer rates. Beginning in 2006, SCE

was required to procure sufficient resources to meet its expected customer needs with a 15-17%'reserve margin. SCE expects to meet this resource adequacy requirement in 2006, but access to long-term power resources is needed. In order to provide reliable service SCE continues to focus on securing reasonable long-term procurement rules (see "Regulatory Matters-Current Regulatory Developments"), finding a path to continue to operate the Mohave Generating Station (Mohave) in 2006 on acceptable financial and commercial terms (see "Regulatory Matters-,Current Regulatory Developments-Mohave Generating Station and Related Proceedings"), and achieving the milestones for the San Onofre steam generator replacefiient (see "Regulitory Matters -Current Regulatory Developmenis-San Onofre Nuclear Generating Station Steam Generators").

• Continuing to be effective in advocating sound, stable and consistent regulatory decisions, including SCE's 2006 GRC application. A proposed decision on SCE's 2006 GRC application was received on January 17, 2006. Theproposed decision would result in a 2006 base rate revenue requirement of

$3.70 billion, an increase of $61.million over SCE's 2005 base rate revenue. See "Regulatory Matters-Current Regulatory Developments" for further discussion of regulatory matters.

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°- ,. '; .'.'_ Southern California Edison Company In addition, SCE will continue to enhance the effectiveness of SCE's ethics and compliance programs and will advance company-wide-leadership'and talent development programs to support its strategic plan objectives.- .'

LIQUIDITY . -;

Overview As of D.-cember 31, 2005, SCE had cash and equivalents of $143 million ($120 million of which was held by SCE's consolidated Variable Interest Entities (VIEs)). As of December 31, 2005, long-term debt, including current maturities of-long-term debt, was $5.3 billion. In December 2005, SCE replaced its

$1.25 billion credit facility with a $1.7 billion senior secured 5-year revolving credit facility. The security pledged (first and refunding mortgage bonds) for the new facility can be removed at SCE's discretion. If SCE chooses to remove the security, the credit facility's rating and pricing will change to an unsecured basis per the terms of the credit facility agreement. As of December 31, 2005,SCE's credit facility supported $180 million in letters of credit, leaving $1.52 billion available under the credit facility.

SCE's 2006 estimated cash outflows consist of:

• Debt maturities of approximately $596 million, including approximately $246 million of rate reduction notes that have a separate nonbypassable recovery mechanisni'approved by state legislation and CPUC decisions;

• Pr6jected capital expenditures of $2.2 billion'primarily to replace and expand distribution and transmission infrastructure and construct and replace generation assets, as discus'sed below;

• Dividend payments to SCE's parent company. On March 1, 2006, the Board of Directors of SCE declared a $60 million dividend to be paid to Edison International,, ,,. .

• Fuel and procurement-related costs (see "Regulatory Matters-Current Regulatory.DevelopmentE '

Energy.Resource Recovery Account Proceedings"); and - .

• General operating expenses. ' '- -'- '- .  ;

SCE expects to meet its continuing obligations, including cash outflows for power-procurement undercollections (if incurred),; throuih 6ush'aid equivalents on hand, dperating cash flows and short-term borrowings, when necessar~ .'Projected capitalexpenditures are'expected to'be financed through operating cash flows and the issuance of long-term debt and preferred equity.

In January 2006, SCE issued two million shares of 6.0% Series C preference stock (non-cumulative,

$100 liquidation value) and received net prdceeds of$197 million. In addition, SCE iss'ued $500 million' offirstand refunding mortgage bonds; The issuance included $350 million of 5.625% bonds due'in 2036 and $15' nMillion of variable rate bonds 'due' in 2009:The proceeds fromnthe January 2006 issuances of preference stock'and bonds will be used for general corporate purposes,'iicluding capital expen'ditule`s fand debt: maturities. -

SCE's liquidity may be affected by, among other things, matters described in "Regulatory Matters."

Capital Expenditures  :

SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its distribution and transmission infrastructure, and to construct and replace generation assets. In April 2M05, the Finance Committee of SCE's Board of Directors approved a $10.1 billion capital budget' and forecast for the period 2005-2009. Pursuant to the'approved capital budget ahd forecast, SCE 3

Management's Discussion and Analysis of Financial Condition and Results of Operations expects its capital expenditures to be $2.2-billion in 2006 and $2.1 billion in both 2007 and 2008, ..

including projected environmental capital expenditures of $482 million, $485 million and $500 millioniin 2006, 2007 and 2006, respectively (see "Other Developments-Environmental Matters"). Significant investments in 2006 are expected to include:

• $1.5 billion related to transmission and distribution projects;

• $300 million related to generation projects;

• $200 million related to information technology projects, including the implementation of a comprehensiveintegrated software system to support a majority of SCE's critical business processes; and .

• $200 million related to other customer service and shared services projects.

Credit Ratings i ;

At December 31, 2005, SCE'§redit and long-term senior secured issuer ratings from Standard &.Poor's and Moody's Investors Service were BBB+ and A3, respectively. At December 31, 2005, SCE's short" term (commercial paper) credit ratings from Standard & Poor's and Moody's Investors Service were A-2 and P-2, respectively.

Dividend Restrictions and Debt Covenants 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 determines compliance with this capital structure based on al 3-month weighted-average calculation'. At December 31, 2005, SCE's 13-month weighted-average common equity component of total capitalization was 50%. At December 31, 2005, SCE had the capacity to pay$197 million in additional dividends based on the 13-month weighted-average method. Based on recorded December-31, 2005 balances, SCE's common equity to total capitalization ratio, for rate-making purposes, was 50.2%. SCE had the capacity to pay $212 million of additional dividends to Edison International based on December 31, 2005 recorded balances.

SCE has a debt covenant that requires a debt to total capitalization ratio of less than or equal to 0.65 to 1!,

to be met. At December31, 2005, SCE's debt to total capitalization ratio was 0.46 to, . ,

Margin and Collateral Deposits

' - r ~~~~~~~. -. .-tiM--..*.-,.t--ts:.P:!,6jij In connection with entering into power-purchase agreements to support SCE's procurement plan..

approved by the CPUC and enter into transactions for imbalance energy with the California Independent System Operator (ISO), SCE has entered into margining agreements for power and gas trading activities to support its risk of nonperformance. SCE's margin deposit requirements can vary depending upon the level of unsecured credit extended by counterparties and brokers, the ISO credit requirements, changes in market prices relative to contractual commitments, and other factors. At December 31, 2005, SCE had a net deposit of $6 million ($158 million recorded in "Margin and-collateral deposits" on the balance sheet and $152 million in unrealized gains recorded in "Counterparty collateral" on the balance sheet) with a broker in support of gas trading activities. In addition SCE deposited $200 million (comprised of i

$20 million in cash and $180 million in letters of credit) with counterparties. Cash deposits with counterparties and brokers earn interest at various rates.

Margin and collateral deposits in support of power purchase agreements and gas trading activities fluctuate with changes in market prices. As ofFebruary 28, 2006, SCE had a net deposit of $242 million

($109 million recorded in "Margin and collateral deposits" on the balance sheet and $133 million in 4

-:; , Southern California Edison Company unrealized losses recorded in "'Counterparty collateral" on the balance sheet) with a broker. In addition, SCE has posted $199 million (comprised of $20 million in cash and $179 million in letters of credit) with counterparties. Future margin and collateral requirements may be higher or lower than the margin -

collateral requirements as of December 31, 2005 and February 28, 2006, based on future market prices and volumes oftrading activity.., r -

In addition, as discussed in "Regulatory Matters-Overview ofRatemaking Mechanisms-CDWR-Related Rates," the CDWR entered into contracts to purchase power for the sale at cost directly to SCi_'s retail customers during the California energy crisis. These CDWR procurement-contracts contain.

provisions that would allow the contracts to be assigned to SCE if certain conditions are satisfied, including having an unsecured credit rating of BBB/Baa2 or higher. However, because the value of power from these CDWR-contracts is subject to market rates; such an assignment to SCE, if actually undertaken, could require SCE to post significant amounts of collateral with the contract counterparties,:

which would strain SCE's liquidity. In addition, the requirement to take responsibility for these ongoing fixed charges, which the credit rating agencies view as debt equivalents, could adversely affect SCE's credit rating. SCE opposes anyrattempt to assign the CDWR~contracts. Hlowever, it is possible that attempts may be made to order SCE to take assignment of these contracts, and that such orders.might withstand legal challenges., .

Rate Rcduction Notes In December 1997, $2.5 billion of rate reduction notes were issued on behalf of SCE by , i SCE Funding LLC, a special purpose entity. These notes were issued to finance the 10% rate reduction mandated by state law beginning in 1998. The proceeds ofthe rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as transition property.Transition property is a current property.right created by the restructuring legislation and a financing order of the CPUC and consists generally of the right to be paid a specified amount from nonbypassable rates charged to residential and small commercial customers. The rate reduction notes are being repaid over 10 years through these nonbypassable residential and small commercial customer rates, which constitute the transition property purchased by SCE Funding LLC. The notes are collateralized by the transition property and are not collateralized by, or payable from, assets of SCE. SCE used the proceeds from the sale of the transition property to retire debt and equity securities. Although, as required by accounting principles generally accepted in the United States, SCE Funding LLC is consolidated with SCE and the rate reduction notes are shown as long-term debt in the consolidated financial statements, SCE Funding LLC is legally separate from SCE. The assets of SCE Funding LLC are not available to creditors of SCE and the transition property is legally not an asset of SCE.

REGULATORY MATTERS ,,  : .  : *; ', .; -

Overview of Ratemaking Mechanisms .  : .

SCE is all investor-owned utility company providing electricity to retail customers in central, coastal and southern California. SCE is regulated by the CPUC and the Federal Energy Regulatory Commission, (FERC). SCE bills its customers for the sale of electricity at rates authorized by these two commissions.

These rates are categorized into three groups: base rates, cost-recovery rates, and CDWR-related rates..

Base Razes Revenue arising from base rates is designed to provide SCE a reasonable opportunity to recover its costs and earn an authorized return on SCE's net investment in generation, transmission and distribution plant (or rate base). 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.

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Management's Discussion and Analysis of Financial Condition and Results of Operations Base rates related to SCE's generation and distribution functions are authorized by the CPUC through a;.

GRC. In a'GRC proceeding, SCE files an application with the CPUC to update its authorized annual !

revenue requirement. After a review process and hearings,' the CPUC sets an annual revenue requirement by multiplying an authorized rate of return, determined in annual cost of capital proceedings (as '

discussed below), by rate base, then adding to this amount the adopted operation and maintenance costs and capital-related carrying costs. Adjustments to the revenue requirement for the remaining years of a typical three-year GRC cycle are' requested from the CPUC based on criteria established in a GRC proceeding for escalation in operation and maintenance costs, changes'in capital-related costs and the expected number of nuclear refueling outages. See "-GCurent Regulatory Developments-2006 General Rate Case Proceedling" for SCE's current annual revenue requirement. Variations in generation and -

distribution revenue arising from the difference between forecast and actual electricity sales are recorded in balancing accounts for future recovery or refund,' and do not impact SCE's operating profit,;while differences between forecast and actual dperating costs; other than cost-recovery-costs (see below), do.,

impact profitability. - -  ;. ' ', - -"

Base rate revenue related to SCE's transmission function is authorized by the FERC in periodic proceedings that are similar' to the CPUC's GRC proceeding, except that requested rate changes are!

generally implemented when the application is filed, and revenue collected prior to a final FERC i decision is subject to refund.

SCE's capital structure, including the authorized rate of return, is regulated by the CPUC and is determined in an annual cost of capital proceeding. The rate of return is a weighted average of the return on common equity and cost of long-term debt and preferred equity. In 2005, SCEs rate-making capital structure was 48% common equity, 43% long-term debt and 9% preferred equity. SCE's authorized cost of long-term debt was 6.96%, its authorized cost of preferred equity was 6.73% and its authorized return on common equity was 11.40%. If actual costs of long-term debt or preferred equity-are higher or-lower than authorized, SCE's earnings are impacted in the current year and the differences are not'subject to' refund or recovery in rates. See "-Current Regulatory Developments-2006 Cost of Capital Proceeding" for discussion of SCE's 2006 cost of capital proceeding.

SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to cam rewards or penalties based on its performance in comparison to CPUC-approved standards of reliability and employee safety..  : ' . ' i Cost-Recovery Rates  ! . '

Revenue requirements to recover SCE's costs of fuel, purchased power, demand-side management programs, nuclear decommissioning, rate reduction debt requirements, and public purpose programs are authorized in various CPUC proceedings on a cost-recovery basis, with no markup for return or profit.

Approximately 52% of SCE's annual revenue relates to the recovery of these costs. Although the CPUC authorizes balancing account mechanisms to refund or recover any differences between estimated and actual costs, under- or-over-collections in these balancing accounts can build rapidly due to fluctuating prices (particularly for purchased power) and can greatly impact cash flows. SCE may request adjustments to recover or refund any under- or over-collections. The majority of costs eligible for recovery are subject to CPUC reasonableness reviews, and thus could negatively impact earnings and cash flows if found to be unreasonable and disallowed.

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sX ~~ '.  :, I.l Southern California Edison Company CDWR-RelatedRales .  ;

As a result of the California energy crisis, in 2001 the 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 CPLUC among the customers of SCE, Pacific Gas and Electric (PG&E) and San Diego Gas & Electric (SDG&;E)

(collectively, the investor-owned utilities). SCE bills and collects from its customers the costs of power purchased and sold by the CDWR, CD)WR bond-related charges and direct access exit fees. The CDWN'R-related charges and a portion of direct'access exit fees (approximately $1.9 billion was collected in 2005) are remitted directly to the CDWR and are not recognized as revenue by SCE and therefore have no impact cn SCE's earnings; however they do impact customer rates.

Impact of Regulatory Matters on Customer Rates SCE is concerned about high customer rates, which were a contributing factor that led to the deregulation of the el ectric services industry during the Imid-I1990s.'At'January 1,2005, SCE's system average rate for bundled customers *vas.12.20-per-kilowatt-hour. As of December 31, 2005, the system average rate was 12.60-pcr-kilowatt-hour. On January 1, 2006, SCE implemented a rate change that resulted inma systemn '

average rate of 13.70-per-kilowatt-hour. Of the 1.1¢ rate increase, 1¢ was due to the implementation of the CDVWR's 2006 revenue requirement approved by the CPUC on December 1, 2005.

SCE implemented a rate change on February 4, 2006. As a result, SCE's current system average rate i3 14.30-per-kilowatt-hour. The rate increase was due to a I ;2 increase resulting from the implementation of SCE's 2006 Energy Resource Recovery Account (ERRA) forecast discussed below, partially offset by a decrease of 0.70 due to spreading of the revenue requirement over-a larger customer base resulting from forecast sales growth. In addition,'the .rate change inclides authorized increases in funding for demand-'

side management programns. - - -;  ;- i; .;

Curreni Regulatory Developments - ,,  ! .' 2 .. ,;'

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This section of the MD&A describes significant regulatory!issues that may impact SCE's financial conditio1 or results of operation. '

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2006 GeuerallRate Case Proceeding . . '..

SCE's 2006 GRC application requested a revised 2006 base rate revenue requirement of $3.96 billion, an increase of $325 million over SCE's 2005 base rate revenue. The requested increase is primharily-driven by capital expenditures needed to accommodate infrastructure replacement and customer and load growth, and by higher operating and maintenance expenses, particularly in SCE's transmission and distribution business unit. SCE also requested the CPUC continue SCE's existing post-test year rate-making mechanism, which would result in further revised base rate revenue increases of $108 million in 2007 and $113 million in 2008. '! .. -. ', '

-,,. i - ' ' - I' , . ,  : , ' ' '. r f. I On January 17, 2006; the assigned administrative law judge issued his proposed decision, which would result in a 2006 base rate revenue requirement of $3.70 billion, an increase of $61 million over-SCE's 2005 base rate revenue. The proposed draft decision contained an error understating the revised 2006 increase. When corrected, the 2006 revenue requirement increase would be $85 million. The proposed decision would reject approximately $121 million of O&M expenses and $143 million of the capital-related revenue requirement that SCE requested. The proposed decision would also reject SCE's post-test year rate-making method and instead escalate 2006 gross additions to 2007 and 2008. The proposed decision's changes would result in base rate revenue increases of $68 million in 2007 and $105 million in 2008. A final CPUC decision is expected by the end of April 2006. SCE cannot predict with certainty the final outzome of SCE's GRC application.

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Management's Discussion and Analysis of Financial Condition and Results of Operations On January 12, 2006, the CPUC approved SCE's request for a GRC memorandum account, which makes the revenue requirement ultimately adopted by the CPUC effective as of that date.

2006 Cost of CapitalProceeding '.,  ::

On December 15, 2005, the CPUC granted SCE's requested rate-making capital structure of 43% long-term debt, 9% preferred equity and 48%-common equity for 2006. The CPUC also authorized SCE's" 2006 cost of long-term debt of 6.17%, cost of preferred equity of 6:09% and a return on common equity of 11.60%. The CPUC decision resulted in a $23 million decrease in SCE's annual revenue requirement due to lower interest costs partially offset by an' increase in return on common equity.' - i; 2006 FERCRate Case SCE's electric transmission revenue and wholesale and retail transmission rates are subject to authorization by the FERC; On November 10, 2005, SCE filed proposed revisionsto the 2006 base' transmission rates, which would increase SCE's revenue requirement by $65 million,' or 23%, over current base transmission rates, effective on January 10, 2006. On January 9, 2006,FERC accepted the filing, but delayed the rate changes to become effective June:10, 2006, subject to refund.-On February 8, 2006; SCE filed a petition for rehearing of the orderseeking, among other things, reversal of the FERC's effective date. SCE is unable .to predict the revenue requirement that the FERC will ultimately authorize and when the rate changes will become effective.

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Energy Resource Recovery Account Proceedings ,: .:

In 2002, the CPUC established the ERRA as the balancing account mechanism to track and recover.:

SC*E's:. (1) fuel costs related to its generating stations; (2) purchased-power costs related to cogeneration and renewable contracts; (3) purchased-power costs related to existing interutility. and bilateral contracts that were entered into before January 17, 2001; and (4) procurement-related costs incurred on or after January 1, 2003 (the date on which the CPUC transferred back to SCE the responsibility for procuring energy resources for its customers). As described above, SCE recovers these costs on a cost-recovery basis, with no markup for return or profit.-SCE-files annual forecasts of the above-described costs that it expects to incur during the following year. If the forecast is approved, as these costs are subsequently incurred they are tracked and recovered in customer rates through the ERRA, but are subject to a reasonableness review in a separate annual ERRA application. If the ERRA overcollection or .

undercollection exceeds 5% of SCE's prior year's generation revenue, the CPUC has established a "trigger" mechaziismwhereby SCE can request an emergency rate adjustment. As of December 31,'.

2005, the ERRA was undercollected by $42 million, which was I;28% of SCE's prior year's generation revenue.; ' '  ; '  ;*

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ERRA Forecast .- '; ' - .:

On January 26, 2006, the CPUC approved SCE's 2006 ERRA forecast application, in which it forecasted a power procurement-related revenue requirement for the 2006 calendar year of $4.3 billion, an increase of'$961 million over SCE's approved 2005 power procurement-related revenue requirement. The I increase was mainly attributable to the substantial increase in natural gas and power prices, load growth and resource adequacy requirements (see the discussion under. "-Resource Adequacy-Requirements'),

the unavailability of Mohave after December 31, 2005, and its replacement with higher-cost natural gas generation (see "-Mohave Generating Station and Related Proceedings"). The increase was, implemented in customer rates beginning February 4, 2006.'

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.. - Southern California Edison Company ERRA Reasonableness Review..,. i, . ... ,

From September 1, 2001 through December 31, 2004, the CPUC found all costs recorded in SCE's ERRA account reasonable and prudent, except for minor amounts in 2001. .

In addition, from September 1,2001 through June 30,;2003, the CPUC authorized recovery of amounts paid to Peabody Coal Company for costs associated with the Mohave mine closing, as well as..

transmission costs related to serving municipal utilities, and also resolved outstanding issues from 2000 and 2001 related to CDWR costs. As a result of this decision; SCE recorded a benefit of $1 18 million in:

20 4  ; ,.'_' .; .. ,s i' 2004. .. ' il _. . . . ' '  : ";

Resource Adequacy Requirements Under the CPUC's resource adequacy framework, all load-serving entities in California have an te i.

obligation to procure sufficient resources to meet their expected customers' needs with a 15-17% reserve level. Effective February 16, 2006, SCE was required to demonstrate that it had procured sufficient resources to meet 90% of its-June-September 2006'resource adequacy requirement. SCE believes that it has met this-requirement. Effective in May 2006, SCE will be required to demonstrate that it has met 100% o- its resource adequacy requirement one month'in advance of expected need: A month-ahead showing demonstrating that-SCE has procured 100% of its resource adequacy requirement will be required every month thereafter. The resource adequacy framework provides forpenalties of 150% ofthe cost of new.monthly capacity for failing to meet the resource adequacy requirements in 2006, and a ,

300% penalty in 2007 and beyond. SCE believes it has procured sufficient resources to meet its expected resource adequacy requirements for 2006. In December 2005, the CPUC opened a new resource adequacy rulemaking to address resource adequacy implementation issues, the implementation of local:

resource adequacy requirements, and other issues related to resource adequacy. A decision on local ,,

resource adequacy requirements is expected in June'2006. .-  ;. , .. ! : .. . '

ProcurementofRenewable Resources  ! , .. . . i -

California law requires SCE to increase its procurement of 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, 2017. The Joint Energy Action Plan adopted in 2003 by the CPUC and the California -Energy Commission (CEC) accelerated the deadline to 2010.;.,

SCE entered into a contract with Calpine Energy Services, L.P. (Calpine) to purchase the output of certain existing geothermal facilities in northern California. On January 30, 2003,-the CPUC issued ai resolution approving the contract. SCE interpreted the resolution as authorizing SCE to count all of the output of the geothermal facilities towards the obligation to increase SCE's procurement from renewable resources and counted the entire output of the facilities toward its 1% obligation in 2003, 2004 and 2005.

On July 21, 2005, the CPUC issued a decision stating that SCE can only count procurement pursuant to;!

the Calfine contract towards its 1% annual renewable procurement requirement if it is certified as "incremental" by the CEC. On February 1,2006, the CEC certified approximately 25% and .17% of SCE's 2003 and 2004 procurement, respectively, from the Calpine geothermal facilities as "incremental."

A simil.r outcome is anticipated with respect to the CECs certification review for 2005. -

On Aug st 26, 2005, SCE filed an application for rehearing and a petition for modification of the CPUC's July 21, 2005 decision. On January 26, 2006, the CPUC denied SCE's application for rehearing of-the decision. The CPUC has not yet ruled on SCE's petition for modification. The petition for modification seeks a clarification that SCE will not be subjected to penalties for relying on the CPUC's 2003 resolution in submitting compliance reports to the CPUC and planning its subsequent renewable -

procurement activities. The petition for modification also-seeks an express finding that the decision w ill 9

Management's Discussion and Analysis of Financial Condition and Results of Operations be applied prospectively only; i.e., that no past procurement deficits will accrue for any prior period based on the decision.

If SCE is not successful in its attempt to modify the-July 21, 2005 CPUC decision and can only count the output deemed "incremental" by the CEC, SCE could have deficits in meeting its renewable procurement obligations for 2003 and 2004. However, based'on the CPUC's rules for compliance with renewable procurement targets, SCE believes that it will have until 2007 to make up these deficits'before becoming subject to penalties for those years. The CEC's and the CPUC's treatment of the output from the -

geothermal facilities could also result in SCE being deemed to be out of compliance in 2005 and 2006.

Under current CPUC decisions, potential penalties for SCE's failure to achieve its renewable procurement obligations for any year will be considered by the CPUC in SCE's annual compliance filing.

On December 20, 2005, Calpine and certain of its affiliates initiated Chapter 11 bankruptcy proceedings in the United States Bankruptcy Court for the Southern District of New York. As part of those proceedings, Calpine sought to reject its contract with SCE as of the petition filing date. On January 27,'

2006, after the matter had been withdrawn from the Bankruptcy Court's jurisdiction, the United States District Court for the Southern District of New York denied Calpine's motion to reject the contract and ruled that the FERC has exclusive jurisdiction to alter the terms of the contract with SCE. Calpine has appealed the District Court's ruling to the United States Court of Appeals -for the Second Circuit. Calpine may also file a petition with the FERC seeking authorization to reject the contract.-The CPUC may take the position that any authorized rejection of the contract would cause SCE to be out of compliance with its renewable procurement obligations during any period in which renewable electricity deliveries are reduced or eliminated as-a result of-the rejection:: '

Further,' in December 2005, SCE made filings advising the CPUC that the need for transmission upgrades to interconnect new renewable projects and the time it will -take under the current process to license and construct such transmission upgrades may prevent SCE from meeting its statutory renewables procurement obligations through 2010 and potentially beyond 2010 depending in part on the results of a pending solicitation for new renewable resources. SCE has requested that the CPUC take several actions' in order to expedite the licensing process for transmission upgrades. The CPUC may take the position that SCE's failure to meet the 20% goal by 2010 due to transmission constraints would cause'SCE to be' out of compliance with its renewable procurement obligations.. ' '

Under the CPUC's current rules, the maximum penalty for failing to achieve renewables procurement targets is $25 million per year. SCE cannot predict with certainty whether it will be assessed penalties.

Mohave Generating Station and Related Proceedings ' i  ; ; i'!

Mohave obtained all of its coal supply-from the Black Mesa-Mine in northeast Arizona, located on lands; of the Navdjo Nation'and Hopi Tribe (the Tribes). This coal was delivered from the mine to Mohave by -

means of a coal slurry pipeline, which requires water from wells located on lands belonging to the Tribes in the mine vicinity. Uncertainty over a post-2005 coal and water supply'has prevented SCE and other,:

Mohave co6-owners from making approximately $1.1 billion in Mohave-related investments (SCE's share is $605-million), including the;installation of enhanced'pollution-control equipment that must be put in place in order for Mohave to continue to operate beyond 2005, pursuant to a 1999 consent decree  !

concerning air quality.

Negotiationslwater studies, and other efforts have continued among the relevant parties in an attempt to '

resolve Mohave's post-2005 coal and water supply issues. Although progress has been made with respect to certain issues, no complete resolution has been reached to date, and efforts to resolve these issues -

continue. The plant ceased operations, as scheduled; on December 31, 2005, consistent with the ' '

provisions of the 1999 consent decree. SCE'remains committed to the environmental objectives 10

- " -I . ' ... . ', 'Southern California Edison Compiany underlying that decree. SCE is also committed to pursuing all reasonable options to return Mohave to service pursuant to the existing consent decree provisions or, if interim operation is permitted pendingi installation of controls, pursuant to additional legal provisions which provide appropriate protection of the environment. However, at this time, SCE does not know the length of the shutdown period, and a permanent shutdown remains possible. The outcome of the efforts to resolve the post-2005 coal and water supply issues did not impact Mohave's operation through 2005, but the presence or absence of Mohave as an available resource beyond 2005 will impact SCE's long-term resource plan. SCE's 2006 ERRA forecast application assumes Mohave is an unavailable resource for power for 2006 (see - .

"-Energy Resource Recovery Account Proceedings-ERRA Forecast" for further discussion). SCE expects to recover Mohave shut-down-costs. in customer rates. ,

In light of the issues discussed above, in 2002 SCE concluded that it was probable Mohave would be shut down at the end of 2005. Because the expected undiscounted cash flows from the plant during the years 2003-2005 were less than the $88 million carrying value of the plant as of December 31, 2002, SCE incurred an impairment charge of$61 million in 2002. However, in accordance with accounting, standards for rate-regulated enterprises, this incurred charge was'deferred and recorded in regulatory assets as a long-term receivable based on SCE's expectation that the unrecovered book valte at the end of 2005 would be recovered in future rates (together with a reasonable return) through a balancing account mechanism. Subsequent charges related to capital additions were also deferred and recorded in regulatory assets. As of December 31, 2005 the regulatory balance related to the Mohave impairment was

$81 million.-  ;  ; i For additional matters-related to Mohave, see,'Other Developments-Navajo Nation Litigation."

San Onofre Nuclear Generating Station Steam Generators On December 15, 2005, the CPUC issued a final decision on SCE's application for replacement of SC(E's San Onofre Units 2 and 3 steam generators. In that decision, the CPUC found that: (1) steam generator replacement is cost-effective; (2) SCE's estimate of the total cost'of steam-generator replacement of -

$680 million ($569 million for replacement steam generator-installation and $111 million for removal and disposal of the original steam generators) is reasonable; (3) SCE will be able to recover all of its*'

incurred costs and the CPUC does not intend to conduct an after-the-fact reasonableness review if the project is completed at a cost that does not exceed $680 million as adjusted for inflation and allowance for funds used during construction; (4) a reasonableness review will be required if the project is completed at a cost between $680 million and $782 million or the CPUC later finds that it had reason. to believe the costs may be unreasonable regardless of the amount; (5) if the cost of the project exceeds i

$782 million, no rate recovery will be allowed for costs above $782 million as adjusted for inflation and allowance forfunds used during constrtiction; (6) traditional cost-of-service ratemaking should govern recovery. of future operating and maintenance and capital expenditures for plant operation; (7) SCE's actions in relation to the issue of potential claims against the manufacturer of the steam generators or its successors were reasonable; and (8) SDG&E must file an application with the CPUC concerning the transfer of its ownership share of San Onofre Units 2 and 3 to SCE -by April 14, 2006. SCE must provide written notice of its acceptance of the conditions set forth in the decision within 85 days. On January 18, 2006, the Utility Reform Network and California Earth Corps filed an application for ,-

rehearing challenging, among other things, the cost benefit analysis, rejection of future spending caps, the timing for initiation of the analysis, and the portion of the final decision finding that SCE acted.-

reasonably in pursuing claims against the manufacturer of the steam generators.

SCE's share of the total estimated cost of the steam generator replacement project based on its current ownership percentage of 75.05% is $510 million. SCE and the city of Anaheim have agreed to an early, transfer of Anaheim's 3.16% share of San Onofre, which would increase SCE's share of the total 11

Management's Discussion and Analysis of Financial Condition and Results of Operations estimated costs to $532 million. By April 14,'2006, SDG&E is expected to apply to the CPUC to transfer all or a portion of its 20% share of San Onofre to SCE. If SDG&E's entire 20% share is transferred to SCE, it would increase SCE's share of the total estimated costs to $668 million.-Any transfer of SDG&E's ownership in San Onofre would require the approval of the CPUC and the FERC. Any transfer of Anaheim's share in San Onofre would require CPUC approval of ratemaking for SCE's acquired share and approval by the FERC. . - I Palo Verde Steam GeneratingStation Steam Generators .  ;  ; -.

SCE owns a 15.8% interest in the Palo Verde Nuclear Generating Station (Palo Verde). During 2003, the Palo Verde Unit 2 steam generators were replaced. During 2005, the Palo Verde Unit I steam generators were replaced. In addition; the Palo Verde owners have approved the manufacture and installation of i steam generators in Unit 3. SCE expects that replacement steam generators will be installed in Unit 3 in 2008 SCE's share of the costs of manufacturing and installing all the replacement steam generators a't Palo Verde is estimated to be approximately $115 million: The CPUC approved the replacement costs for Unit 2;in the 2003 GRC; The proposed decision in the 2006 GRC proceeding would allow SCE to recover the replacement costs for-Units I and 3. * >- .  ; - . l ISO Disputed Charges . . . . :

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain charges: The order reversed anmarbitrator's award that had affirmed the ISO's characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those charges to scheduling coordinators (SCs) in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from SCs in the affected zone to the responsible participating transmission owner, SCE. The potential cost to SCE, net of amounts SCE expects to receive through the California Power Exchange (PX), SCE's SC at the time, is estimated to be approximately

$20 million to $25 million, including interest. On April 20, 2005, the FERC stayed its April 20, 2004 order during the pendency of SCE's appeal filed with the Court of Appeals for the D.C. Circuit. On February 7, 2006, the FERC advised SCE that the FERC will move the Court of-Appeals for a voluntary remand so that the FERC may amend the order on appeal. A decision is expected in-late 2006. The FERC may require SCE to pay these costs,;but SCE does not believe this outcome is probable. If SCE is required to pay these costs, SCErmay seek recovery in its reliability'service rates::

Transmission Proceeding .  : . . :. ..  :. , i In August and November 2002, the FERC issued opinions affirming a September 1999 administrative law judge decision to disallow,'among other things,,recovery by SCE and the other California public utilities of costs reflected in network transmission rates associated with ancillary services and losses i incurred by the utilities in administering existing wholesale transmission contracts after implementation of the restructured California electric industry. SCE has incurred approximately $80 million of these r unrecovered costs since 1998. In addition, SCE has accrued interest on these unrecovered costs. The t:

three California utilities appealed the decisions to the Court of Appeals-for the D.C. Circuit. On July;12,i 2005, the Court of Appeals for the D.C. Circuit vacated the FERC's August and November;2002 orders,;

and remanded the case to the FERC for further proceedings. On December 20, 2005; the FERC.;

authorized SCE and the other California public utilities to recover the costs through their existing FERC tariffs. As a result, SCE recorded a benefit of approximately $93 million (including $23 million related to interest which is reflected in the consolidated statements of income caption "Interest expense - net of amounts capitalized"). . . , - . i  : - - -,

. . ,,,t., , .',':'. -', ',,

12

Southern California Edison Company FERC Refund Proceedings . . . .

In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by.

sellers of electricity in theiPX and ISO markets. On March 26, 2003, the FERC staff issued a report concluding that there had been pervasive gaming and market manipulation of both the electric and natural gas markets in California and on the West Coast during 2000-2001 and describing many of the techniqt es and effects of that market manipulation. SCE is participating in several related proceeding:s seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets. SCE is required to refund to customers 90% of any refunds actually realized by SCE net of litigation costs,rexcept for the Ell Paso Natural Gas Company settlement agreement discussed below, and 10% will be retained by SCE as a shareholder incentive. A brief summary of the various settlements isbelow:; ' -,t*.: * *

• In June 2004, SCE received its first settlement payment of $76 million resulting from a settlemenI agreement with El Paso Natural Gas Company. Approximately $66 million of this amount was credited to purchased-power expense, and was refunded to SCE's ratepayers through the ERRA mechanism over the following twelve months, and the remaining $10 million was used to offset SCE's incurred legal costs. In May 2005, SCE received its final settlement payment of $66 million, which was also refunded to ratepayers through the ERRA mechanism. ,

• 'In A ugust 2004, SCE received its $37 million share of settlement proceeds resulting from a FEFC approved settlent agreernent'with The Williamns'Cos. and Williams Power Company.

• In November 2004, SCE received its $42 million share of settlement proceeds resulting from a EERC-approved settlement agreement with WVest Coast Power, LLC and its owners, Dynegy Inc. and NRG Energy, Inc. ,  ;

• In January.2005, SCE received its:$45 million share of settlement proceeds resulting from a, FERC-approved settlement agreement with Duke Energy Corporation and a number of its affiliates.

• In April 2005, the FERC approved a settlement agreement among SCE, PG&E, SDG&E and several governmental entities, and Mirant Corporation and a number of its affiliates (collectively Mirant), all' of whom are debtors in Chapter' I bankruptcy proceedings pending in'Texas. In April and May 200.5, SCE received its $68 million share of the'cash poition of the settlement proceeds. SCE also received a $33 million share of an allowed, unsecured claim in the bankruptcy of one of the Mirant parties which was sold for $35 million in December 2005.

• In November 2005, the FERC approved a settlement agreement among SCE, PG&E, SDG&E and several gdvernniental entities, and Enron Corporation and a number of its affiliates (collectively Enroti), most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In January 2006, SCE received cash settlement proceeds of $4 million for legal fees and anticipates receiving approximately $5pillion in additional cash proceeds assuming certain contingencies are sati!;ie'd.' SCE'also received an allowed, unsecured claim against one of the Enron debtors in the amount of.$241 million. In February 2006, SCE received a partial distribution of $10 million of its allowed claim. The remaining amount of the'allowed claim that will actual] 'be realized will depend on events in Enron's bankruptcy that impacts the value of the relevant debtor estate.

• In December 2005, the FERC approved a settlement agreement among SCE, PG&E, SDG&E, several governmental entities and certain other parties, and Reliant Energy, Inc. and a number of its affiliates (collectively Reliant). In January 2006, SCE received $65 million of the settlement proceeds. SCE-expects to receive an additional $66 million in 2006.

During 2005, SCE recognized $23 million in shareholder incentives related to the FERC refunds described abovewhich is reflected in the consolidated statements of income caption "Other nonoperating income."' , 1. , , ,

13

Management's Discussion and Analysis of Financial Condition and Results of Operations Holding Company Order Instituting Rulemaking On October27, 2005, the CPUC issuedan order instituting nilemaking (OIR) to allow the CPUC to C re-examine the relationships of the major California energy utilities with their parent holding companies and non-regulated affiliates. The OIR was issued in part in response to the recent repeal of the Public Utility Holding Company Act of 1935. v '

• - *;- .  !*. l . I;. , ,,..

,i By means of the OIR, the CPUC will consider whether additional rules to supplement existing rules and requirements governing relationships between the public utilities and their holding companies and non-regulated affiliates should be adopted. Any additional rules will focus on whether (I) the.public utilities retain enough capital or access to capital to meet their customers' infrastructure needs and (2) mitigation of potential conflicts between ratepayer interests and the interests of holding companies and affiliates that could undermine the public utilities' ability to meet their public service obligations at the lowest cost.;

Demand-Side Management and Energy Efficiency PerformanceIncentive Mechanisms Under a variety of incentive mechanisms adopted by the CPUC in the past, SCE was entitled to certain shareholder incentives for its performance achievements in delivering demand-side management and energy efficiency programs. On June .10, 2005, SCE and the CPUC's Division of Ratepayer Advocates executed a settlement agreement for SCE's outstanding issues concerning SCE shareholder incentives and performance achievements resulting from the demand-side management, energy efficiency, and lowv-income energy efficiency programs from program years 1994-2004. In addition, the's'ettlemnent addresses shareholder incentives anticipated but not yet claimed for performance achievements in program years 1994-1998. The settling parties agreed that it is reasonable for SCE to recover approximately $42 million of these claims plus interest in the near future as full recovery of all of SCE's outstanding claims as well as future claims related to SCE's pre-1998 energy efficiency programs.  ;

On October 27, 2005, the CPUC approved the settlement agreement. As a result of the decision, SCE recognized a $45 million benefit in 2005 for the claims settled and other related items, reflected in the consolidated statements of income caption "Other nonoperating income." . -

InvestigationsRegarding PerformanceIncentives Rewards SCE is eligible undler its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfitetiori, employee injury and illness reporting, and system reliability.

SCE has been conducting irivestigations into its performance under these'PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreportingras further discussed below. As a result of the reported events, the CPUC could 'institute its own proceedings to determine whether and in what aimrounts to order refunds or disallowances of pastarid potential PBR rewards for customer satisfaction, injury and illness reporting, and system reliability portions of PBR. The 'CPUC also may consider whether to impose additional penalties on SCE: SCE cannot predict with certainty 'the outcome of these matters oiestimate the potential amount of refunds, disallowances, and penalties that may be required.' . -  : - .

Customer Satisfaction SCE received two letters in 2003 froml on6'or more anonymous employees alleging that personnel in the service planning group of SCE's transmission and distribution business unit altered or omitted data in' 14

, ':,' - Southern.California Edison Company attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or penalties to SCE under the PBR provisions for customer satisfaction: SCE recordec: aggregate customer satisfaction rewards'of $28 million for-the yearsl998, 1999 and 2000.

Potential customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of approximately $10 million for.2003.

Following its internal investigation, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5 million of the PBR rewards pending that are both attributable to the design organization's portion of the customer. satisfaction rewards for the entire PBIR.

period ('1997-2003)..in addition, SCE also proposed to refuind all of the approximately $2 million of.

customer satisfaction rewards associated with meter reading. As a result of these findings,.SCE accrued a

$9 million charge in the caption "Other nonoperating deductions" on the income'statement in 2004 for the potential refunds of rewards that have been received. - , .  ; .

SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of several supervisory personnel, updating system process and relited documentation for survey reporting, and implementing additional supervisory controls over data collection and processing.

Performance incentive rewards for customer satisfaction'expired in 2003 pursuant to the 2003 GRC.

The CPUJC has not yet opened a formal investigation into this matter.IHowever, it has submitted several data requests to SCE and has requested an opportunity to interview a number of SCE employees in the design organization. SCE has responded to these requests and the CPUC has conducted interviews of approximately 20 employees who were disciplined for misconduct and four senior managers and executives of the transmission .and distribution business unit. - . .

Employee Injury and Illness Reporting . . .

• In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE's employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has received $20 million in employee safety incentives for 1997 through 2000 and, based on SCE's records,'

may be entitled to an additional $15 million for 2001 through 2003.

On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE's performance under the PBR incentive mechanism for injury and illness reporting. SCE disclosed iin the investigative findings to the CPUC that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.

': . . ,  : 4. I ! ' . ' .t .! , '

As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the '.

mechanism for any year before 2005, and it return to ratepayers the $20 million it has already received.

Therefore, SCE accrued a $20 million' charge in the caption "Other nonoperating deductions" on the' income statement in 2004 for the potential refund of these rewards. SCE has also proposed to withdraw the pending rewards for the 2001-2003 time frames.  ; - . ' . -

SCE has taken other remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance and disciplining  !.

employees who committed wrongdoing. SCE submitted a repoft on the results of its investigation to the CPUC on December 3, 2004. As with the customer satisfaction matter, the CPUC has not yet opened a formal investigation into this matter.

.15

Management's Discussion and Analysis of Financial Condition and Results of Operations System Reliability, .;

In light of the problems uncovered with the PBR mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability. On February 28, 2005,'SCE provided its final investigatory report to the CPUC concluding that the reliability reporting system is working as intended.

OTHER DEVELOPMENTS . ' * -

Navajo Nation Litigation -  : ' -' -, .- : , -

A,, ; ' ,  ;. I . ' (.l'I In June 1999, the Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its affiliates, Salt River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply, agreement'for Mohave. The complaint asserts claims for, among other things,-violations of the federal Racketeer Influenced and Corrupt Organizations statute, interference with fiduciary duties and.

contractual relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims.

The complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the full)>

value in royalty rates for the coal supplied to Mohave. The complaint seeks damages of not'less than

$600 million,'trebling of that amount, and punitive damages of not less than $1 billion, as well as a' declaration that Peabody's lease and contract rights to-mine coal on Navajo'Nation lands should be; terminated. SCE joined Peabody's motion to strike the Navajo Nation's complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C: District Court denied these motions for dismissal,'

except for Salt River Project Agricultural Improvement and Power District's motion f6r its separate dismissal from the lawsuit. , . '. . . , . .. ' . , ii ';i '

Certain issues related to this case were addressed by the United States Supreme Court in a separate legal proceeding filed by the Navajo Nation in the United States Court of Federal Claims against the United States Department of Interior. In that action, the Navajo Nation claimed that the Governiment breached its fiduciary duty concerning negotiations relating to the coal lease involved in the Navajo Nation's lawsuit against SCE and Peabody. On March 4; 2003; the Supreme Court concluded, by majority decision', that there was no breach of a fiduciary duty and that the Navajo Nation'did not have a right to relief against the Government. Based on the Supreme Court's conclusion, SCE and Peabody brought motions to dismiss or for summary judgment in the D.C. District Court action but the D.C. District Court denied the motions on; i April 13, 2004.  ! ,  !' ' . .

The Court of Appeals for the Federal Circuit, acting on a suggestion filed by the Navajo Nation on remand from the Supreme Court's March 4,;2003 decision held, in an October 24, 2003 decision that the-Supreme Court's decision was focused on three specific statutes or regulations and therefore did not ;-

address the question of whether a network of other statutes; treaties and regulations imposed judicially enforceable fiduciary duties on the United States during the time period in question. On March 16, 2004, the Federal Circuit issued an order remanding the case against the Government to the Court of Federal Claims, which considered (1) whether the Navajo Nation previously waived its "netwvork of other laws" argument and, (2) if not, whether the Navajo Nation can establish that the Government breached any -

fiduciary duties pursuant-to such "network." On December 20; 2005; the Couit of Federal 'Claims issued its ruling and found that although there was no waiver, the Navajo Nation did not establish that a , a "network of other laws" created a judicially enforceable trust obligation. The Navajo Nation filed a',

notice of appeal from this ruling on February 14, 2006.

Pursuant to ajoint request of the parties, the D.C. District Court granted a stay of theiaction in that court-to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with' !;-

Mohave. Negotiations are ongoing and the stay has been continued until further order of the court. J 16

I' . Southern California Edison Company SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact on the complaint of the Supreme Court's decision and the recent Court of Federal Claims ruling in the Navajo Nation's-suit against the Government, or the impact-of the complaint on the possibility of resumed operation of Mohave following the cessation of operation on December 31, 2005..

Environmental Matters, SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct-and operate new facilities, and mitigate or remove the'eflect of past operations on the environment. SCE believes that it is in substantial compliance with existing environmental regulatory'requirements. ' -. -

SCE's power plants; in particular its coal-fired plants, may be affected by recent developments in federal and state laws and regulations. These laws and regulations, including those relating to sulfur dioxide and nitrogen oxide emissions, mercury emissions, ozone and fine particulate matter emissions, regional haze, and climate change, may require SCE to make significant capital expenditures at its facilities. The developments in certain of these laws and regulations are discussed in more detail below. These developments will continue to be monitored by SCE to assess what implications, if any, they will have on the operation :of domestic power plants owned or operated by SCE, or the impact on SCE's results of operations or financial position. '

The enactment of more stringent environmental laws and regulations could affect the costs and the manner in which SCE's business is conducted and could cause substantial additional capital , '

expenditures. There is no assurance that additional costs would be recovered from customers or that SCE's financial position and results of operations would not be materially affected.

SCE's projected environmental capital expenditures over the next three years are:; 2006 - $482 million; 2007 - $485 million; and 2008 - $500 million. The projected environmental capital expenditures are mainly for undergrounding certain transmission and distribution lines.

Air Quality Standlar(ds.

In 1998; several environmental groups filed suit against the co-owners of the Mohave plant regarding alleged violations of emissions limits. In order to resolve the lawsuit and accelerate resolution of key -

environmental issues regarding the plant, the parties entered into a consent decree, which was approved by the Nevada federal district court in December 1999. The consent decree required the installation of certain air pollution control equipment prior to December 31, 2005 if the'plant was to operate beyond that date. In addition, operation beyond 2005 required that agreements be reached with the Navajo Nation and the Hopi Tribe (Tribes) regarding post-2005 water and coal supply needs.

SCE's share of the costs of complying with the consent decree and taking other actions to allow operation of the Mohave plant beyond 2005 is estimated to be approximately $605 million. Agreement.

with the Tribes on water and coal supplies for Mohave was not reached by December 31, 2005, and it is not currently known whether such an agreement will be reached. No agreement was reached to amend the terms of the federal court consent decree. As a result, Mohave shutdown operation on December 31, ' :

2005. For the Mohave plant to restart operation, it will be necessary for agreements to be reached with the Navajo Nation and.the Hopi Tribe on the water and coal supply issues, and 'for the terms of the consent decree to be met or modified. See "Regulatory Matters-Current Regulatory Developments--.

Mohave Generating Station and Related Proceedings" for further discussion of the Mohave issues.

~.. . .....:....,I

^:,,:

17

Management's Discussion and Analysis of Financial Condition and Results of Operations Climate Change - -, - !A' . ,:; *, ;.. 1 In California, Governor Schwarzenegger issued an executive order on June 1, 2005,'setting forth targets for greenhouse gas'reductions. The targets call for a reduction of greenhouse gas emissions to 2000 levels by 2010; a reduction of greenhouse gas emissions to 1990 levels by 2020; and a reduction of greenhouse gas emissions to 80% below 1990 levels by 2050. The CPUC is addressing climate change related issues in various regulatory proceedings.

SCE will continue to monitor these developments relating to greenhouse gas'emissions to determine their impacts on SCE's operations. Any legal obligation that would require -SCE to reduce substantially its, emissions of carbon dioxide could require extensive mitigation efforts at its Mohave plant if it resumes operations, and would raise considerable uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generating facilities. New regulations could also increase the cost of purchased power, which is generally borne by SCE's customers.'Additional information regarding purchased power costs appears under the heading "Regulatory Matters."':.

EnvironmentalRemediation -  :  : , '

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 estimites 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. - . i '

SCE's recorded estimated minimum liability to remediate its 24'identified sites is $82 million. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination, the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; anid the time periods over which site remediation is expected to occur. SCE believes that,' due to these  :

uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to

$115 million. The-upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also had 31immaterial sites whose total liability ranges from $4 million (the recorded minimum liability) to $9 million. * . .

The CPUC allows SCE to recover environmental remediation costs at certain sites, representing

$30 million of its recorded liability, through an incentive mechanism (SCE may request to include'  ;

additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs~incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $56 million for its estimated minimum environmental-cleariup'costs expected to be recovered through customer rates. ' .;.' . , _. ', ' ,.

SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination and the extent, if any, that SCE may be held 18

Southern California Edison Company responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.

-  :' 4 S . : . i  ;:-,i i'. ::2 .;  :,.; S SCE expects to clean up its identified sites over a period of up to 30 years: Remediation costs in each of!

the next several years are expected to range from $11 million to $25 million. Recorded costs for 2005 were $13 million. 2 , ' - .

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental remediation costs, SCE believes that costs ultimately'recorded will not material.ly affect its results of operations or financial position? There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

., . . . , , J ., . . . . . , . ~

.2  ; ' , . 2;;;.

Federal Income Taxes ! * '. . - '

Edison International has reached a settlement with the IRS on tax-issues and pending affirmative claims relating to its 1991-1993 tax years. This settlement, which was signed by Edison International in March 2005 and approved by the United States Congress Joint Committee on Taxation on-July 27, 2005,'

resulted in a third quarter 2005 net earnings benefit for SCE of approximately $61 million, including interest. This benefit was reflected in the caption "Income tax" on the consolidated statements of income.

i  ;,, .. ,- ,

Edison International received Revende Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its:1994-1996 and -

1997-1999 tax years, respectively. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would benefit SCE as future tax deductions. -. - i -. ; - ;

The IRS Revenue Agent Report for the 1997-1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company. While Edison International intends to defend its tax return position with respect to this transaction,'the tax benefits relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these tax losses are sustained. £i . ' 2I, 2, , . *. .2

I a *i2% * ,'j..!.'

*..',Jl.7.' ssX' In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through 2002 to abate the possible imposition of new-California penalty provisions on transactions that may be considered as listed or substantially similar to listed transactions described in an IRS notice that was published in 2001. These transactions include the SCE subsidiary contingent liabilitycompany ..

transaction described above. Edison International filed these amended returns under protest retaining its appeal lights. -  ; *  ;. i: 1 - ) '

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 andlcounterparty credit losses however 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.-, '

L . 2#.q{.. t*+ ;1'i 4 4 9 L .

19

Management's Discussion and Analysis of Financial Condition and Results of Operations Interest RateRisk i.. ' . ' ' ', *'}

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity purposes, to fund business operations, and to finance capital expenditures. 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-i equity (I 1.4% for 2005 and 11.6% for 2006), which is established in SCE's annual cost of capital proceeding, is set on the basis of forecasts of interest rates and other factors.  ;;

At December 31; 2005, SCE did not believe that its short-term debt and current portion of long-term debt was subject to interest rate risk, due to the fair market value being approximately equal to the carrying value. ~  :;- ,;!'

At December 31, 2005, the fair market value of SCE's long-term debt was $4.8 billion. A 10% increase in market interest rates would have resulted in a $233 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 $256 million increase in the fair market value of SCE's long-term debt. -  :' ; . .

.:!-. . . ' 1'&,

j- . i,.,

Commodity Price Risk !*......... :...v...... , ........

SCE forecasts that it will have a net-long position (generation supply exceeds expected load requirements) in the majority of hours during 2006. SCE's net-long position arises primarily from resource adequacy requirements set by the CPUC which require SCE-to acquire and demonstrate enough' generating capacity in its portfolio for a -planning reserve margin of 15-17% above its peak load as forecast for an average year (see "Regulatory Matters-Current Regulatory Developments-Resource:-

Adequacy Requirements"). SCE has incorporated a 2005 price and volume, forecast from expected sales of net-long power in its 2006 revenue forecast used for setting rates. If actual prices or volumes vary:

from forecast, SCE's cash flow could be temporarily impacted due to regulatory recovery delays, but such variations are not expected to affect earnings. For 2006, SCE forecasts that at certain times it Will' have a net-short position (expected load requirements exceed generation supply)i SCE's forecast net-.;

short position is expected to increase each year, assuming no new generation supply is -added, existing I-contracts expire, SCE generating plants retire, andrload grows. The establishment of a sufficient planning reserve margin mitigates, to some extent,-several conditions that could increase SCE's'net-short position, including lower utility generation due to expected or unexpected outages or plant closures, lower deliveries under third-party power contracts, or higher than anticipated demand for electricity. However, SCE's planning reserve margin may not be sufficient-to supply the needs of all returning directiaccess customers (customers who choose to purchase power directly from an electric service provider other than SCE but then decide to return to utility service). 'Increased procurement costs resulting from the return of direct access customers could lead to temporary undercollections and the need to adjust rates.

SCE anticipates purchasing additional capacity and/or ancillary services to meet its peak-energy '.-

requirements in 2006 and beyond if its net-short position is significantly higher than SCE's current forecast. As of December 31, 2005, SCE entered into energy options and tolling arrangements and forward physical contracts to mitigate its exposure to energy prices in the spot market. The fair market value of the energy options and tolling arrangements as of December 31, 2005, was a net asset of

$25 million. A 10%'increase in energy prices would have resulted in a $208 million increase in the fair market value. A 10% decrease in energy prices would have resulted in a $143 million decrease in the fair market value. The fair market value of the forward physical contracts as of December 31, 2005,mwas a net liability of $49 million. A 10% increase in energy. prices would have resulted in a $52 million increase in the fair market value. A 10% decrease in energy prices would have resulted in a $53 million decrease in the fair market value.

20

'Southern California Edison Company SCE is also exposed to increases in natural gas prices related to its qualifying facilities (QE) contracts, fuiel tolling arrangements, and owned gas-fired generation, including the Mountainview project. SCE purchases power from QFs under CPUC-mandated contracts. Contract energy prices for most nonrenewable QFs are based in large part on the monthly southern California border price of natural gas.

In addition to the QF contracts, SCE has power contracts in which SCE has agreed to provide the natural gas needed for generation under those power contracts, which are known as fuel tolling arrangements.

SCE has an active gas fuel hedging program in place to minimize ratepayer exposure to spot market price spikes. However, movements in gas prices over time will impact SCE's gas costs and the cost of QF power which is related to natural gas prices.

As of Dezember 31, 2005, SCE entered into gas forward transactions including options, swaps and futures, and fixed price contracts to mitigate its exposure related to the QF contracts and fuel tolling arrangements. The fair market value of the forward transactions as of December 31, 2005, was a net asset of $105irnillion. A 10% increase in gas prices would have resulted in a $105.million increase in the fair market value. A 10% decrease in gas prices would have resulted in a!$104 million decrease in the fair market value. SCE cannot predict with certainty whether in the future it will be able to hedge customer risk for other commodities on favorable terms or that the cost of such hedges will be fully recovered in rates. E; -; -- '

SCE's purchased-power costs, as well as its gas expenses and gas hedging costs, are recovered through, ERRA. To the extent SCE conducts its power and gas procurement activities in accordance with its CPUC-authorized procurement plan, California statute (Assembly Bill 57) establishes that SCE is entitled to full cost recovery. As a result of-these regulatory mechanisms, changes in energy prices may impact SCE's cash flows but are not expected to affect earnings. Certain SCE activities; such as contract administration, SCE's duties as the CDWR's limited agent for allocated CDWR contracts, and portfolio dispatch, are reviewed annually by the CPUC for. reasonableness. The CPUC has currently established a maximumn disallowance cap of $37 million for these activities. ,

In accordance with CPUC decisions, SCE, as the CDWR's limited agent, performs certain services for CDWR contracts allocated to SCE-by the CPUC, including arranging for natural gas supply. Financial and legal responsibility for the allocated contracts remains with the CDWR. The CDWR, through coordinal ion with SCE, has hedged a portion of its expected natural gas requirements for the gas tollin;g contracts allocated to SCE. Increases in gas prices overtime, however, will increase the CDWR's gas costs. California state law permits the CDWR to recover its actual costs through rates established by the CPUC. This would affect rates charged to SCE's customers, but .would not affect SCE's earnings or cash flows. : - - - *  ;

Quoted market prices, if available, are used for determining the fair value of contracts, as discussed above. If quoted market prices are not available, internally maintained standardized or industry accepted models are used to determine the fair value. The models are updated with spot prices, forward prices, volatilities and interest rates from regularly published and widely distributed independent sources.

Credit Risk Credit risk arises primarily due to the chance that a counterparty under various purchase and sale contracts will not perform as agreed or pay SCE for energy products delivered. SCE uses a variety of strategies to mitigate its exposure to credit risk. SCE's risk management committee regularly reviews procurement credit exposure and approves credit limits for transacting with counterparties. Some counterparties are required to post collateral depending on the creditworthiness of the counterparty and the risk associated with the transaction. SCE follows the credit limits established in its CPUC-approved procurement plan, and accordingly believes that any losses which may occur should be fully recoverable from customers, and therefore are not expected to affect earnings.

21

Management's Discussion and Analysis of Financial Condition and Results of Operations RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS The following subsections of "Results of Operations and Historical Cash Flow Analysis" provide a discussion on the changes in various line items presented on the Consolidated Statements of Income as well as a discussion of the changes on the Consolidated Statements of Cash Flows.

Results of Operations '!- >  !

Inconiefronz Continuing Operations . ;, , .'. . ,'

SCE's income from continuing operations was $749 million in 2005, compared to $921 million in 2004.

SCE's 2005 earnings included positive items of $61 -million related to a favorable tax settlement (see X !

"'Other Developments-Federal iicome Taxes"), $55 million 'from a favorable FERC decision-on a SCE, transmission proceeding (see "Regulat6ry Matters--Current Regulatory Developments-Transmission:

Proceeding") andra $14 million incentive benefit from generator-refunds related to the California energy crisis period (see "Regulatory !Matters---Current Regulatory Developments-FERC Refund Proceedings"). SCE's 2004 earnings included $329 million of positive regulatory and tax items, primarily from implementation of the 2003 GRC decision that was received *in July 2004. Excluding these positive items, earnings were up $27 million due to higher net revenue, including tax benefits, and lower financing costs, partially offset by the impact of a lower CPUC-authorized rate of return in 2005.

SCE's income from continuing operations in .2004 was $921 million, compared to $882 million in 2003:..

The $39 million increase betwveen 2004 and 2003 was mainly due to the resolution of-regulatory:

proceedings and prior years':tax issues which increased income by'$86 million over 2003. The 2004 proceedings included the 2003 GRC that was resolved-in July'2004'and the 2003 ERRA proceeding addressing power procurement reasonableness that was resolved in the fourth quarter of 2004. Also, in the fourth quarter of 2004, SCE favorably resolved prior years' tax issues. Excluding these items, income decreased $47 million, primarily from the expiration at year-end 2003 of the ICIP mechanism at San Onofre partially offset by the increase in revenue authorized by the 2003 GRC decision. Post-test-year revenue increases for 2004 and 2005, to compensate for customergrowth and increased capital expenditures were authorized in the '2003 GRC decision.

i .  ; . .  :  : i l,.:.,  ; ., . . -. i e .

OperatinggRevenue . .s. - > ,'  ; ' )

SCE's retail sales represented approximately 82%;85%, and 91% 'of operating revenue for the years ended December 31, 2005, 2004, and 2003, respectively. Due to warmer weather during the summer' months, operating revenue during the third quarter of each year is generally significantly higher than other quarters.. ..i; . L .. . . .. .. *. ' . ..

The following table sets forth the 'major.changes in operating revenue:

In millions Year ended December 31, 2005 vs. 2004 2004 vs. 2003 Operating revenue Rate changes (including unbilled) $ 517 $ (677)

Sales volume changes;(includirig inbilled)": - i '  ! 410  ; (159).'

Deferred revenue i - ' ' (324) ' (30)

-Sales for resale'.. ', ' ' 256 164; SCE's variable interest entities-~ " 7'I 177 " 285 Other (including intercompany transactiorns):  ; 16 ! ' ' ' il

.Total -" - ' ' - " $ 1,052 $ (406) 22

, - *Southern California Edison Company Total'operating revenue increased by $1.1 billion in 2005 (as shown in the table above). The variance in.

operating revenue from rate changes reflects the'implementation of the 2003 GRC, effective in August 2004. As a result, generation and distribution rates increased revenue by approximately $166 million and

$351 million, respectively. The increase in operating revenue resulting from sales volume changes was mainly due to an increase in kilowatt-hour (kWh) sold and SCE providiig a greater amount of energy to its customers from its own sources in 2005, compared to 2004. The 'change in deferred revenue reflects the deferral of approximately $93 million of revenue in 2005, resulting from balancing account .

overcollections, compared to the recognition of approximately $231 million in 2004. Operating revenue-from sales for resale represents the sale of excess energy. As a result of the CDWR contracts allocated to SCE, excess energy from SCE sources may exist at certain times, which then is resold in the energy markets. Revenue from sales for resale is refunded to customers through the ERRA rate-making mechanism and does not impact earnings. SCE's variable interest entities revenue represents the recognition of revenue resulting from the consolidation of SCE's variable interest entities on March 31, 2004. ;J ' .-  ; : . . - S t,. ,

Total operating revenue decreased by $406 million in 2004 (as shown in the table above). The reduction in operat ng revenue due to rate changes resulted from the implementation of a CPUC-approved customer rate reduction plan effective August 1, 2003, additional rate changes effective in 2004 resulting from implementation of the 2003 GRC (an increase in distribution rates and a further decrease in generation rates), and an allocation adjustment for the CDWR energy purchases recorded in 2003. The decrease in electricTrevenue resulting from sales volume changes wasmainly due to the CDWR providing a greate; amount cf energy to SCE's customers in 2004, as compared to 2003,partially offset by an increase in kWh sold. Sales for resale increased due to a greater amount of excess energy in 2004, as compared to 2003. As a result of the CDWR contracts allocated to SCE, excess energy from SCE sources may exist at certain times, which then is resold in the energy markets. SCE's variable interest entities revenue'i represents the recognition of revenue resulting from the consolidation of SCE's variable interest entities beginning March 31, 2004. ,  ! :'

Amounts SCE bills'and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers (beginning January 17, 2001); CDWR bond-related costs (beginning November 1;,.

2002) and a portion of direct access exit fees (beginning January 1, 2003) are remitted to the CDWR and, are not recognized as revenue by SCE. These amounts were $1.9 billion, $2.5 billion, and $1.7 billion for the years ended December 31, 2005, 2004, and 2003, respectively.

OperatingExpenses Fuel Expense - .  : . .' .,

. ;! '; f! . I ' ' . '; '.;

>-l ,, it , .:. : . . ; :, i SCE's fuel expense increased $383 million in 2005 and $575 million in 2004 primarily due to the consolidation of SCE's variable interest entities on March 31, 2004 resulting in the recognition of fuel -

expense of $924 million in 2005 and $578 million in 2004. - ' . '

Purchased-PowerExpense. . '

Purchased-power expense increased $290 million in 2005 and decreased $454 million in 2004. The 2005 increase was mainly due to higher firm energy and QF-related purchases, partially offset by net realized and unrealized gains on economic hedging transactions and an increase in energy settlement refunds in 2005, as compared to 2004: Firm energy purchases increased by approximately $670 million resulting from an increase in the number of bilateral contracts in 2005, as compared to 2004, and QF-related purchases increased by approximately $170 million in 2005; as'compared to 2004 (as discussed below). Net realized and unrealized gains related to economic hedging transactions reduced purchased-power expense by ,

23

Management's Discussion and Analysis of Financial Condition and Results of Operations approximately $205 million in 2005, as compared to net realized and unrealized losses of approximately

$25 million which increased purchased-power expense in 2004. Energy settlement refunds received in 2005 and 2004 were approximately $285 million and $190 million, respectively, further decreasing purchased-power expense in these periods (see "Regulatory Matters-Current Regulatory Developments-FERC Refund Proceedings"). The consolidation of SCE's variable interest entities effective March 31, 2004 resulted in a $935 million and $669 million reduction in.purchased-power expense in 2005 and 2004, respectively. The 2004 decrease was mainly due to the consolidation of SCE's variable interest entities and energy settlement refunds received (both discussed above), partially offset by higher expenses of approximately $150 million related to power purchased by SCE from QFs (as discussed below), higher expenses of approximately $100 million resulting from an increase in the number of gas bilateral contracts in 2004, as compared to 2003, and higher expenses of approximately $130 million related to ISO purchases.

Also included in purchased-power expense in 2005 is a $25 million charge related to amounts billed to the Los Angeles Department of Water & Power (DWP) for scheduling coordinator charges incurred by SCE on the DWP's behalf. The scheduling coordinator charges are billed to DWP under a FERC tariff that remains subject to dispute. DWP has paid the amounts billed under protest but requested the FERC i declare that SCE was obligated to serve as the DWP's scheduling coordinator without charge. The FERC accepted SCE's tariff for filing, but held that the rates charged to DWP have not been shown to be just and reasonable and thus made them subject to refund and further review at the FERC. As a result, SCE could be required to refund all or part of the amounts collected from DWP under the tariff. If the FERC ultimately rules that SCE may not collect the scheduling coordinator charges from DWP and requires the amounts collected to be refunded to DWP, SCE would attempt to recover the scheduling coordinator charges from all transmission grid customers through another regulatory mechanism. However, the availability of other recovery mechanisms is uncertain, and ultimate recovery of the scheduling coordinator charges cannot be assured.-

Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments to gas-fired QFs are generally tied to spot natural gas prices.

Effective May 2002, energy payments for most renewable QFs were converted to a fixed price of  ;

5.370-per-kWh. Average spot natural gas prices were higher during 2005 as compared to 2004. The higher expenses related to power purchased from QFs were mainly due to higher average spot natural gas prices, partially offset by lower kWh purchases.

Provisionsfor RegulatoryAdjustment Clauses - Net Provisions for regulatory adjustment clauses - net increased $636 million in 2005 and decreased $1.3 billion in 2004. The 2005 increases mainly result from regulatory adjustments recorded in 2004, net overcollections related to balancing accounts, higher net unrealized gains on economic hedging transactions and lower CEMA-related costs. The net regulatory adjustments of $345 million recorded in 2004 related to the implementation of SCE's 2003 GRC decision and the implementation of an ERRA-related CPUC decision (see "Regulatory Matters-Current Regulatory Developments-Ehergy Resource Recovery Account Proceedings"). In addition to these net regulatory adjustments, the increase reflects higher net overcollections of purchased power, fuel, and operating and maintenance expenses of approximately

$65 million which were deferred in balancing accounts for future recovery, higher net unrealized gains of approximately $95 million related to economic hedging transactions (mentioned above in purchased-power expense) that, if realized, would be refunded to ratepayers, and lower costs incurred and deferred of approximately $95 million associated with CEMA-related costs (primarily bark beetle infestation related costs). The 2003 GRC regulatory adjustments primarily related to recognition of revenue from the rate recovery of pension contributions during the time period that the pension plan was fully funded, resolution over the allocation of costs between transmission and distribution for 1998 through 2000, partially offset by the deferral of revenue previously collected during the incremental cost incentive pricing mechanism for dry cask storage, as wvell as pre-tax gains related to the 1997-1998 generation-related capital additions. The 24

'. ..., I &"  :;. Q ',r!i ;r

. .- * 'Southern California Edison ConmpaIny 2004 decrease was mainly ddie to'the collection of the Procurement-Related Obligations Account  ;

(PROACT) balance in 2003 and the implementation of the CPUC-authorized rate-reduction plan in the summer of 2003, resulting in decreases of approximately $700 million. The decrease also reflects a net effect of regulatory adjustments discussed above and the deferral of costs for future recovery.in the amount!

of approximately $100 million associated with the bark beetle infestation. The 2004 decrease was partially offset by approximately $190 million in settl&ment agreement payments received and refunded to ratepayers and shareholder incentives (see "Regulatory Matters--Current Reguilatoiy Developments--u FERC Refund Proceedings"), the favorable resolution of certain regulators cases recorded in the third quarter of 2003, and an allocation adjustment of approximately $110 million for CDWR energy purchases.

recorded in 2003. 1. . ,,."' ,,.. '

Other Operation and Maintenance Expense .;: .

• p 1 .; .

,,., ,.,,:'  ! ., .' ,,'i'7 i . Ii' SCE's other operating and maintenance expense increased $66 million in 2005 and $385 million in 2004.

The 2005 increase was mainly due to an increase in reliability costs, demand-side management and energy efficiency costs, and benefit-related costs, partially offset by lower CEMA-related costs and generation-related costs. Reliability costs increased approximately $80 million, as compared to 2004, due to an increase in must-run units to improve the reliability of the California ISO systems operations (which are recovered through regulatory mechanisms approved by the FERC). Demand-side!management and energy efficiency costs increased approximately $90 million (which are recovered through regulatory mechanisms approved by the CPUC). Benefit-related costs increased approximately $50 million in 2005, resulting from an increase in heath care costs and value of performance shares. The 2005 increase was partially offset by lower CEMA-related costs (primarily bark beetle infestation related costs) of approximately $95 million and a decre.ase'in generation-related expenses of approximately $90 million,resulting from lower outage and refueling costs (in 2004, there 'was a scheduled major overhaul at SCE's Four Corners coal facility, as well as a refueling outage at SCE's Sari Onofre Unit 2). The 2005 variance also reflects an increase of approximately $35 million resulting from the consolidation of SCE's variable interest entities effective:

March 31, 2004. The 2004 increase was mainly due to approximately $130 million of costs incurred in 2004 related to the removal of trees and vegetation associated with the bark beetle infestation, higher operation and maintenance costs of approximately $60 million related to the San Onofre refueling outages in 2004,'.

operating and maintenance expense of $66 million related to the consolidation of SCE's variable interest entities; higher operation and maintenance costs related to a scheduled major overhaul at SCE's Four .i Corners coal facility and additional costs for 2003 incentive compensation due to upward revisions ini he computation in 2004. These increases wcre partially offset by a decrease in postretirement benefits other' than pensions expense, including the effects of adopting the Medicare Prescription Drug, Improvemefr: and Modernization Act-of 2003 in the third quarter of 2004 and lowerworker's compensation claims in 2004.

Depreciation, Decommissioning and Amortization Expense ,";, ' ., .' a, ..

SCE's depreciation, decommissioning and amortization increased $55 million in 2005 and decreased

$22 million in 2004. The increase in 2005 is mainly due to a change in the Palo Verde rate-making mechanisms resulting from the implementation of the 2003 GRC and an increase in depreciation expense resulting from additions to transmission and distribution assets. The 2004 decrease was mainly due to a change in the Palo Verde and San Onofre rate-making mechanisms in 2003 and 2004, partially offset by an increase in SCE's depreciation associated with additions to transmission and distribution assets, the '

consolidation of SCE's variable interest entities, and an increase in nuclear decommissioning expense.

Other Income'andDeductions.:! *: * .H . ..

'i:,,!- . . l .',, :1

-. is , . , (i i..  : A, I E I ,. - . :. ,X, - . ,

Interedil and DividendIncome SCE's interest and dividend income increased $24 million in 2005 and decreased $80 million in 2004. The undercollections in 2005 as compared to 2004. The 2004 decrease was mainly due to the absence of 25

Management's Discussion and Analysis of Financial Condition and Results of Operations interest income-on the PROACT balance. At July 31, 2003, the PROACT balance was overcollected and was transferred to the ERRA on August 1 2003.

OtherNonoperatingIncome  :.  :'

SCE's other nonoperating income increased $43 million in 2005 mainly due to the recognition of approximately $45 million in incentives related to demand-side management and energy efficiency:

performance (see "Regulatory Matters-Current Regulatory Developments-Demand-Side Management and Energy Efficiency Performance Incentive Mechanisms" for further discussion of this matter) and an increase in shareholder incentives related to the FERC settlement refunds. SCE recorded shareholder incentives of $23 million in 2005 and $12 million in 2004 (see "Regulatory Matters-Current Regulatory Developments-FERC Refund Proceedings" for further discussion)."In addition, other nonoperating .

income includes rewards approved by the CPUC for the efficient operation of Palo Verde of $ 10 million in 2005 and $19 million in 2004. .i InterestExpense - Net ofAnzounts Capitalized .

SCE's interest expense - net of amounts capitalized decreased $49 million in 2005 and $48 million in 2004. Effective July 1, 2003, dividend payments on preferred securities subject to mandatory redemption are included as interest expense based on the adoption of a new accounting standard. The new standard did not allow for prior period restatements, therefore dividends on preferred securities subject to mandatory redemption for the first six months of 2003 are not included in interest expense-net of amounts capitalized in the consolidated-statements of income. In addition, the 2005 and 2004 decreases were also due to lower interest expense on long-term debt resulting from the redemption of high interest rate debt by issuing new debt with lower interest rates. The 2005 decrease also reflects the reversal of approximately $25 million of accrued interest expense as a result of a FERC decision allowing recovery of transmission-related costs (see "Regulatory Matters-Current Regulatory Developments-,

Transmission Proceeding"), partially offset by interest expense on balancing account overcollections.

OtherNonoperatingDeductions SCE's other nonoperating deductions in 2005 includes an accrual of $22 million for system reliability penalties under a performance incentive mechanism. Based on recorded data through December 2005, SCE expects it will incur a penalty of $22 million under the reliability performance mechanism for 2005.

The 2004 increase was mainly due to a $29 million pre-tax charge for the anticipated refund of certain previously received performance incentive rewards, aswell as-the accrual of $6 million in system reliability penalties (see "Regulatory Matters-Current Regulatory Developments-Investigations Regarding Performance Incentive Rewards").  : . -

Minority Interest ..

Minority interest represents the effects of the adoption of a new accounting pronouncement in second quarter.2004 related to SCE's variable interest entities.  ; -

Income Taxes  : .' a  : - - -  ;-

The composite federal and state statutory income tax rate was approximately 40% for all periods presented. The lower effective tax rate of 28.1 % realized in 2005 was primarily due to settlement of the 1991-1993 IRS audit cycle as well as adjustments made to the tax reserve to reflect the issuance of new j.; ,: .

26

I ,::",Southern California Edison Compainy IRS regulations and the favorable settlement 'of other federal and state tax audit issues. The lower effective tax rate of 32.2% realized'ii 2004 was primarily due to adjustments to tax liabilities relating to prior years. The lower effective tax rate of 30.5% realized in 2003 was primarily due to the resolution of a FERC rate case and recording the benefit of a favorable resolution of tax'audit issues. -.

InconmeJ om DiscontinuedOperations Earnings from discontinued operations during 2003 include a gain on sale' and operating results totaling

$50 million from SCE's pipeline business which was sold in the third quarter of 2003. '-

Historical Cash Flow Analysis Cash Flows from OperatingActivities Net cash provided by operating activities was $2.4 billion in 2005, $2.3 billion in 2004 and $2.6 billion in 2003. 'rhe 2005 'change in cash provided by operating activities from continuing operations was mainly due the results from the timing of cash receipts and disbursements related to working capital items. The 2004 decrease in cash provided by operating activities from continuing operations was mainly due to SCE's implementation of a CPUC-approved customer rate reduction plan effective August I, 2003.

and the timing of cash receipts and disbursements related to working capital items.

Cash Flows from Financing Activities

'' ' -- t' -i .1,  ; -, ,, , , ,. ,i SCE's short-term debt is normally used to working capital requirements. Long-term debt is used mainly to finance the utility's rate base. External financings are influenced by market conditions and other factors. ' - . i ; l *l  ; , ', >'

SCE financing activities in 2005 included activities relating to the rebalancing of SCE's capital structure.

SCE's first quarter 2005 financing activity included the issuance of $650 million of first and refunding mortgage bonds. The issuance included $400 million of 5% bonds due in 2016 and $250 million of 5.55% bonds due in 2036. The proceeds were used to redeem the remaining $50,000 of its 8% first and refunding mortgage bonds due February 2007 (Series 2003A) and $650 million of the $966 million 8/'-l.

first and refunding mortgage bonds due February 2007 (Series 200313). SCE's second quarter financing activity included the issuance of $350.million of its 5.35%'first and refunding mortgage bond due in 2135 (Series 2005E). A portion of the proceeds was used to redeem $316 million of its 8% first and refunding mortgage bonds due in 2007 (Series .2003B). In addition, in April 2005,WSEissued four million shares of Series A preference stock (non-cumulative, $100 liquidation value) and received net proceeds of approximately $394 million.-Approximately $81 million of the'proceeds was used to redeem all the outstanding shares of its $100 cumulative preferred stock, 7.23% Series, and approximately $64 million of the proceeds was used to redeem all the outstanding shares of its $ 100 cumulative preferred stock, 6.05% Series. SCE's third quarter 2005 financing activity included the issuance of two million shares of, Series B preference stock (non-cumulative, $100 liquidation value) and received net proceeds of approximately $197 million. Financing activities in 2004 also included dividend payments of

$214 million to Edison International.* ' i. '. .  ;'.'

SCE financing activities in 2004 include the issuance of $300 million of 5% bonds due in 2014,

$525 million of 6% bonds due in 2034 and $150 million of floating rate bonds due in 2006 all issued during the first quarter of 2004. The proceeds from these issuances were used to call at par $300 million-of 7.25O,4 first and refunding mortgage bonds due March 2026, $225 million of 7.125% first and refunding mortgage bonds due July 2025, $200 million of 6.9% first and refunding mortgage bonds due October 2018, and $100 million ofjunior subordinated deferrable interest debentures due June 2044. In addition, during the first quarter of 2004, SCE paid the $200 million outstanding balance of its credit

. . ' . . - -, . . , .

. . , 4..

27

Management's'Discussion and Analysis of Financial Condition and Results of Operations facility, as well as remarketed approximately $550 million of pollution-control bonds with varying .'

maturity dates ranging from 2008 to 2040; Approximately $354 million of these pollution-control bonds had been held by SCE since 2001 and the remaining $196 million were purchased and reoffered in 2004.

In March 2004, SCE issued $300 million of 4.65% first and refunding mortgage bonds due in 2015 and*

$350 million of 5.75% first and refunding mortgage bonds due in 2035. A portion of the proceeds from the March 2004 first and refunding mortgage bond issuances were used to fund the acquisition and construction of the Mountainview project. During the third quarter, SCE paid $125 million of 5.875%

bonds due in September.2004. During the fourth quarter, SCE issued $150 million of floating rate first and refunding mortgage bonds due in 2007. Financing activities in 2004 'also included dividend payments of $750 million to Edison International.

SCE's financing activities during 2003 included an exchange offer of $966 million of 8.95% variable rate notes due November 2003 for $966 million of new series first and refunding mortgage bonds due '

February 2007. In addition, during 2003, SCE repaid $125 million of its 6.25% bonds, the outstanding balance of $300 million of a $600 million one-year term loan due March 3, 2003, $300 million on its revolving line of credit, and $700 million of a term loan due March 2005. The $700 million term loan was retired with a cash payment of $500 million and $200 millioh drawn on a $700 million credit facility, that expires in 2006. SCE's financing activities also include a dividend payment of$945 million to Edison International. - -  : -

• Cash Flowsfrom Investing Activities Cash flows from investing activities are affected by additions to property and plant and funding of nuclear decommissioning trusts.'  ;

Investing activities include capital expenditures of $1.8 billion, $1.7 billion and $1.2 billion in 2005, 2004 and 2003, respectively, primarily for transmission and distribution assets, including $166 million related to the Mountainview project and approximately $59 million and $70 million for nuclear fuel" acquisitions in 2005 and 2004, respectively. In addition, investing activities in 2004 include $285'million of acquisition costs related to the Mountainview project. -.

DISPOSITIONS AND DISCONTINUED OPERATIONS ' l ; -'

In July 2003, the CPUC approved SCE's sale of certain oil storage and pipeline facilities to Pacific Terminals LLC for $158 million. In third quarter 2003, SCE recorded a $44 million after-tax gain to .

shareholders.iln accordance with an accounting standard related to the-impairme'nt and disposal of long-lived assets; this oil storage and pipeline facilities unit's results have been accounted foir as a discontinued operation in the 2003 financial statements. For 2003, revenue from discontinued operations.

was $20 million and pre-tax income was '$82 million. . -i ACQUISITION - ,  : !

In March 2004, SCE acquired Mountain'vie'w Power Company LLC, which consisted of a power plant in the early stages of construction in Redlands, California. The Mountainview generating facility is now '

operating, providing southern California with additional generating capacity of 1,054 MW. As a result, customers will receive over the'life of the asset, a $58 million net present'value benefit from "bonus" tax '

depreciation.' On January 10, 2006; the FERC accepted the use of the 2005 CPUC-approved rateof return to be applied to the Mountainview power-purchase agreement. -.

• 'iI'. .~ . . j.'I

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CRITICAL ACCOUNTING ESTIMATES -  : . K , ! .,

The accounting policies'described below'are viewed by management as critical because their application is the most relevant and material to SCE's results of operations and financial position and these policies 28

Southern CaliforniaEdison Company require the use of material judgments and estimates; Many of the critical accounting estimates discussed below generally do not impact:SCE's earnings since SCE applies accounting principles'for rate-regulated enterpriscss. However, these critical accounting estimates may impact amounts reported on the consolidated balance sheets. , i 'A Rate Regulated Enterprises SCE applies accounting principles for rate-regulated enterprises to the portion of its operations, in which regulators set rates at levels intended to recover the estimated costs of providing service, plus a return on capital. flue to timing and other differences in the collection of revenue, these principles allow an incurred *-ostthat would otherwise be charged to expense by a nonregulated entity to be capitalized as a regulatory asset if it is probable that'the cost is recoverable through future rates and conversely allow creation of a regulatory liability for probable future costs collected through rates in advance. SCE's management continually assesses whether the 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 speci Fic incurred cost or a similar incurred cost to SCE or other rate-regulated entities in California, and assurances from the regulator (as well as its primary intervenor groups) that the incurred cost will be treated as an allowable cost (and not challenged) for rate-making purposes. Because current rates include the recovery of existing regulatory assets and settlement of regulatory liabilities, and rates in effect are I expected to allow SCEto cam a reasonable rate of return, management believes that existing regulatory..

assets anI liabilities are probable of recovery. This determination reflects the current political and K regulatory climate in California and is subject to change in the future. If future recovery of costs cease s 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, 2005, the consolidated balance sheets included regulatory, assets of $3.5 billion and regulatory liabilities of $3.6 billion. Management continually evaluates the anticipated recovery of regulatory assets, liabilities, and revenue subject to refund and provides for '

allowances and/or reserves as appropriate.

Derivative Financial Instruments and Hedging Activities '  : 'K ' '.

. -~ . , ,'4j ..  ; ' i.,,*:*!, 1A.F.

- "' .-  ; i SCE follows the accounting standard for derivative instruments and hedging activities, which requires :

derivative financial instruments to be recorded attheir fair value unless an exception applies. The' accounting standard also requires that changes in a derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Fornderivatives that qualify .for hedge.

accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings. '- J. "^  :

Derivative assets and liabilities are shown at gross amounts on the balance sheet, except that net presentation is used when SCE has the legal right of setoff, such as multiple contracts executed with the same counterparty under master netting arrangements.

SCE entcrs into contracts for power and gas-options, as well as'swaps,'futures and for vard contracts in order to mitigate its exposure to increases in natural gas and electricity pricing; These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. Hedge accounting is not used for these transactions. Any fair value changes for recorded derivatives are offset through a regulatory mechanism; therefore, fair value changes do not affect earnings.

Unit-speciific contracts (signed or 'modified after June 30, 2003) in'which SCE takes virtually all of the output of a facility are generally considered to be leases under accounting rules. Leases are not derivatives and are not recorded on the balance sheet unless they are classified as capital leases.

,29

Management's Discussion and Analysis of Financial Condition and Results of Operations Most of SCE's QF contracts are not required.to be'recorded on its balance sheet. However, SCE . -

purchases power from certain QFs in which the contract pricing is based on a natural gas index, but the power is not generated with natural gas. The portion ofthese contracts that is not eligible for the normal purchases and sales exception under accounting rules is recorded on the balance sheet at fair value, based on financial models.

Management's judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal sales and purchases exception applies or whether individual transactions qualify for hedge accounting treatment. '.

Determining the fair value of SCE's derivatives under this accounting standard is a critical accounting, estimate because the fair value of a derivative is susceptible to significant change resulting from a number of factors, including volatility of energy prices, credits risks, market liquidity and discount rates.

See "Market Risk Exposures" for a description of risk management activities and sensitivities to change in market prices. - . - -

Income Taxes . . ' , . ' , '

SCE and its subsidiaries are included in Edison International's consolidated federal income tax and combined state franchise tax returns. Under an income tax allocation agreement approved by the CPUC, SCE's tax liability is computed as if it filed a separate return. -

The accounting standard for income taxes requires the asset and -liability approach for financial accounting and reporting for deferred income taxes. SCE uses the asset and liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ,  ; - .

As part of the process of preparing its consolidated financial statements, SCE is required to estimate its income taxes in each jurisdiction in which it operates. This-process involves estimating actual current 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 tax laws. The application of these positions is subject to interpretation and audit by the IRS. As further described in Other Developments-Federal Income, Taxes," the IRS has raised issues in the audit of Edison International's tax returns with respect to certain issues at SCE. -. - , . . - - -

-, J- . . ,', jA ;'.'."'!.i Management continually evaluates its income tax exposures and provides for allowances and/or reserves as appropriate.

AssetImpairment - . - J s . . ,'

SCE evaluates long-lived assets whenever indicators of potential impairment exist. Accounting standards require that if the undiscounted expected future cash flow from a company's assets or group of assets (without interest charges) is less than its carrying value, an asset impairment must be recognized in the, financial statements. The amount of impairment-is determined by the difference between the carrying amount and fair value of the asset.  ;

. :! -  : "i-... . . . ;t I The assessment of impairment is a critical accounting estimate because significant management judgment is required to determine& (1) if an indicator of impairment has occurred, (2) how assets should be, 30

- . . . ;  ;. Southern California Edison Company grouped, (3) the forecast of undiscounted expected future cash flow over the asset's estimated useful life to determine if an impairment exists, and (4) if an impairment exists, the fair value of the asset or asset '

group. Factors that SCE considers important; which could trigger an impairment, include operating losses from a project, projected future operating losses, the financial condition of counterparties,'or significant -

negative industry or economic trends.' ."; i ."

Nuclear'Decommissioning - at '- .- ,.

SCE's legal asset retirement obligations (ARO) related to the decommissioning of its nuclear power facilities are recorded at fair value. The fair value of decommissioning SCE's nuclear power facilities are based on site-specificestudies performed in 2005 for SCE's San Onofre and Palo Verdernuclear facilities.-

Changes in the estimated costs, timing of decommissioning, or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission these facilities. SC'E estimates that it will spend approximately $11.4 billion through'2049 to decommission-its active nticlenr facilities. This'estimate is based on SCE's decommissioning cost methodology used for rate-making' purposes, escalated at rates ranging from 1.7% to 7.5% (depending on the cost element) annually.

i .. - . . *., o Nuclear decommissioning costs are recovered in utility rates. These costs are expected to be funded frcm independent decommissioning trusts that currently receive contributions of approximately $32 million per year. As of December 31, 2005, the decommissioning tnist balance was $2

9 billion. Contributions to' the decommissioning trusts are reviewed every three years by the CPUC. The contributions are:'

determined from an analysis of estimated decommissioning costs, the current value of trust assets and long-term forecasts of cost escalation and'after-tax return on trust investments. Favorable or unfavorable investment performance in a'period will not change the amount of contributions for that period '

However, trust performance for the three years leading up to a CPUC review proceeding will provide input into future contributions. The CPUC has set certain restrictions related to the investments of these trusts: If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates. Trust funds are recorded bn the balance sheet at'market value.

,' ', ,  : ': ' / ' -:. '

Decommissioning of San Onofre Unit I is underwvay. All of SCE's San Onofre Unit I decommissioning costs will be paid from its nuclear decommissioning trust funds, subject to CPUC review.'The estimated' remaining cost to decommission San Onofre Uniit1l of $186 million at of December 31, 2005 is recorded as an ARO liability. - .7 . ' ' . i I .  :

Pensions and Postretirement fBenefits Other than Pensions' '

Pension and other postretirement obligations and the related effects on results of operations are calculatedc 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 heath care plans. These critical assumptions are evaluated at least annually. Other assumptions, such'as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience. . - - '

• . . . -I - . . ,

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 Three yield curves were considered: two corporate yield curves (Citigroup and AON) and a curve based on treasury rates (plus 90 basis points). SCE also compared the yield curve analysis against the Moody's AA Corporate bond rate. At the December 31, 2005 measurement date, SCE used a discount rate of 5.'% for both pensions and postretirement benefits other than pensions (PBOP).

. . ,  :.  : - .  ! . -  :..-.I; i 't,'-*i.  ; ?; .'!

4.;-Rt..1 31

Management's Discussion and Analysis of Financial Condition and Results of Operations To'determine the expected long-tern rate of return on pension plan assets, current and expected asset: i, allocations are considered, as well as historical and expected returns on plan assets. The expected'rate'of return onplan assets was 7.5% for pensions and 7.1% for'PBOP A portion of PBOP trusts asset returns are subject to taxation; so the.7.1% figure above is determined on an after-tax basis: Actual time-.

weighted, annualized returns on the pension plan assets were 11.0%, 6.0% and 10.9% for the one-year, five-year and ten-year periods ended December 31, 2005, respectively. Actual time-weighted, annualized returns on the PBOP plan assets were 6.3%, 3.3% and 8.3% over these same periods..Accounting*:

principles provide that differences between expected and actual returns are recognized over the average futureserviceofemployees." - , - +' a k . , . , i t q ~~~~~~~~. . ; . i. !'"

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SCE records pension expense equal to 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 accounting standards is accumulated as a regulatory asset or liability,,and will, over time, be recovered from or :

returned to customers. As of December 31, 2005, this cumulative difference amounted to a regulatory liability of $88 million, meaning that the rate-making method has recognized $88 million more in expense than the accounting method since implementation ofthe pension accounting standard in 1987.

Under accounting standards, if the accumulated benefit obligation exceeds the market value of plan assets at the measurement date, the difference may result in a reduction to shareholders' equity through a charge to other comprehensive income, but would not affect current net income. The reduction to other comprehensive income would be restored through shareholders' equity in future periods to the extent the market value of trust assets exceeded the accumulated benefit obligation: This assessment is performed annually. - ; *. -

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

At December31, 2005, SCE's PBOP plans had a $2.3 billion benefit obligation. Total expense for these:

plans-was $78 million for 2005. The health care cost trend rate is 10.25% for.2006, gradually declining to 5% for 2011 and beyond. Increasing the health care cost trend rate by one percentage point would X *, -

increase the accumulated obligation as of December 31, 2005 by $271 million and annual aggregate service and interest costs by $19 million. Decreasing the health care cost trend rate by. one percentages.;:

point would decrease the accumulated obligation as of December 31, 2005 by $243 million and annual aggregate service'and interest costs by $17 million. :,1;.:,  :":', '

NEWACCOUNTINGPRINCIPLES. l -i . 'r! .*  ! '. '

In March 2005, the Financial Accounting Standards Board issued an interpretation related to accounting for conditional ARO. This interpretation clarifies that an entity is-required to recognize a liability for the fair value of a conditional ARO if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. This interpretation was effective as of December 31, 2005.6 SCE identified conditional AROs related to:; treated wood poles, hazardous materials such as i.,

mercury and polychlorinated biphenyls-containing equipment; and asbestos removal costs at buildings...

Since SCE follows accounting principles for rate-regulated 'enterprises and receives recovery of these costs through rates, implementation of this interpretation increased SCE's-ARO by $14 million, but did.

not affect SCE's earnings. , ' ;' . 'I'. i ' '

A new accounting standard requires companies to use the fair value accounting method for stock-based compensation. SCE is required to implement the new standard in the first quarter of 2006 and will apply 32

..- '.' .: i :'-, I I Southern California Edison Company the modified prospective transition method. Under the modified prospective method, the new accounting standard will be applied effective January 1, 2006 to the unvested portion of awards previously granted and will be applied to all prospective awards; Prior financial statements will not be restated under this' method. The new accounting standard wvill result in the recognition of expense for all stock-based compensation awards; previously, SCE used the intrinsic value method of accounting, at times resulting in no recognition of expense for stock-based compensation. . ,.

COMMITMENTS AND INDEMNITIES SCE's commitments for the years 2006 through 2010 and thereafter are estimated below:

' i , ', ' ' '; I, , '  ; ,  :  : i¢ 2 In millions . - 2006 , 2007 2008--- 2009 20;2O010 Therefmfter Long-term debt maturities and ' - .

sinking fund requirements"t ) $ 823 $ 622, $ 596 $ 210 . L$ 442:-; $ 7,044; Fuel supply contract payments  ! .126 i] <- 64 i; *64 *-,,..!40 . 47 ,-22 Purchasedl-power capacity payments , _842 _775 . 528 ,417., 393, 2,6E1 Unconditional purchase obligations ,, 5 5 . ,5 , 5 - 6 1,26. 6.,6 Operating lease obligations 192 301 271 , ' 213 ,, 208  : 5 Capital lease obligations 3 4 4 ' 4 4 -

Employer benefit plans contributions(2) 128 - - - -

(I) Amoint includes"'cheduled principal payments for debt outstanding as of December3i, 2005, assuming

'lonig-terni debt is held to maturity, anid related fore'aist interest payments over the applicable period of the debt.

(2) Amoint includes estimated contributions to the pension plans and postretirement benefits other than pensions '

The estimated contributions beyond 2006 are not available.- .

Fuel Supply Contracts , ' : .  ; . .', . .r.

SCE has fuel supply contracts which require payment only if the fuel is made available for purchase.

SCE has a coal fuel contract that requires payment of certain fixed charges whether or not coal is delivered.

Power 1 urchasc Contracts SCE has power-purchase contracts with certain QFs (cogenerators and small power producers) and other power producers. These contracts provide for capacity payments if a facility meets certain performance obligations and energy payments based on actual power supplied to SCE (the energy payments are not included in the table above). There are no requirements to make debt-service payments. In an effort to replace higher-cost contract payments with lower-cost replacement power, SCE has entered into purchased-power settlements to end its contract obligations with certain QFs. The settlements are reported as power-purchase contracts on the consolidated balance sheets.

Unconditional Purchase Obligations SCE has an unconditional purchase obligation for firm transmission service from another utility.

Minimum payments are based, in part, on the debt-service requirements of the transmission service provider,. whether or not the transmission line is operable. The contract requires minimum payments of

$62 million through 2016 (approximately $6 million per year).

33

Management's Discussion'and Analysis of Financial Condition and Results of Operations Operating and Capital Leases .

SCE has operating leases, primarily for vehicles (with varying terms, provisions and expiration dates). Unit-specific contracts (signed or modified after June 30, 2003) in which SCE takes virtually all of the output of a facility are generally.considered'to be leases under accounting rules. At December31, 2005, SCE had six power contracts that were classified as operating leases and one power contract that was classified as a capital lease (executed in late 2005).

Indemnity Provided as Part of the Acquisition of Mountainview In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to specific environmental claims related to'SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. The generating station has not operated since early 2001, and SCE retained certain responsibilities with respect to -  ;

environmental claims as'part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity. ! '

Other SCE Indemnities -- - .

SCE provides other indemnifications through contracts entered into in the normal course of business.

These are primarily indemnnifications against adverse litigation outcomes in connection with undervriting agreements, and specified environmental indemnities and income taxes with respect to assets sold. SCE's obligations under these agreements may be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. SCE has not recorded a liability related to these' indemnities.

334

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'N 35

Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholder of Southern California Edison Company In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, cash flows and common shareholder's equity present fairly, in all material respects, the financial position of Southern California Edison Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note I to the consolidated financial statements, the Company changed the manner in which it accounts for financial instruments with characteristics of both debt and equity as of July 1, 2003, variable interest entities as of March 31, 2004, and asset retirement costs as of December 31, 2005.

Los Angeles, California March 6, 2006 36

Consolidated Statements of Income Southern California Edison Company In millions Year ended December.3 1:, :; 2005 2004 200^_

Operating revenue $ 9,500 $ 8,448 $ 8,85g.

Fuel , 1,193 810 235 Purchased power 2,622 2,332 2,785 Provisions for regulatory adjustment clauses - net 435 (201) 1,13 8 Other op ration and maintenance 2,523 2,457 2,072 Depreciation, decommissioning and amortization 915 . 860 882 Property and other taxes 193 177 168 Net gain on sale of utility property and plant (10) - (5)

Total operating expenses 7,871 6,435  ; 7,276 Operating income 1,629 2,013 1,578 Interest and dividend income 44 20 10D Other nonoperating income .. -1277 .. 84 72 Interest expense -- net of amounts capitalized (360) (409) " (457)

Other noioperating deductions (65) i(69) (23L Income from continuing operations before tax.

and minority interest 1,375 . 1,639 1,270 Income tax 292 438 388 Minority interest 334- 280 -_

Income from continuing'operations . . . 749 921 882 Income from discontinued operations - net of tax - 50 Net income 749 921 . 932 Dividends on preferred stock subject to mandatory redemption - . 5 Dividends on preferred stock

-not subject to mandatory redemption - 24 6 5.

Net income available for common stock $ 725 $ 915 $ 922 Consolidated Statements of Comprehensive Income In millions Year ended December 31, 2005 2004 2003 Net income S 749 $ 921 $ 932 Other comprehensive income (loss), net of tax:

Minimum pension liability adjustment (1) (1) (4)

Amortization of cash flow hedges 2 3 1 Comprelhensive income S 750 $ 923 $ 929

.I mu, The accompanying notes are an integral part of these financial statements.

.37

Consolidated Balance Sheets ..  ;~

In millions . December 31,, 2005 .2004.

ASSETS Cash and equivalents' $ 143 $ 122 Restricted cash I57 '61 Margin and collateral deposits 178 66 Receivables, less allowvances of $33 and $31 for uncollectible accounts at respective dates .. 849 618 Accrued unbilled revenue ' 291 -320 Inventory 22 ' 196' Accumulated deferred income taxes net 134 Trading and price risk management aisset 237 .26.

Regulatory assets 5.53653 Prepayments and other current assets -92 . 46~

Total current assets 2,603  :..2,142 Nonutility property -'less accumulat~ed provision for depreciation of $569 and $554 at respective dates . 1,086 ~ .960 Nu-clear decommissioning trusts 2,907. 2,757 Other investments 80 '. 104 Total investments and other assets'~ -.. 4,073 3,82 1' Utility plant, at orig inal cost:

Transmission and distribution . 16,7'60 15,685 Generation 1,370 4i;356.

Accumulated provision for depreciation (4,763), (4,506)

Construction wvork in progress 956 789 Nuclear fuel, at amortized cost 146 '151

-Total utility-plant ...-.. ...- 14,469' 13,475 Regulatory assets .- 3,013 - 3,285 Other long-term assets 545 567 Total regulatory assets and other long-term assets 3,558 3,852 Total assets S 24,703 $ 23,290 The accompanying notes are an integral part of these financial statements.

'38

Consolidated Balance Sheets Southern California Edison Company In 'millions, except'share amounts .-,eeme.1;. . . 2005 ..20041 LIABILITIES AND SHAREHOLDERS' EQUITY Short-term debt $ - <$ 88 Long-term debt due within one year 596 246.

Preferred stock to be redeemre'd w~ithiniione'y(ar - 9 Accounts. payable.. 898, .700 Accrued taxes .242, ~ 357 Accrued interest 106 .115 Counterparty collateral .183 2-Custome.- deposits 1183 168 Book overdrafts 257 *23 2 Accumulated deferred income taxes - net 5 -

Regulatory liabilities ,. ~ . . . . 681 490 Other current liabilities 810l. 643 Total current liabilities I:,.3,961 3,048 Long-te im debt 4,669 5,225 Accumulated deferred income taxes - net 2,815 2,865 Accumulated deferred investment tax credits 119 126 Custo'me;- advances and other deferre credits 550 510

.Power-ptirchase contracts ..-- 165 130 Preferred stock subject to mandatory~redemption .. . .~.-139.

Accumulated provision for pensions and benefits 500 417 Asset retilrement obligations .2,621 2,183 Regulatory liabilities :1.2,962 3,355 Other lorig-term. liabilities 284" 23 2 Total detrerred credits and other liabilities 10,016 ~ 9,95 8 Total liabilities .. 18,646 18,231 Commitments and contingencies (Notes 8 and 9)

Minority interest -. 398, .40)

Common stock, no par value (434,888,104 shares outstanding at each date) 2,168216 Additional paid-in capital .. 361- '350-

• Acumulaited other, comprehensive los's (1)(17).

Retained earnings 2,417 .2,020 Total common shareholder's equit 4,930 4,521 Preferreil and preference stock .

not sul ject to mandatory redemption .. . . 729 .1,129-Total shaireholders' equity ;5,f659465

-Total liab~ilities anidshareholders' equity.- $ 24,70!3' $ 23,290

. I. .. -_ .. . . . .1 . . . .. .- - . . . .. . . . . . I.. I . I - :_ ... . -

I . I . . -  ;,O :  ;. , .. , " J . . . I .

The accompanying notes are an integral part of these financial statements.

4 "I . ; 1  ! - ,  :  : ,

.39

Consolidated Statements of Cash Flows . .

2003 In millions Year ended December 31, . ,- 2005 2004 Revised(X)

Cash flows from operating activities:.. .

Net income -749 - -$ 921 S 932-Less: income from discontinued operations - - (50)

Income from continuing operations 749' 921 . 882 Adjustments to reconcile to net cash provided by operating activities:

Depreciation, decommissioning and amortization 915 860 882 Other amortization 96 90 101 Minority interest 334 280 Deferred income taxes and investment tax credits 34 .514 (104)

Regulatory assets - long-term 387 442: . 535 Regulatory liabilities - long-term (168) (69) (48)

Other assets 46 (44) . 117 Other liabilities 72 18 . (364)

Margin and collateral deposits - net of collateral received 70 (33) '5 Receivables and accrued unbilled revenue -. . . (202) . . (9) .- 185 Trading and price risk management assets (211) (23) 113 Inventory, prepayments and other current assets (66) 13 (35)

- Regulatory assets -short-termrn 17 -- (254) - 13,268 Regulatory liabilities-short-term - 192 (169) . (12,486).

Accrued interest and taxes .' (126) (111) (223)

Accounts payable and other current liabilities 251 (152) . .(18.1)

Operating cash flows from discontinued operations - - , . (34)

Net cash provided by operating activities 2,390 2,274 2,613v Cash flows from financing activities:

Long-term debt issued and issuance costs 980 ., 1,747 . . (11)

Long-term debt repaid (1,040) (966) (1,263)

Bonds remarketed - net - .350; Issuance of preference stock - -. 591 Redemptionofpreferredstock.. . . ' (148); (2) . (6).

Rate reduction notes repaid (246) (246) - . (246)

'Short-term debt financing- net .. (88) '- (112) (4)

Change in book overdrafts 25 ' 43 65 Shares purchased for stock-based compensation (115) (60) (13)

Proceeds from stock option exercises Hi 53 29 ' . ' 3 Minority interest .  ; . - . . (345) (290)  ;

Dividends paid (234) (756) . (955)

Net cash used by financing activities (567) . (263) * (2,430)

Cash flows from investing activities: * ,

Capital expenditures (1,808) .,,,(1,678) (1,153)

Acquisition costs related to nonutility generation plant - -- '(285)

Proceeds from sale of discontinued operations . _46 1 Proceeds from nucleardecommissioning trust sales 2,067 2,416. , 2,200 Purchases of nuclear decommissioning trust investments (2,159) (2,525)X. (2,286)

Customer advances for construction and other investments -- - 98 -9 13 Net cash used by investing activities (1,802) (2,063) .. (1,080)

Effect of consolidation of variable intcrestentities ' - 79 ' ' .

Net increase (decrease) in cash and equivalents 21 27 (897)

Cash and equivalents, beginning of year 122 95 992 Cash and equivalents, end of year-continuing operations S 143 $ 122 $ 95

( See "Revisions" in Note I for further explanation.

The accompanying notes are an integral part of these financial statements.

40

Consolidated Statements of Changes in Common Southern California Edison Company Shareholder's Equity

• , ; *, , * * , ,*- I. . :f Accumulated Total Additional Other Common Common Paid-in. Comprehensive Retained, Shareholder's In millions Stock Capital Income (Loss) Earnings Equity_

Balance'itDeceniber.31,2002 ' . $2,168 $ 340 $ (16) $ 1,892- $ 4,384 Net income 932 932 Minimum pension liability adjustment (7) (7)

Tax effict 3 .. 3 Amortizal ion of cash flow hedges 2 2 Tax effict * (I) ' , (1)

Dividends declared on common stock - . *, (945) (945)

Dividends declared on preferred stock . ,

subject to mandatory redemption (5) (5)

Dividends declared on preferred stock not sub ect to mandatory redemption - '-(5) (5)

Shares purchased for stock-based compensation (9) (4) (13)

Proceeds from stock option exercises 3 3 Non-cash stock-based compensation ' 5 ' ' 5 Capital stock expense and other ': '2 Balance sit December 31,2003 $ 2,168 $ 338 $ (19) $ 1,868 $ 4,355 Net inconie! *,9 - . . . 921. . 921 Minimum pension liability adjustment (1) .(1).

Amortization of cash flow hedges 5 5 Dividends 'declared on common stock' ' " (750) (750)

Dividends declared 'on preferred stock ' .'

not subject to mandatory redemption ' ' (6) (6)

Shares pu chased for stock-based compensation ' " (17)' (43). ' (60)

Proceeds from stock option exercises' -:- '  : 29 - .29 Non-cash stock-based compensation 30 ;. 30 Capital stock expense and other (1) 1 __

Balanceat Deccmber31,2004 $2,1168 $ 350 $ (17) $ 2,020' $ 4,521 Net incomre 749 .: 749 Minimum pension liability adjustment (2) (2)'

Tax effect I I Amortization of Cash flowh es:! i;. i 4 4 Tax effhct h (2) '(2)

Dividends declared on common stock - ' ' '(285) (285)

Dividends declared on preferred and . . i .; - . ..; -

preference stock not subject to mandatory redemption (24) (24)

Shares puichased for stock-based compensation (19)  ; (95) - (114)

Proceeds from stock option exercises 53 53 Non-cash :;tock-based compensation . . .I. I; . . . . .; I I Tax benef.t related to stock-based awards . . 29 . . 29 Capital stc ck expense and other (10) (1) -(I 1)

Balance at December 31, 2005 $ 2,168 $ 361 $ (16) $ 2,417 $ 4,93D Authorized common stock is 560 million shares. The outstanding common stock is 434,888,104 shares for all years reported. . .. . . .

,2  ; II . ; i l  : l The accompanying notes are an integral part of these financial statements.

41

Notes .to Consolidated Financial Statements Significant accounting policies are discussed in Note 1,unless discussed in the respective Notes for specific topics.

Notel1. Su'mm~ary o'f'Sign'irlc-anitAccountinPolicies SouthemnCaliforinia Edison Company (SCE) is arate-regulated electric utility that suppliec electric~

energy to a 50,000 square-mile area of central, coastal and southern California.

Basis of Presentation The consolidated financial statements include SCE, its subsidiaries and variable interest entities (VIEs) forw~hich SCE is the primary beneficiary. Effective March 31,2004, SCE began consolidating fdur :-

cogeneration projects for which SCE typically purchases 100% of the energy'produced under lonig-term'"

power-purchase agreements, in accordance with a new accounting standard for the consolidation of variable interest entities. Intercompany transactions have been eliminated.

SCE's accounting policies conform to accounting principles generally'accepted in the Uniited,!tates,,

including the accounting principles for rate-regulated enterprises, which reflect the rate-making policies of the California.Public Utilities Commission (CPUC) and the Federal Energy~gegulato~ry-Commission (FERC) ..

Certain prior-year amounts were reclassified to conform to the December 31, 2005 financial statement presentation. ,*;~.

Financial statements prepared ini compliance wvith accounting principles generally accepted in the United States require management to make estimates and assumptions that affect te amounts reporte in th financial statements and Notes. Actual results could differ from those estimates. Certai sinifcn estimates related to financial instruments, income taxes, pensions~and postretirement,benefits other than pensions, decommissioning and contingencies are further discussed in Notes 2,5, 6, 8 and 9 to the..,

Consolidated Financial Statements, respectively.  :'.

SCE's outstanding common stock is owned entirely by its parent company, Edison International.

Cash Equivalents ,

Cash equivalents include original maturities of three months or less. Cash equivalents include othe~r.,

investments of $16 million at December 31, 2005. There were no cash equivalents at December 31, 2004. In addition, at December 31, 2005 and 2004, the VIE segment had $120 million and $90 million of cash and equivalents, respectively. For a discussion of restricted cash, see "Restricted Cash'%,

Debt and Equity In vestments. .,

SCfE has debt and equity investments for the nuclear decommissioning trust funds. Unrealized ansand, los~ses on decommissioning trust funds increase or decrease the related re'gulJator'y assietor liability'.All investments are 'clitssified as available-for-sale..

Dividend Restriction The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International.'

SCE's authorized capital structure includes a common equity component of 48%. SCE determines compliance with this capital structure based on a 13-month weighted-average calculation. At 42

Southern California Edison Company December 31, 2005, SCE's 13-month weighted-average common equity component of total capitalization was 50%. At December 31, 2005, SCE had the capacity to pay $197 million in additional dividends based on the 13-month weighted-average method.! Based on recorded'December3l, 2005 balances, ,:

SCE's common equity to total capitalization ratio was 50.2% for ratemaking purposes. SCE had the capacity to pOay $212 million of additional dividends to Edison International based on December.31, 2005 recorded balances. -. , ,

Inventoty 1 -;

Inventor/ is stated at the lower of cost or market, cost being determined by the first in, first out method for fuel end the average cost method for mhaterials and supplies. .-- ' . - .

Margin and CollateralDeposits i.'

Margin and collateral deposits include margin requirements and cash deposited with counterparties and brokers is credit support unidermaigining agreem'e'nts for poWerrind gas price risk managemeit activities. The amount of margin and collateral deposits varies based on changes in the value of the agreements. Deposits with counterparties and brokers earn interest at various rates.:,, .; is New Accounting Pronouncements . -, i -;

In March 2005, the Financial Accounting Standards Board issued an interpretation related to accounting for conditional asset retirement obligations (ARO). This interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value can be reasonably estimated even though uncertainty exists about the timing and/or method of settlement. This E ';i lo:

interpretation was effective as of December 31, 2005. SCE identified conditional AROs related to:

treated wirobd poles, hazardous materials such as mercuriy and polychlorinated biphenyls-containing equipment; and asbestos removal costs at buildinigs. Since SCE follows accounting principles for rate-r, regulated enterprises and receives recovery of these costs through rates, implementation of this interpretation at SCE did not affect earnings. '  : ' '- ., -

i , lA,,,,; i;',j

. , ., s  ! ,,'. ,

A new accounting standard requires companies to use the' fair value accounting method for stock-based-compensation: SCE is required to implement the new standard in the first quarter of 2006 and will apply' the modified prospective transition method. Under the modified prospective method, the new accounting standard will be applied effective January l 2006 to the unvested portion of awards previously granted and will be applied to'all prospective awards. Prior financial statements will not be restated under this, method. The new accounting standard will result in the recognition'of expense for all stock-based; '

compensation awards; previously, SCE used the intrinsic value method of accounting, at times resulting in no recognition of expense for stfick based compensation.'

,. !; ;, ,* . .- * '; . . ' A, i .A . 3 A;l. ;sSG1blssrj; 43

Notes to Consolidated Financial Statements Othler Nonoperating Income and Deductions . . .- ..

Other nonoperating income and deductions are as follows:

In millions Year.ended December 31, _.:. 12005 _-2004 2003 Allowance for funds used during construction S 25 $ 35 $ 27 Performance-based incentive awards 33 31 21 Demand-side management and energy efficiency performance incentives 45

-Other i, - i - 24 -18' _24 Total other nonoperating income S 127 $ '84 $ 72 Various penalties $ 27 $ 35, $

Other 38 34 23 Total other nonoperating deductions i $ 65 $ 69 $ 23 PlannedMajor Maintenance . . .

Certain plant facilities require major maintenance on a periodic basis. All such costs are expensed as incurred.

,F.-.

Property and Plant . .

Utility Plant .... ,

Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor, construction overhead, a portion of administrative and general costs capitalized at a rate authorized by the CPUC, and an allowance for funds used during construction (AFUDC). AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction.-Currently, ;

AFUDC debt and equity is capitalized during plant construction and reported in interest expense and other nonoperating income, respectively. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset. Depreciation of utility plant is computed on a straight-line, remaining-..

life basis. - , i . '; .

Depreciation expense stated as a percent of average original cost of depreciable utility plant was 3.9% for 2005, 3.9% for 2004 and 4.3% for 2003.. ,

AFUDC - equity was $25 million in 2005, $23 million in 2004 and $21 million in 2003. AFUDC -debt was $14 million in 2005, $12 million in 2004 and $6 million in 2003.

Replaced or retired property costs are charged to the accumulated provision for depreciation. Cash payments for removal costs less salvage reduce the liability for AROs.

Effective January 1,2004, San Onofre Nuclear Generating Station (San Onofre) Units 2 and 3 returned to traditional cost-of-service ratemaking. The July 8, 2004 CPUC decision on SCE's 2003 general rate case returned Palo Verde Nuclear Generating Station (Palo Verde) to traditional cost-of-service ratemaking retroactive to May 22, 2003 (the date a final CPUC decision was originally scheduled to be issued). As authorized by the CPUC, SCE had been recovering its investments in San Onofre and Palo Verde on an accelerated basis; these units also had incentive rate-making plans.

44

Southern California Edison Company SCE's nuclear plant investments made prior to the return to cost-of-service ratemaking are recorded as regulatory assets on its consolidated balance sheets. Since the return to cost-of-service ratemaking, capital additions are recorded in utility plant. These classifications do not affect the rate-making treatment: for these assets. . ,

Estimated useful lives of SCE's property, plant and equipment, as authorized by the CPUC, are as -

follows: - i. .

Generation plant 38 years to 81-years Distribution plant 24 years to 53 years Transmission plant . ' ' '40 years to 60 years . ,  ;

Other plant 5 years to 40 years Nuclear fluel is recorded as utility plant in accordance with CPUC rate-niakin 'lprocedures.

Nonutilit Property -. - -

Nonutility property, including construction in progress, is capitalized at cost, including interest accrued on borrowed funds that finance construction. Capitalized interest was $16 million in 2005, $9 million in 2004, and zero in 2003. The Mountainview power plant is included in nonutility property in'accordance with the rate-making treatment. . '

Depreciation and amortization is primarily comput'ed n a' straiglit-line' ba'sis 'ov'ertle estimated useful lives of nonutility properties and over the lease term for leasehold improvements; Depreciation expense stated as a percent of average original cost of depreciable nonutility property was, on a composite basi:;,

3.6% for 2005. The composite rate for 2004 and 2003 is not disclosed due to the non-comparability of this prope-rty in 2003. The VIEs (commenced consolidation in March 31, 2004) compose a majority of nonutility property. 'i,. ,:' .. , -  !

Nonutility property included in the consolidated balance sheets is comprised of:

In millions December 31, 2005 2004 Furniture and equipment . . 3 a - i Bui I i ,'aiantandepuIpment eu4;p. ...-j ' - i ;d 1,347 ' ' 1 012 Land (including easements)" ' , 34 ' 31 Construction in progress 271 470 ,

x. :; t w ' f! . 4 ,655 . 15514, .

Accumulated provision for depreciation . , , . (569) -i (554)

Nonutility property - net $ 1,086 $ 960 Estimated useful lives for nonutility property are as follows: . -

Furniture and equipment . 3 years to 20 years ' ..  :  :

• Building, plant and equipment 3 years to 40 years Land easements 60 years 45

Notes to Consolidated Financial Statements Asset Retirement Obligations -

I . .  ; . .  ; -

As a result of an accounting standard adopted in 2003, SCE recorded the fair value of its liability for legal AROs, which was primarily related to the decommissioning of its nuclear power facilities. In addition, SCE capitalized the initial costs of the ARO into a nuclear-related ARO regulatory asset, and also recorded an ARO regulatory liability as a result of timing differences between the recognition of costs recorded in accordance with the standard and the recovery of the related asset retirement costs through the rate-niaking process. SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts.

A reconciliation of the changes in the ARO liability is as follows:

In millions ARO liability as of December 31, 2003 $ 2,084 Accretion expense 132 Liabilities settled (33)

ARO liability as of December 31, 2004 2,183 Revisions .. 117 Liabilities added .14 Accretion expense -  ;  ; . 366 Liabilities settled (59) .i .- ...

ARO liability as of December 31, 2005 $ 2,621 Fair value of nuclear decommissioning trusts $ 2,907 Since SCE follows accounting principles for rate-regulated enterprises and receives recovery of these costs through rates; therefore implementation of this new standard and the subsequent interpretation did:

not affect SCE's earnings. The pro forma disclosures for conditional AROs are not shown due to the immaterial impact on SCE's consolidated balance sheet. See "New Accounting Pronouncements" above.

PurchasedPower From January 17, 2001 t6oDecember 31,2002, the California Department of Water Resources (CDWR) purchased power on behalf of SCE's customers for SCE's residual net short poier position (the amount of energy needed to serve SCE's customers in excess of SCE's own generation and purchased power contracts). Additionally, the CDWR signed long-term contracts that provide power for SCE's customers.

Effective January 1I 2003, SCE resumed power procurement responsibilities for its residual net short :

position. SCE acts as a billing agent for the CDWR power, and any power purchased by the CDWR for delivery to SCE's customers is not considered a cost to SCE.

Receivables -.-

SCE records an allowance for uncollectible accounts, as determined by the average percentage of amounts written-off in prior-accounting periods. SCE assesses its customers a late fee of 0.9% per month, beginning 19 days after the bill is prepared. Inactive accounts are written off after 180 days.

46

Southern California Edison Company Regulatory Assets and Liabilities In accordance with accounting principles for rate-regulaed'enterprises, -SCE records regulatory assets, which represent probable future recovery of certain costs from. customers through the rate-making process, Hand regulatory liabilities, wvhich represent probable future credits to customers through the ra-te-mak ing process.

Included in these regulatory assets and liabilities are SCE's regulatory balancing accounts. Sales,,

balancing accounts accumulate differences betwveen recorded revenue and revenue SCE is authorized ta collect through rates. Cost balancing accounts accumulate differences between recorded costs and costs SCE is authorized to recover through rates. Undercollections are recorded as regulatory balancing account itssets: Overcollections are recorded as regulatory balancing account liabilities. SCE regulatory 9s balancirig accounts accumulate balances until they are refunded to or received from SCE's customers through authorized rate adjustments. Primarily all of SCE's balancing accounts can be classified as one of the following types: generation'-revenue related, distribution-revenue related, generation-cost related!,

distributibn'-cost related, transi~nission-cost related or piublic 'urpose and other cost related.

Balancin!, account undercollections and overcollections accrue interest based on a three-month commercial paper rate published by the Federal Reserve. Income tax effects on all balancing account changes atre deferred.

Amounts included in regulatory assets and liabilities are generally recorded with corresponding offsets to the applicable income statement accounts, except for regulatory balancing accounts, which are offset through the provisions for regulatory adjustment clauses.

47

Notes to Consolidated Financial Statements Regulatory Assets Regulatory assets included in the consolidated balance sheets are:

0. . .

In millions December 31, 2005 i: 2004 ! , . ,

Current:

Regulatorybalancingaccounts; i - 355 l $ i371 Direct access procurement charges 3 109' Purchased-power settlements : - 53 -62 Other - 15 II

.  ;;,536 . 553 .

Long-term: -  : .

Flow-through taxes-net - 1,066 .; 1,018 Rate reduction notes -. transition cost deferral 465 - p739.

Unamortized nuclear investment - net 487 526 Nuclear-related ARO investment- net

• e... . 8 292 ' ri l 272 Unamortized coal plant investment- net,; - - -] 97: ' or 78 Unamortized loss on reacquired debt 323 250 Direct access procurement charges 40 141 Environmental remediation: - . . - . 56 '. 55' Purchased-power settlements us

.; , . .39 , 91 .

Other 148 -I15 1  :: i 3,013 3,285 Total Regulatory Assets $ 3,549 $ 3,838 SCE's regulatory assets related to direct access procurement charges are for amounts direct access customers owe bundled service customers for the period May 1, 2000 through August 31, 2001, and are offset by corresponding regulatory liabilities to the bundled service customers. These amounts will be collected by mid-2007. SCE's regulatory assets related to purchased-power settlements will be recovered through 2008. Based on current regulatory ratemaking and income tax laws, SCE expects to recover its net regulatory assets related to flow-through taxes over the life of the assets that give rise to the accumulated deferred income taxes. SCE's regulatory asset related to the rate reduction bonds is amortized simultaneously with the amortization of the rate reduction bonds liability, and is expected to be recovered by the end of 2007. SCE's nuclear-related regulatory assets are expected to be recovered by the end of the remaining useful lives of the nuclear facilities. SCE has requested a four-year recovery period for the net regulatory asset related to its unamortized coal plant investment. CPUC approval is pending. SCE's regulatory asset related to its unamortized loss on reacquired debt will be recovered over the remaining original amortization period of the reacquired debt over periods ranging from one year to 30 years. SCE's regulatory asset related to environmental remediation represents the portion of SCE's environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. This amount will be recovered in future rates as expenditures are made.

SCE earns a return on three of the regulatory assets listed above: unamortized nuclear investment - net, unamortized coal plant investment - net and unamortized loss on reacquired debt.

48

Southern California Edison Company Regulatcry Liabilities Regulatcry liabilities included in the consolidated balance sheets are

In millions December31,'. 2005 2004 Current:!

Regulatory balancing accounts ' S 370 $ 357 Direct access procurement charges 113 109 Energy derivatives 136 Other 62' 24 681 490 Long-term:

ARO) . ..  :;y:. .', 584 - . 819 Ccsts of removal . . . 2,110 - 2,112 Direct access procurement charges ,: . 39 . .. . 141 ,v,.

Enmployee benefits plans - .  : 229 200 Other. ' ':'  : - . .-84 2,962 3,356; Total Regulatory Liabilities $ 3,643 $ 3,846 SCE's regulatory liability related to the ARO'represerits timing differences between the recognition of AROs in accordance' with generally accepted accounting principles and the amounts 'recognized for rate-'

making purposes. SCE's regulatory liabilities related to costs of removal represent revenue collected for' asset removal costs that SCE expects to incur in the future. SCE's regulatory liabilities related to direct access procurement charges are a liability to its bundled service customers arid are offset by regulatory' assets from direct access customers. SCE's regulatory liabilities related to energy derivatives are an offset to unrealized gains on recorded derivatives. SCE's regulatory liabilities related to employee benefit plan expenses represent pension and postretirement benefits other than pensions costs recovered through rates charged to customers in excess of the amounts recognized as cipense. These balances will be returned to ratepayers in some future rate-making proceeding, be charged against expense to the'exten:

that future expenses exceed amounts recoverable through the rate-making process, or applied as otherwise directed by the CPUC.

Related Party Transactions Four Edison Mission Energy (EME) subsidiaries have 49% to 50% ownership in partnerships that sell electricity generated by their project facilities to SCE under long-term power purchase agreements with terms and pricing approved by the CPUC. Beginning March 31, 2004, SCE consolidates these projects.

(see "Vaiable Interest Entities").

SCE holds $153 million in notes receivable from affiliates, due in June 2007. The notes were issued ba Edison Intern'atiorial in second quarter 1997, and assigned to'SCE in fourth quarter 1997. A $78 million note receivable from EME with an interest rate of LIBOR plus 0.275%; and a 4.4%, $75 million note receivable from Edison Capital. The amounts are in long-term assets on the consolidated balance sheet.

Restricted Cash SCE's restricted cash represents amounts used exclusively to make scheduled payments on the current maturities of rate reduction notes issued on behalf of SCE by a special purpose entity.

49

Notes to Consolidated Financial Statements Revenue ,:

Operating revenue is recognized as electricity is delivered and includes amounts for services rendered but unbilled at the end of each year. Amounts charged for services rendered are based on CPUC-authorized rates and FERC-approved rates. Revenue related to SCE's transmission function is authorized by the FERC irnperiodic proceedings that are similar to the CPUC's'proceedings, except that requested rate, changes are generally implemented when the application is filed, and revenue collected prior toafiinl FERC decision is subject to refund. Rates include amounts for current period costs, plus the recovery of certain previously incurred costs. However, in accordance with accounting standards forriite-rygiated tnto eingcsardred for rthe-reulted enterprises, amounts currently authorized in rates for recovery of costs to be incurred in the future are not recognized as revenue until the associated costs are incurred. Instead, these amounts are recorded'as regulatory liabilities: For costs recovered through CPUC-authorized general rate case rates;-costs-incurred in excess of revenue billed are deferred in a balancing account,.and recovered in future rates.

Since January 17, 2001, power purchased by the CDWR or through the California Independent System Operator (ISO) for SCE's customers is not considered a cost to SCE, because SCE is acting as an agent for these transactions. Further, amounts billed to ($1.9 billion in 2005, $2.5 billion .in 2004 and - t6

$1.7 billion in 2003) and collected from SCE's customers for these power purchases, CDWRi'!

bond-related costs (effective November 15, 2002) and a portion of direct access exit fees (effective January, 1,2003) are being remitted to the CDWR and are not recognized as revenue by SCE.

Revisions . -o-.- .-........- _  :. .. * .

SCE revised its consolidated statements of cash flows for the year ended December 31, 2003 to separately disclose the operating portion of the cash flows attributable to discontinued ooerations SCE has previously reported this amount as a net change in cash of discounted operations.SC Stock-Based Compensation *,. - . te: . t -

SCE has stock-based compensation plans, which are described more fully in Note 6. SCE accounts for.

those plans using the intrinsic value method. Upon grant, no stock-based compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income if SCE had used the fair-value accounting method. , .  ;, ...

In millions Year ended December 31, 2005 2004 2003 Net income available - .

for common stock, as reported S 725 $ 915 $ 922 Add: stock-based compensation expense'using . '- i \' .

the intrinsic value.accounting method,- net of tax l26  :.. ?7' 1 728.. - i Less: stock-based-compensation expense using .  : . .

the fair-value accounting method - net of tax 24  ; 9 Pro forma net income availableforcommmonstock - S 727 ' $911 -I $920'

'50

Southern California Edison Company SupplenientalAccumulatedOther Comprehensive Loss Information  : I. .

Supplemental information regarding SCE's accumulated other comprehensive loss is:, . . .

II A In millions December31, 2 005 2004 Minimum pension liability- netoftax , .S: (11) $(10)  :

Unrealized losses on cash flow hedges - net of tax . ..(5) . (7)

Accumulated other comprehensive loss $ (16) $ (17)

The minimum pension liability-is discussed in Note 6, "Compensatiot and Benefit Plans."

Unreali2ed losses on cash flow hedges relate to SCE's interest rate swap (the swap terminated on January 5, 2001, but the related debt matures in 2008). The unamortized loss of $5 million (as of December 31, 2005, net of tax) on the interest rate swap will be amortized over a period ending in 2008.

Approximately $2 million, after tax, of the unamortized loss on this swap wvill be reclassified into earnings during-2006.ea..

-. 1: I ,

.g , u:ri .

!1:. :.1 ...............................

. ,: I i _. ..

I' I I ' !' . ........ .

I 7 i , . , !. ,

Supplentental Cash Flowis Information .. . .

-i L ppe n, , c - . i.nfor'tio : !s , , ,I ,' ,. , .

SCE supplemental cash flows information is:

In millions Year ended December 31,.. . 2005 .2004 2003 I , . .l .. j-Cash payments for interest and taxes: . 1.: . if l 1 .

Interest --net of amounts capitalized. . $ 330 $ 342 i $ 390; Tax payments., .. i 1 " .j  ;. h .410 29 . I .. . 585 Non-cash investing and financing activities:

Details of debt exchange:

.Pcllution-control bondsre'deemed $S (452) '  ;

Polluti6n-con'triol bonds'issued ~. . '. . ,

452

. ,!,,; .,':i:!:

Details of obligation under capital lease: . . . .. -.. . :

Capital lease purchased - . : .(15) . - e -

Capital lease obligation issued.. .i-  ; 15; -

• Dividendsdeclared butiiot paid ' ' s r S 81-

,Det.ils of consolidation of variable interest entities:, ., - , .  ;.

Assets - $458. -

Liabilities - (537)

Reodfering of pollution-control bonds  ; $ 196 Details'of pollution-control bonds redemption:  ;',If::  : i:.?!; ! l :.:~ 'l., i. !

I. 2  !  ; ',  ;

Release of funds held in trust * ,' '

i.- ... . I ;i,; ', - $ 20 ,

Pcllution-control bonds redeemed - (20)

,, .I(. 20)

• Details of debt.exchange: -,:,  ! . . . ;,I .r i . I , iI i -I .

Rctirement of senior secured credit facility, ; * - - $ (700)..

Short-term credit facility utilized -, - . 1200 Cash paid _ $ (500)

Details of long-term debt exchange offer: -. . ,.

Variable rate notes redeemed l  ;- - $ (966)

First and refunding mortgage bonds issued . - , 966 '

Obligation to'fund investment in acquisition ' - $ 8 51

Notes to Consolidated Financial Statements Variable InterestEntities ,. . . .

SCE has variable interests in'contracts with'certain qualifying facilities (QFs) that contain variable

contract pricing provisions based on the price of natural gas. Four of these contracts are with entities that are partnerships owned in part by a related party; EME. These fou'r contracts had 20-year terms at inception. The QFs sell electricity to SCE and steam to nonrelatedcparties. Under a new accounting standard, SCE consolidated these four projects effective March 31, 2004. Prior periods have 'not been restated. . I' . . ." '

Proiect Capacity Termination Date EME Ownership Kern River 300 MW August'2010 ' 50%

Midway-Sunset 225 MW May 2009 50%

Sycamore 300 MW,, December 2007 50%

Watson:, 385MW December 2007  : 49%

SCE has no investment in, nor obligation to'lrovide support to, these entities othelr than its requirementi to make contract payments. Any profit or loss generated by these entities will not effect SCE's income statement, except that SCE would be required to recognize losses if these projects have negative equity in the future. These losses, if any, would not affect SCE's liquidity. Any liabilities of these projects are non-recourse to SCE.

Effective April 1,2004, the variable interest entities' operating costs are shown in SCE's consolidated statements of income. Prior to that date, purchases under these qualifying facility c6ntracts were reported as purchased-power expense. Further, SCE's operating revenue beginning April 1, 2004, includes' revenue from the sale of steam by these four projects. The effect that these variable interest entities have on SCE's consolidated financial statements is shown in Note 10.

SCE also has eight other contracts with QFs that contain variable pricing provisions based on the price of natural gas and are potential VIEs. SCE might be considered to be the consolidating entity under the new accounting standard. However, these entities are not legally obligated to provide the financial information to SCE that is necessary to determine whether SCE must consolidate these entities. These eight entities have declined to provide SCE with the necessary financial information. SCE is 'continuing to attempt to obtain information for these projects in order to determine whetherthey should be !;

consolidated by SCE. The aggregate capacity dedicated to SCE for these projects is 267 MW. SCE paid

$198 million in 2005, $166 million in 2004 and $147 million in 2003 to these projects. These amounts are recoverable in utility customer rates. SCE has noiexposure to loss as a result of its involvement with these projects.` -'

Note 2. Derivative Instruments and Hedging Activities SCE's uses derivative financial instruments to manage financial exposure on its investments and fluctuations in commodity.prices and interest rates.

SCE is exposed to credit loss in the event of nonperformance by counterparties. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral depending on the creditworthiness of each counterparty and the risk associated with the transaction.

SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale. The normal purchases and sales exception requires,' among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business SCE enters into contracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure to increase in natural gas and electricity pricing. These 52

• -Southern California Edison Company transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved -

procurement plans. Hedge accounting is not used for these transactions. Any fair value changes for recorded derivatives are recorded in purchased- power expense and offset through'the provision for regulatory adjustment clauses; therefore, fair value changes do not affect earnings. ,

Unit-specific contracts (signed or modified after June 30, 2003) in which SCE takes virtually all of the output of a facility are generally considered to be leases under accounting rules. Leases are not derivatives and are not recorded on the consolidated balance sheets unless they are classified as capital leases.

Most of SCE's QF contracts are not required to be recorded on the consolidated balance sheets. For further discussion see "Variable interest entities" in Note 1. HoweverSCE purchases power from certain QFs in which the contract pricing is based on a natural gas index, but the power is not generated with natural gas. The portion of these contracts that is not eligible for the normal purchases and sales exception is recorded on the consolidated balances sheet at fair value.

Derivative assets and liabilities are shown on the consolidated balance sheets, except that net, presentation is used when SCE has the legal right of setoff, such as multiple contracts executed with the same counterparty under master netting arrangements. - -

The carrying amounts and fair values of financial instruments are:  ;  : ; I 1; 1 ,  : L. i i

~

,. .  : , . I , I I, ! .; ,I I , ,  : . ,,r . I .I I December 3 1.

• .2005 2004 I  ! .mlon Carrying . Fair Carrying Fair ,

In millions ' Amount Value Amount Value Derivatives: -  ; I I . . - .1, , .

Interest rate hedges I-, 1; ;,$4 . :. $:- $ .3 *$;' 3

- Commodity price assets , .. 239 . .. 239 14 I .. 14 Commodity price liabilities  ;. .

(87) (87) I. (12) ,(12'1 Other:..

Decommissioning trusts 2,907 2,1907 2,757 2,757 DOE decommissioning and decontamination fees (7) (7) (13).. , -_('3:

QF power contracts assets 23 23 -

QF' power contracts liabilities * . %(94); (94) (12) (12)

Long-term debt (4,669) (4,1812) (5,225) (5,55f,)

Long-term debt due within one year (596) 604) (246) (254)

I ~,_ (I Preferred stock to be redeemed within one year - (9) (9)

Preferred stock subject to mandatory redemption -(139) (140)

Fair values are based on: brokers' quotes for interest rate hedges, long-term debt and preferred stock; financial models for commodity price derivatives and QF power contracts; quoted market prices for decommissioning trusts; and discounted future cash flows for United States Department of Energy (DOE) decomm ssioning and decontamination fees. - .

Due to their short maturities, amounts reported for short-term debt and cash equivalents approximate fair value.

I I- . .1,

- I- .,_1% ,.I : --. . ." 1.

.11  ;, .

53

Notes to Consolidated Financial Statements Note 3. Liabilities and Lines of Credit i .

f Almost all SCE properties are subject to a trust indenture lien. SCE has pledged first and refunding !

mortgage bonds as security for borrowed-funds obtained from pollution-control bonds issued by - i:

government agencies. SCE used these proceeds to finance construction of pollution-control facilities.

SCE has a debt covenant that requires a debt'to'total capitalization ratio be met. At December 31, 2005,,

SCE was in compliance with this debt covenant. Bondholders have limited discretion in redeeming-certain pollution-control bonds, and SCE has arranged with securities dealers to remarket or purchase them if necessary.

Debt premium, discount and issuance expenses are deferred and amortized (on~astraight-line basis),

through interest expense over the life of each issue. Under CPUC rate-making'procedures, debt K reacquisition expenses are amortized (on a straight-line basis) over the remaining life of the reacquired debt or, if refinanced; the life of the new debt. California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates;~ e '. i -

In December 1997, $2.5 billion of rate reductiori notes were issued on behalf of SCE by SCE Funding LLC, a special purpose entity. These notes were issued to finance the 10% rate reduction mandated by state law. The proceeds of the rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as transition property. Transition property is a current property right created by the restructuring legislation and a financing order of the CPUC and consists generally of the right to be paid a specified amount from nonbypassable rates charged to residential and small commercial customers. The rate reduction hotes are being repaid over 10 years through these nonbypassable residential and small commercial customer rates, which constitute the transition property purchased by SCE Funding LLC.!The notes are collateralized by the transition property and are not collateralized by, or payable from, assets of SCE or Edison International. SCE used the proceeds from the sale' 6f the transition property to retire debt and equity securities. Although, as required by accounting principles generally accepted in the United States, SCE Funding LLC is consolidated with SCE and the rate :

reduction notes are shown as long-term debt in the consolidated financial statements, SCE Funding LLC is legally separate from SCE. The assets of SCE Funding LLC are not available to creditors of SCE or Edison International and the transition property is legally not an asset of SCE or Edison International:

Long-term debt'is:' '

Irn millions December 31, 2005 2004' First and refunding mortgage bonds:

2006 - 2036 (4.65% to 6.00% and variable) S 2,775 i $ 2,741 Rate reduction notes:

2006 - 2007 (6.38% to 6.42%) .-.-- 493 -- 739 Pollution-control bonds:

2008-2035 (2.00% to 5.55% and vhriable)L  ! j96 (

!1 9 1, 196:

Debentures and notes:'

2006-2053 (5.00% to.7.625%) ; , 810 r - .812 Long-term debt due within one year (596)

;  :!,  ; (246) ; ,

Unamortized debt discount - net (9) (17)

Total  ; ' $ 4,669 '$ 9 5,225 ,,

Note: Rates and terms as of December 31, 2005 Long-term debt maturities and sinking-fund requirements for the next five years are: 2006 -

$596 million; 2007 - $396 million; 2008 - $385 million; 2009 - zero; and 2010 - $250 million.

54

, .,Southern California Edison Company At December 31, 2005 and 2004 SCE iadacreditUline witha limit of$1.7 billion and$700 million; -

respectively. At December 31, 2005, SCE had $1.52 billion in available credit under its credit line. At December 31,2004, SCE had $602 milliotn in available credit under its credit-line. There was nib outstanding short-term debt at December 31, 2005. At December 31, 2004 the outstanding short-term debt and weighted-average interest rate was $88 million at 2.48%.-I .',-

In Januaiy 2006, SCE issued $500 million of first and refinding mortgage bonds. The issuance included

$350 million of 5.625% bonds due in 2036 and $150 million of variable rate bonds due in 2009.

SCE has 12 million authorized shares of preferred stock. These shares can be issued with oriwithout.

mandatory redemption requirements - see Note 4. Shares of SCE's preferred stock have liquidation and dividend preferences over shares of SCE's common stock and preference stock. Mandatorily redeemable preferredistock is subject to sinking-find provisions. When preferred shares are redeemed, the premiums paid, if any, are charged to expense. . - I At Decemnber 31, 2005, SCE had no preferred stock subject to mandatory redemption. At December.3 1,,.

2004, SCE's $100 par value cumulative preferred stock subject to mandatory redemption consisted of

$58 million (net of $9 million of preferred stock to be redeemed within one year) of preferred stock for Series 6.05% and $81 million for Series 7.23%.. , ,. E The 6.0'% Series preferred stock had mandatory sinking funds, requiring SCE to redeem -at least 37,500 shares per year from 2003 through 2007, and 562,500 shares in 2008. SCE was allowed to credit previously repurchased shares against the mandatory sinking-fund provisions. In 2005, SCE redeemed 673,800ishares'of 6.05% Series cumulative'epreferred stock;, Which iuiluded '36,300 shares redee'rned to satisfy'the mandatory sinking-fund requiremeni 'In 2004, SCE repurchased 20,000 share; of 6.05% ii Series preferred stock.. In 2003, SCE repurchased 56,200 shares of 6.05% Series preferred stock. At-'

December 31, 2004, SCE had 1,200 previously repurchased, but not retired, shares available to cr'edit ;

against the mandatory sinking-fund provisions.

The 7.23% Series preferred stock also has mandatory sinking funds, requiring SCE to redeem` adtleast 50,000 shares per year from 2002 through 2006, and 750,000 shares in 2007. However, SCE was allowed to credit previously repurchased shares against the mandatory sinking-fund provision's. In 2005, SCE" redeemed the remaining 807,000 shares of 7.23% Series cumulative preferred stock. Since SCE had Drevious IvreDurchased 193.000 shares of this series. no shares were redeemed in 2004 or 2003. At

Notes to Consolidated Financial Statements Preferred stock and preference stock not subject to mandatory redemption is:,

' c - . - .

- 'A Dollars in millions, except per-share amounts ' December 31, . 2005  : 2004 December'31. 2005 - '

Shares Redemption Outstanding Price -

Cumulative preferred stock:

$25 par value:

4.08% Series -1,000,000 $ 25.50 S 25 $ 25 4.24 ' 1,200,000 25.80 :30 30 4.32 1,653,429' 28.75 41 4 '-

4.78 1,296,769 25.80 33 33 Preference stock: - . '

No par value:

5.349% Series A ' 4,000,000 *100.00 400'-

6.125% Series B 2,000,000 100.00 200 -

Total $ 729 $ 129 The Series A preference stock may not be' redeemed prior to April 30,12010. After April 30, 2010, SCE may, at its option, redeem the shares in whole or in part and the dividend rate may be adjusted. The Series B preference stock may not be redeemed prior to September 30, 2010. After September 30, 2010, SCE may, at its option, redeem the shares in whole or in part.

In January 2006, SCE issued two million shares of 6.0% Series C preference stock (non-cumulative,

$ 100 liquidation value). The Series C preference stock may not be redeemed prior to January 31, 2011.

After Januiry 31, 2011, SCE may, at its option, redeem the shares in whole or in piart. The Series C preference stock has the same general characteristics as the Series A and B preference stock mentioned above.

Note 5. Income Taxes 1 I -

, .. I . . I I i .

SCE and its subsidiaries are included in Edison International's consolidated federal income tax and combined state franchise tax returns. Under an income tax allocation agreement approved by the CPUC, SCE's tax liability is computed as if it filed a separate return.

Income tax expense includes the current tax liability from 'perations and the change in' deferred income taxes during the year. Investment tax credits are amortized over the lives of the related properties.

56

• -SouthernCalifornia Edison Company The components of income tax expense from continuing operations-by location of taxing jurisdiction are:

In millions Year ended December 31, 2005 2004 2003

.Curi~ent: -.

Federal $ 255 $ (88) $ 408 State 84  : 46 - 174 339 (42) 582 Deferred: ( 4 Federal (18)  ; 425 (1.34)

State (29) 55 (60)

,(47) 480 (194)

Total I $ 292 $438 $ 388-

..- . .i; ~ .. .  ; , . . 't I ., i . . I The components of the net accumulated deferred income tax liability are: I i , . , ,. A)~ ,:.-

- .,I1 I. I I . . . . I c In millions :December 31, .2005 2004 Deferred tax assets: ..

Accrued charges -* $ 117 $ 200:

Inves;tment tax credits 72 64 Property-related 352 196 Regulatory balancing accounts 301 321 Unrealized gains and losses . .: 321 -392 Decommissioning 163 ;84  :

Pensions and postretirement benefits other than pensions 182 125 Other ' 409 20 Total $ 1,917 $ 1,502 Deftrred tax liabilities:

Property-related $ 3,184 $ 2,915 Capitalized software'costs - '173 164 Regulatory balancingacco'unts! -' 607 710 Unrealized gains and losses 321 289 Decommissioning . 125 31 Other i:*; i 327  ;'" ii 24 Total $ 4,737 $ 4,233 Accumulated deferred income taxes - net $ 2,820 $ 2,731 Classification of accumulated deferred income taxes: -

Included in deferred credits ; $S2,815 $ 2,865'.

Included in current assets  : .34:,!' 1 Included in current liabilities 5

.I~. i

'; " ' -' I -J ' ' '! ,

1 I -

57

Notes to Consolidated Financial Statements The federal statutory income tax rate is reconciled to the effective tax rate from continuing operations as follows:

Year ended December 31, 2005 2004 .2003 Federal statutory rate - 35.0% 35.0% 35.0%

Tax reserve adjustments (2.1) (7.3) (2.8)

Resolution of 1991-1993 audit cycle (5.8) - -

Resolution of FERC rate case - - - - (5.9)

Property-related (0.5) 0.4 0.1 State tax - net of federal deduction 3.2 4.8 6.0 Other (1.7) - (0.7) (1.9)

Effective tax rate - - 28.1% 32.2% 30.5%

The composite federal and state statutory income tax rate was approximately 40% for all periods presented. The lower effective tax rate of 28.1% realized in 2005 was primarily due to settlement of the 1991-1993 Internal Revenue Service (IRS) audit cycle as well as adjustments made to the tax reserve to reflect the issuance of new IRS regulations and the favorable settlement of other-federal and state tax audit issues. The lower effective tax rate of 32.2% realized in 2004 was primarily due to adjustments to tax liabilities relating to prior years. The lower effective tax rate of 30.5% realized in 2003 was primarily due to the resolution of a FERC rate case and recording the benefit of a favorable resolution of tax audit issues.

As a matter of course, SCE is regularly audited by federal and state taxing authorities. For further discussion of this matter, see "Federal Income Taxes" in Note 9.

Note 6. Compensation and Benefit Plans Employee Savings Plan ~ - .

SCE has'a 401(k) defined contribution savings plan designed to supplement employees' retirement income. The plan received employer contributions of $51 million in 2005, $37 million in 2004 and

$33 million in 2003.

Pension Plans and Postretireinent Benefits Other Than Pensions Pension Plans -.----.

Defined benefit pension plans (some with cash balance features) cover employees meeting minimum service requirements. SCE recognizes pension expense for its nonexecutive plan as calculated by the' actuarial method used for ratemaking.

At December 31, 2005 and December 31, 2004, the accumulated benefit obligations of the executive pension plans exceeded the related plan assets at the measurement dates. In accordance with accounting standards, SCE's consolidated balance sheets include an additional minimum liability, with corresponding charges to intangible assets and shareholder's equity (through a charge to accumulated other comprehensive income). The charge to accumulated other comprehensive income would be restored through shareholder's equity in future periods to the extent the fair value of the plan assets exceed the accumulated benefit obligation.

58

- r; Southern California Edison Company The expected contributions (all by the employer) are approximately $51 million for the year ended December 31, 2006. This amount is subject to change based on, among other things, the limits established for federal tax deductibility.

SCE uses a December,31 measurement date for all of its plans. The fair value of plan assets is determined by market value.

I Informati.on on plan assets and benefit obligations is shown below:

In millions Year ended December 31, 2005 2004 Change in projected benefit obligation Projected benefit obligation-at beginning of year - $ 3,033 $ 2,809 Service cost .99 -86 Interest cost 166 162 Amendments 2 .22 Actuaria. loss 103 106 Benefits paid (181) (152)

Projected benefit obligation at end of year S 3,222 $ 3,033 Accumulated benefit obligation at end of year $ 2,791 $ 2,627 Change in plan assets Fair value of plan assets at beginning of year $ 2,981 $ 2,779 Actual return on plan assets 297 316 Employer contributions 6 38 Benefits paid (181) '(152)

Fair value of plan assets at end of year $ 3,103 $ 2,981 Funded status $ (119) $ (52)

Unrecognized net loss 113 105 Unrecognized transition obligation - 1 Unrecogiized prior service cost 76 91 Recorded asset $ 70 $ 145 Additional detail of amounts recognized in balance sheets:

Intangible asset $ 2 $ 2 Accumulated other coimprehensive income (19) (16)

Pension plans with an accumulated benefit obligation I in exccss of plan assets:

Projected benefit obligation $ 101 $ 77 Accumulated benefit obligation - . 1 85 ... 61 Fair value of plan assets Weighted-average assumptions at end of year:

Discount rate 5.5% 5.5%

Rate of compensation increase 5.0% *5.0%

t.

59

Notes to Consolidated Financial Statements Expense components are: '

In millions Year ended December31, 2005 2004 2003-Service cost S 99 $ 86 $ 79 Interest cost ;' 166 ' 162 - 162 Expected return on plan assets (215) (201) ' (187)

Special termination benefits - - 3 Net amortization and deferral 21-' 22i' 34 Expense under accounting standards 71 69 91 Regulatory adjustment - deferred (26) (26) - (44)-

Total expense recognized $ 45  ; $'43 i $ 47 Change in accumulated other comprehensive income S (3) ':$ (7) -

Weighted-average assumptions:

Discount rate 5.5% 6.0% 6.5% ,.

Rate of compensation increase 5.0% 5.0% , 5.0%>

Expected return on plan assets 7.5% .7.5% 8.5% .

--  :- - wI, .- , i 'Aa.  ;; , ~-1 I , .

.... v The following benefit payments, which reflect expected future service, are expected to be paid: ~

I. . .1 In . .1 . . . .. .I . ..

• 1-_

.... x r _ _ _ _ 1 _ ] To _ _ _

• _ q 1 in millions Y ear ended December 31, 2006 $ 237  : , . , 1 ':. . .

-2007 ..- - -- 251 2008 264 2009 274 2010 285 2011-2015Asse allcaton i .1 ! I I ,

Asset allocations are:- ~ --- --- -.

" ' ' i Target for December 31, 2006 2005 2004 "

, I United States equity 245% 267% 2547% I Non-United States equity 25 262 I .. i Private equity  ; 4 2, 2 Fixed income 26 25 26 . 7' .  !,

PostrelirementBenefits Other Than Pensions 1.I , {

Employees retiring at or'after age 55 with at least 10 years of service are eligible for'postretirement health and dental care, life insurance and other benefits.

On December 8, 2003, President Bush signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Act authorized a federal subsidy to be provided to plan sponsors for certain prescription drug benefits under Medicare. SCE adopted a new accounting pronouncement for the effects of the Act, effective July 1, 2004, which reduced SCE's accumulated benefits obligation by

$116 million upon adoption.

60

Southern California Edison Company The expected contributions (all by the employer) to the postretirement benefits other than pensions tru t are $77 million for the year ended December 31, 2006. This amount is subject to change based on, among other things, the limits'established for federal tax deductibility.-

SCE use s a December 31 measurement date. The fair value of plan assets is determined by market value.

Information on plan assets and benefit obligations is shown below:

In millions Year ended December 31, 2005 2004 Change in benefit obligation Benefit obligation at beginning of year $ 2,146 $ 2,137 Service cost 44 40 Interest cost 118 123

'Amendments ' ' (15) 28 Actuarial loss (gain) 38 (88).

Benefits paid (56) (94),

Benefit obligation at end of year $ 2,275 $ 2,146 Change in planassets Fair value of plan assets at beginning of year $ 1,465 $ 1,389 Actual return on plan assets 92 145 Employer contributions 72 -25 Benefits paid (56) (94' Fairvalueof plan assets at end of year ' $ 1,573 $ 1,465 Funded status $ (702) $ (681,i Unrecognized net loss 842 841 Unrecognized prior service cost (271) (285)

Recorded liability S (131) $ (125)

Assumed health care cost trend rates:

Rate assumed for following year 10.25% 10.01'/0 Ultimate rate 5.0% . 5.0%1/

Year ultimate rate reached 2011 I 2010 Weighted-average assumptions at end of year:

Discount rate 5.5% I ' 5.75%/o

.61

Notes to Consolidated Financial Statements Expensecomponentsare:.  ; . i '  ; -.(I h' i . , -

In millions Year ended December31, /!'. .,2005 i - 2004 1 -2003 Service cost $ 44 $ 40 $ 42 Interest cost . ! ,:, .123,:  : 122 Expected return on plan assets (101) (96) (89)

Special termination benefits , ,  ; - i, .,. . i Amortization of unrecognized prior service costs (28) (29) (20)

Amortization of unrecognized loss -

• l '45 49 52 Amortization of unrecognized transition obligation - 9 9-Total expense s 78! $ 87ii $ 117 Assumed health care cost trend rates:

Current year 10.0% 12.0% - - 9.75%

Ultimate rate 5.0% ' 5.0% , 5 Year ultimate rate reached 2010 2010 2008 Weighted-average assumptions:  ;

Disc6untfrhte -5.75%1/0 - 6.25% - 6.4%

Expected return on plan assets 7.1% 7.i%/o ; I 8.2%

Increasing the health care cost trend rate by one percentage point would increase the accumulated, i obligation as of December 31, 2005 by $271 million and annual aggregate service and interest costs by

$19 million. Decreasing the health care cost trend rate by one percentage poiin would decrease the.

accumulated obligation-as of December 31, 2005-by $243 million and annual aggregate service and interest costs by $17 million.

The'following benefiitpayments are expected to be paid: . ' -;

Before  ;

In millions ... Year ended December31, Subsidy Net 2006 $ 104 $ 99 2007 113 .107 2008  ;. 118. ;. I . 111 F 2009 127 120 2010 135 127 2011-2015 760 711 Asset allocations are:

Target for December 31, 2006 2005 2004 United States equity 64% 65% 64%

Non-United States equity 16 14 14 Fixed income 20 21 22 Description of Pension andPostretirementBenefits Other Than PensionsInvestment Strategies The investment of plan assets is overseen by a fiduciary investment committee. Plan assets are invested using a combination of asset classes, and may have active and passive investment strategies within asset classes. SCE employs multiple investment management firms. Investment managers within each asset 62

Southern California Edison Company class cover a range of investment styles and approaches. Risk is controlled through diversification amcng multiple asset classes, managers, styles and securities. Plan, asset class and individual manager performance is measured against targets., SCE also monitors the stability of its investments managers':

organizations. ';.-- B' , . -* , -.

Allowab]e investnienttypes include:' ' -; i. ' . ' .

United States Equity: Common and preferred stock of large, medium, and small companies which are predomitiantly.United.States-based.6 2 . . .,.2 ..' , '.!..

Non-United States Equity:' Equity securities issued by companies domiciled outside the United States and in depository receipts which represent ownership of securities of non-United States companies.

Private Equity: ,Limited partnerships that invest in non-publicly traded entities.  ;

Fixed Income: Fixed income securities issued or guaranteed by the United States government, non United States governments, government agencies and instrumentalities, mortgage backed securities and corporate debt obligations. A small portion of the fixed income position may be held in debties securities that are below -investment grade.  ; .

.,. , .,~ aI, . . .:iI1 S' ' '

Permitted ranges around asset class portfolio weights are plus or minus 5%. Where approved by the fiduciary investment committee; futures contracts are used for portfolio rebalancing and to-approach fiilly invested portfolio positions. Where authorized, a few of the plan's investment managers employ limited use of derivatives, including futures contracts, options, options on futures and interest rate swaps in pl ace of direct investment in securities to gain efficient exposure to markets. Derivatives are not used to leverage the plans or any portfolios.

Determination of the Expected Long-Term Rate of Return on A ssets for United States Plans The overall expected long term rate of return on assets assumption is based on the target asset allocation for plan assets, capital markets return forecasts for asset classes employed, and active management, excess return expectations. A portion of postretirement benefits other than pensions trust asset returns are subject to taxation, so the expected long-term rate of return for these assets is determined on an after-tax basis. .. - ' '

CapitalMarkets Return Forecasts; The estimated total return for fixed income is based'on an euilibrium yield for intermediateUnited States government bonds plus a premium-for exposure to non-government bonds in the broad fixed income market. The equilibrium yield is based on analysis of historic data and is consistentAwith experience over various economic environments. The premium of the broad market over United States government bonds is a historic average premium. The estimated rate of return for equity is estimated to be a 3% premium over the estimated total return of intermediate United States government bbnds. This value is determined by combining estimates of real earnings growth, dividend yields and inflation, each of which was determined using historical analysis. The rate of return for private equity-is estimated to be a 5% premium over public equity, reflecting a premium for higher volatility and illiquidity.

Active Management Excess Return Expectations For asse: classes that are actively managed, an excess return premium is added to the capital market return forecasts discussed above.

63

Notes to Consolidated Financial Statements Stock-Based Compensation . . , i . .

Under various plans, SCE may grant stock options at exercise prices equal to the'market price at the grant date and other awards based on Edison International common stock to directors and certain employees.

Options generally expire 10 years after the grant date and vest over a period of up to five years, with expense accruing evenly over the vesting period. Edison International has' approximately 12.5 million shares remaining for future issuance under equity compensation plans.

,  : ,,;, :i , ,  : i .

Most Edison International stock options issued prior to 2000 accrue dividend equivalents, subject to certain performance criteria. The 2003, 2004, and 2005 options accrue dividend equivalents for the first five years of the option term. Unless deferred, dividend equivalents accumulate without interest.

• ~~~~ . .i .. ~~ .- . ~- . . . .. . . . . . .

The fair value for each option granted, reflecting the basis for the pro forma disclosures in Note I, was determined as of the grant date using the Black-Scholes option-pricing model. The following assumptions were used in determining fair value through the model:

I "i

• AS December 31, 2005 2004 2003 It II .

Expected years until exercise '9-10 9- 10 10 Risk-free interest rate 4.1%-4.3% 4.0% '- 4.3% 3.8% - 4.5%

Expected dividend yield 2.1% -3.1% 2.7% -3.7% 1.8%

Expected v6latility ' ' 15%- 20% ' 19% - 22% 44% - 530io'

. I . ' .  ; , .; , , ll .. .': ':'i A summary of the status of Edison International stock options is as follows:,

.. , , ., i: i

.7 Weighted-Average , -. -

Share Exercise Fair Value

-: I  ! Options - .Price At Grant , j i Outstanding, Dec. 31, 2002 6,810,798 $ 22.37 Granted '  ;' ' ' 2,076,070 :12.41 $ 7.34 . :I! (.7 ..

Expired (115,612)

(- 22.98 '

-J Forfeited - ' (59,473) i 15.34' ': - i , ". I Exercised. (156,697) ' ' 18.71 -

Outstanding, Dec. 31, 2003 8,555,086 $ 20.06 Granted 2,476,820 21.98 $ 6.61 Expired (509) 16.23 Forfeited (79,536) 16.83 Exercised (1,589,948) 18.20 Outstanding, Dec. 31, 2004 9,361,913 . $ 20.91 , 9. :4 0 , ,. '.

Granted .. * -. . 1. . i 1,848,039- 32.26 , $ 9.40.

Expired , .

I;:i Forfeited i .. (162,606) . ,2!.02 ,,  ;

1',

Outs t a ndi n g !,D c 31, . 20 05. 1. .8.5.

11 A-f%faftO\

87, 24 . . - ' .

1- 7

. 2.

-23

Outstanding, Dec. 31, 2005 ' 8,587,248' , -~ $ 23.22  : '! ,-

I Ii i -, - ,  ;-' l' ,

8 .

.-A  !, ., ' . .

A* . 5.

64

XSouthern California Edison Company A summary of stock options outstanding at December3l, 2005 is as follows: -i; Outstanding Exercisable Weighted Average Weighted Weighted Remaining Average . Average Range of Number Years of Exercise Number Exercise Exercise Prices of Options Contractual Life Price of Options Pricc.

$ 8.90413.99 1,539,416 7 $ 12.22 717,388 $ 12.165

$14.00-$20.99 '1,174,081 - i ' 6 ' $18:55 811,701 '-$ 18.52;

$21.00-$31.49; 4,016,320; .:: '6 $24.62 '2,262,774 S$26.66

$31.50-$46.87 1,857,431 9 $32.26 51,206'- $ 31.9 4 Total ' 8,587,248 7 $ 23.22 3,843,069 $ 22.31 The number of options exercisable and their weighted-average exercise prices at December 31, 2004 and 2003 were 4,546,711 at $23.69 and 4,845,967. at $24.06, respectively. '  : -

Performance shares'were'awarded to executives in January 2003, January 2004 and January:2005 and vest at the end of December 2005, 2006 and 2007, respectively. The number of common shares paid cut from the performance share awards depends on the performance of Edison International common stock relative to the stock performance of a specified group of companies. Performance share values are accrued atably-over the vesting period based on the value of the underlying Edison International common stock. The number of performance shares granted and their weighted-average grant-date value for 2005, 2004 and 2003 were 132,655 at $32.07, 178,684 at $21.94, and 293,497 at $12.33, respectively.

In the plo forma disclosure reflected in Note 1,the portions of these performance shares settled in stock, which w ere half of the total shares outstanding, were treated as equity awards. The weighted-average grant-date fair values of these performance shares were $46.09, $33.62 and $21.42, for 2005, 2004 and 2003, respectively.

See Note I for SCE's accounting policy and expenses related to stock-based compensation.

Note 7. Jointly Owned Utility Projects SCE owns interests in several generating stations and transmission systems for which each participant I provides its own financing. SCE's share of expenses for each project is included in the consolidated.

statements of income. i , - .i I . i. I SCE's investment in each project as of December 31, 2005 is: -  :

' Investment Accumulated in Depreciation and Ownership In millioins 'Facility' i ' Amortization Interest Transmission systems:S ,- . . . . _ i' I '. '

Eldorado ' $ 60" $ 9 60%

Pacific Intertie ' 306 80 50 Generating stations:,

Four Comers Units 4 and 5 (coal) 499 407 48 Mohave (coal) .  ; 350 269 56 Palo Verde (nuclear) 1,710  ! 1,468i 16 Saa'Onofre (nuclear). 4,522 3,956 75 Total $ 7,447 - - $ 6,189 65

Notes -to'Consolidated Financial Statements All of Mohave Generating Station'and a portion of San Onofre and Palo'Verde isiincluded in regulatory assets on the consolidated balance sheets. See Note 1. Mohave ceased operations on December 31, 2005.

At this time, SCE does not know the length of the shutdown period, and a permanent shutdown remains possible.

Note 8. Commitments '.

Leases . .  :'  :

Unit-specific contracts (signed or modified after June 30, 2003) in which SCE takes virtually all of the output of a facility are generally considered to be leases under accounting rules.,At December 3.1, 2005, SCE had six power contracts that were classified as operating leases and one capital lease (executed in late 2005). Operating lease expe'nse'for power purchases was $68 million in 2005 and zero for all other

'periods presented: Other operating lease expense; primarily for vehicle leases, wvas$20 million in 2005;

$17 million in 2004, and $15 million in 2003. The leases have varying terms, provisions and expiration dates. The capital lease (net commitment of$15 million)is reported as along-term obligation on the consolidated balance sheet under the caption, other long-termi'liabilities.'! .' ..

Estimated remaining commitments for noncancelable operating leases at December. 31,2005 are:

'Power Contracts -. Other

• -Operating..-  ; -'.Operating In millions -Year ended December 31, - .Leases Leases,'

• 2006: - ' . $' 177 $ 15 2007 - i  : 288- 13  : c 2008 . It'260 ' I 2009 I '205 . 8 2010 - ' '* ; '  ! 204 4 Thereafter - 5 ' '

Total $ 1,134 $ 56 NuclearDecommissioning . -.  ;!

• As a result;of an accounting standard adopted in 2003, SCE recorded the fair value of its liability for AROs, primarily related to the decommissioning of its nuclear power facilities. At that time, SCE 3' adjusted its nuclear decommissioning obligation, capitalized the initial costs of the ARO into'a nuclear-related ARO regulatory asset, and also recorded an ARO regulatory liability as a result of timing differences between the recognition of costs recorded in accordance with the standard and the recovery' of the related asset retirement costs through the rate-making process. SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts.

The fair value of decommissioning SCE's nuclear power facilities is $2.6 billion as of December 31, 2005, based on site-specific studies performed in 2005 for San Onofre and Palo Verde: Changtes in the estimated costs, timing of decommissioning, or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission. SCE estimates that it will spehd" approximately $11.4 billion through 2049 to decommission its active nuclear facilities' This estimate is based on SCE's decommissioning cost methodology used for rate-making purposes, esc Ialated at rates ranging from 1.7% to 7.5% (depending on the cost element) annually. These costs 'areexpected to be funded from independent decommissioning trusts, which effective October 2003 receive contribiitions of approximately $32 million per year. SCE estimates annual after-tax earnings on the decommissioning funds of 4.5% to 5.'6%. If the assumed-return on trust assets is not-eamed,-additional funds needed for decommissioning will be recoverable through rates.. .

66

.. Southern California Edison Company Decommissioning of San Onofre Unit 1 is underway, and will be completed in three phases:

(1) decontamination and dismantling of all structures and some foundations; (2) spent fuel storage monitoring; and (3) fuel storage facility dismantling, removal of remaining foundations, and site restorati:n.,Phase one is scheduled to continue through 2008. Phase two is expected to continue until 2026. Phase three will be conducted concurrently with the San Onofre Units 2 and.3 decommissioning projects. In February 2004, SCE announced that it discontinued plans to ship the San Onofre Unit 1 reactor pressure vessel to a disposal site until such time as appropriate arrangements are made for its permanent disposal. It will continue to be stored at its current location at San Onofre Unit I. This action-results in placing the disposal of the reactor pressure vessel in Phase three of the San Onofre Unit I decommissioning project.. v-I

., . ' , 5 -f 'I All of SCE's San Onofre Unit I decommissioning costs will be paid from its nuclear decommissioning trust funds and are subject to CPUC review. The estimated remaining cost to decommission San Onofre Unit I is recorded as an ARO 'liability ($186 million at December 31, 2005). Total expenditures for the decommissioning of San Onofre Unit l were $414 million from the beginning of the project in 1998 through December 31, 2005.. " - .; . l SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by the Nuc'lear Regulatory Commission.-Decommissioning is expected to begin after the plants'.operating licenses expire. The operating licenses currently expire in 2022 for.San Onofre Units 2 and 3, and in 2025, 2026 and 2027 for the Palo Verde units. Decommissioning costs, which are recovered through nonbypassable customer rates over the term of each .nuclearfacility's operating license, are recorded as a component of depreciation expense, with a corresponding credit to the ARO regulatory liability. The earnings impact of amortization of the ARO asset included within the unamortized nuclear investment and accretion of the ARO liability, both created under this new standard, are deferred as increases to the ARO regulatory liability account, with no impact on earnings.

SCE ha, collected in rates amounts for the future costs of removal of its nuclear assets. The cost of removal amounts, in excess of fair value collected for assets not legally required to be removed, are classified as regulatory liabilities.. - I ' . * . *'

Decommissioning expense under the rate-making method was $118 million in 2005, $125 million in 2004 and $118 million in 2003. The ARO for decommissioning SCE's active nuclear facilities was $2.4 billion at December 31, 2005 and $2.0 billion at December 31, 2004.

Decommissioning funds collected in rates are placed in independent'trusts, which, together with accumulated earnings, will be utilized solely for decommissioning. ,  ; -- . -

Trust' investments (at fair value) include: -  : ' ..

In millions ' . Maturity Dates. , December 31, 2005 2004 Municipal bonds - 2006-2039 $' 863 '784' Stock - 1,451 1,403 United States government issues 2006 - 2035 479 485 Corporate bonds  ;-  :.2006-2045i'  ; ' 42 ';41 Shc rt-term 200t 72 44

-Total - $ 2,907 , $2,757 Nole' Maturity dates as of December31, 2005.'

, . , . . ., ..S....

67

Notes to Consolidated Financial Statements Trust fund earnings'(based on specific identification) increase the trust fund balance and the ARO I regulatory liability. Net earnings (loss) were $87 million in 2005, $91 million in 2004, and $93 million in 2003. Proceeds from sales of securities (which are reinvested) were $2.0 billion in 2005, $2.5 billion in 2004, and $2.2 billion in 2003. Net unrealized holding gains were $852 million and $796 million at December 3 1,2005 and 2004, respectively. Approximately 91 % of the cumulative trust fund contributions were tax-deductible. ,

Other Comtnihnents .

SCE has fuel supply contracts which require payment only if the fuel is made available for purchase.

SCE has a coal fuel contract that requires payment of certain fixed charges whether or not coal is delivered. -  ; . .  ;- -

SCE has power-purchase contracts with certain QFs (cogenerators and small power producers) and other' power producers. These contracts provide for capacity payments if a facility meets certain performance obligations and energy payments based on actual power supplied to SCE (the energy payments are not included in the table below). There are no requirements to make debt-service payments. In an effort to replace higher-cost contract payments with lower-cost replacement power, SCE has entered into purchased-power settlements to end its contract obligations with certain QFs. The settlements are reported as power purchase contracts on the consolidated balance sheets.

Certain commitments for the years 2006 through 2010 are estimated below:

In millions i ;2006 2007i -2008 2009  ; i2010

-Fuel supply $126 $ 64 $ 64 $40 $ 47 Purchased power 842 775' 528 417 393 SCE has an unconditional purchase obligation .for firm transmission service from another utility.

Minimum payments are based, in part, on the debt-service requirements of the transmission service' provider, whether or not the transmission line is operable. The contract requires minimum payments of

$62 million through 2016 (approximately $6 million -per year).-;

- , 5i.

I,,dentnities X ' .  : . . - - .

In connection with the acquisition of Mountainview, SCE agreed to indemnify the seller with respect to' specific environmental claims related to SCE's previously owned San Bernardino Generating Station,-.

divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. The generating station has not operated since 2001. SCE retained certain responsibilities with-respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for I; environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.

SCE provides other indemnifications through contracts entered into in the normal course of business.

These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified environmental indemnities and'income taxes with respect to assets sold.SCE's obligations under these agreements may be limited in terms of time and/or amount, and in some instances SCE may have recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. SCE has not recorded a liability related to these indemnities.

68

Southern California Edison Company Note 9. Contingencies' . i.V! .*

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

Environvmental Remediation SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

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 measurcs 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,land the probable level of involvementland 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 lover end of this reasonably likely range of costs (classified as other long-term liabilities) at undiscounted amounts. - .'-

SCE's recorded estimated minimum liability to remediate its 24 identified sites is $82 million. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due to these uncerta nties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to

$115 million. The upper limit of this range of costs was estimated using assumptions least favorable 1o SCE among a range of reasonably possible outcomes. In addition to its identified sites (sites in which the upper eiad of the range of costs is at least $1 million), SCE also had 31 immaterial sites whose total i liability ranges from $4 million (the recorded minimum liability) to $9 million.

The CP UC: allows SCE to recover environmental remediation costs at certain sites, representing

$30 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance can-iers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SC(E expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $56 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. ' . ' '

SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites. - - -

69

Notes to Consolidated Financial Statements SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $11 million to $25 million. Recorded costs for 2005 were $13 million. .  ;

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental remediation costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

FederalIncome Taxes Edison International has reached a settlement with the IRS on tax issues and pending affirmative claims relating to its 1991-1993 tax years. This settlement, which.was signed by Edison International in March 2005 and approved by the United States Congress Joint Committee on Taxation on July 27, 2005, resulted in a third quarter 2005 net earnings benefit for SCE of approximately $61 million, including interest. This benefit was reflected in the caption "Income tax" on the consolidated statements of income.

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting deficiencies in federal corporate income taxes with respect to audits of its 1994-1996 and 1997-1999 tax years, respectively. Many of the asserted tax deficiencies are timing differences and, therefore, amounts ultimately paid (exclusive of penalties), if any, would benefit SCE as future tax deductions.

The IRS Revenue Agent Report for the 1997-1999 audit also asserted deficiencies with respect to a transaction entered into by an SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability company. While Edison International intends to defend its tax return p6sition with respect to this transaction, the tax benefits relating to the capital loss deductions will not be claimed for financial accounting and reporting purposes until and unless these tax losses are sustained. -

In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through 2002 to abate the possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to listed transactions described in an IRS notice that was published in 2001. These transactions include the SCE subsidiary contingent liability company',

transaction described above. Edison International filed these amended returns under protest retaining its appeal rights.

FERCRefundProceedings .

In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of electricity in the California Power Exchange (PX) and ISO markets. On March 26, 2003, the FERC staff issued a report concluding that there had been pervasive gaming and market manipulation of both the electric and natural gas markets in California and on the West Coast during 2000-2001 and describing many of the techniques and effects of that market manipulation. SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets. SCE is required to refund to customers 90% of any refunds actually realized by SCE net of litigation costs, except for the El Paso Natural Gas Company settlement agreement discussed below, and 10% will be retained by SCE as a shareholder incentive. A brief summary of the various settlements is below:

'70

Ai Southern California Edison Company

• In June 2004, SCE received its first settlement payment of $76 million resulting from a settlement agreement with El Palo Natural Gas Company. Approximately $66 million of this amount was credited to purchased-power expense, and was refunded to SCE's ratepayers through the energy -

resource recovery account (ERRA) mechanism over the following twelve months, and the remaining

$10 million was used to offset SCE's incurred legal costs. In May. 2005, SCE received its final settlement payment of $66 million, which was also refunded to ratepayers through the ERRA mechanism. . .,

• In August 2004, SCE received its $37 million share of settlement proceeds resulting from a FERC-approved settlement agreement-with The Williams Cos. and Williams Power Company.

• In November 2004, SCE received its $42 million share of settlement proceeds resulting from a FERC-approved settlement agreement with West Coast Power, LLC and its owners, Dynegy Inc. and NRG Energy, Inc.

• In January 2005, SCE received its $45 million share of settlement proceeds resulting from a FERC-approved settlement agreement with Duke Energy Corporation and a number of its affiliates.

• In April 2005, the FERC approved a settlement agreement among SCE, Pacific-Gas and Electric (PG&E), San Diego Gas'& Electric (SDG&E)'and several governmental entities, and Mirant '

Corporation and a number of its affiliates (collectively Mirant), all of whom are debtors in Chapter 1I bankruptcy proceedings pending in Texas. In April and May 2005, SCE received its

$68 million share of the cash portion of the'settlement proceeds. SCE also received a $33 million

' share of an allowed, unsecured claim in the bankruptcy of one of the Mirant parties which was sold for S35 niillion in December 2005. -

• In November 2005, the FERC approved a settlement agreement among SCE, PG&E, SDG&E and

'several governmental entities, and Enron Corporation and a number of its affiliates (collectively Enron), most of which are debtors in Chapter 11 bankruptcy proceedings pending in Newv Ydrk. In January 2006, SCE received cash settlement proceeds of $4 millidn and'anticipates receiving approximately $5 million in additional cash proceeds assuming certainhconiingencies are satisfied.'

'SCE alsoreceived an allowed, unsecured claim against one of the Enron debtors' in the amount of

$241 million. In February 2006, SCE received a partial distribution of $10 million of its allowed claim. The remaining amount of the allowed claim that will actually be realized will depend on events in'Enron's bankruptcy that impact the value of the relevant debtor estate.

• 'In December 2005, the FERC approved asettlemrcnt agreement amnong SCE,' PG&E, SDG&E, several governmental entities and certain other parties,' and Reliant Energy, Inc. and a number of its affiliates (collectively Reliant). In January 2006, SCE received its $65 million share ofthe settlement proceeds. SCE expects to receive an additional $66 million in the first quarter of 2006.

On November'19, 2004, the CPUC'issued a resolution authorizing SCE to establish an energy settlement memorandum account (ESMA) for the purpose of recording the foregoing settlement proceeds (excluding the El Paso settlement) from energy providers and allocating them in accordance with a2 settlement agreement. The resolution provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA are allocated to recovery of SCE's litigation costs and expenses in the FERC refund proceedings described above and the 10% shareholder incentive. Remaining amounts for each settlement are to be refunded to ratepayers through the ERRA mechanism. During 2005, SCE recognized

$23 million in shareholder incentives related to the FERC refunds described 'above.

71

Notes to Consolidated Financial Statements In vestigations RegardingPerfortmanceIncentives Rewards: -. , '2 ..

SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties 'based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability. -

SCE has been conducting investigations into its performance under these PBR mechanisms and has, reported to the CPUC certain findings of misconduct and misreporting as further discussed below. As a result of the reported events, the CPUC could institute its own proceedings to determine whether and in what amounts to order refunds ordisallowances of past and potential'PBR rewards for customer.

satisfaction, injury and illness reporting, and system reliability portions of PBR. The CPUC also may consider.whether to impose additional penalties on SCE. SCE cannot predict with certainty the outcome of these matters 'or estimate the potential amount of refunds, disallowances,-,and penalties that may be required.

CustomerSatisfaction ., ' .,* . .. - .;; * . ,; .

SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE's transmission and distributtionbusiness unit altered or, omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The results of these.surveys are used, along with other factors, to determine the amounts of any incentive rewards or penalties to SCE under the PBR provisions for customer, satisfaction. SCE -

recorded aggregate customer satisfaction rewards of $28 million for the years 1998, 1999 and 2000.

Potential customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of approximately $10 million for 2003.

Ii.

Following its internal investigation, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5.million of the PBR rewards pending that are both attributable to the design. organization's portion of the customer satisfaction rewards for the entire PBR period (199772003). adtion, in SCE also, proposed to refund all of the approximately $2 million of customer satisfaction rewards associatedwith meter reading. As a result of these findings, SCE accrued a

$9 million charge in.2004 for.the potential refunds of rewards that have been received. .,

SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the.

employment of several supervisory personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls over data collection and processing..

Performance incentive rewards'for customer satisfaction expired in 2003 pursuant to the 2003 general rate case.. , , ; ,; v . - . i :' a '

The CPUC has not yet opened a formal investigation into this matter. However, it has submitted several data requests to SCE and has requested an opportunity to interview a number of SCE employees in the,,

design organization. SCE has responded to these requests and the CPUC has conducted interviews of,.

approximately 20 employees who w*re disciplined for misconduct and four senior managers and executives of the transmission and distribution business unit. -

Employee Injury and Illness Reporting . * .- . ,

• s . ' l I,.~:: i . , ;l  ;

In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE's employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine the amount of the incentive 72

Southern California Edison Company reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997,SCE has received $20 million in employee safety incentives for 1997 through 2000 and, based on SCE's records, may be entitled to an additional $15 million for 2001 through:2003.*

On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE's performance under the PBR incentive mechanism for injury and illness reporting. SCE disclosed in the investigative findings to the CPUC that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.

As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the' mechanism for any year before 2005, and it return to ratepayers the $20 million it has already received..

Therefore, SCE accrued a $20 million charge in 2004 for the potential refurnd of these irewards. SCE ha's also proposed to withdraw the pending rewards for the 2001-2003 time frames.

SCE has taken other remedial action to address the issues identified, including revising its organizational structure and overall prograii'f6r environnental, health and safety compliance and disciplining; employees who committedirwrongdoing. SCE submitted a feport'o6nthe results of its investigation to the' CPUC o0l Deceinber'3, 2004. As with the 'customier satisfaction matter, the CPUC has not yet opened E.

formal investigation into this matter. . ' ' ' '

ISO DisplutedCharges . r -.

On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain charges. The order reversed an arbitrator's award that had affirmed the ISO's characterization in May 2000 of the-charges as Intra-Zonal Congestion costs and allocation 'ofthose charges 1o scheduling coordinators (SCs) in the affected zone within the ISO transmission grid. The April 20:, 2004 order directed the ISO to shift the costs from SCs in the affected zone to the responsible participating transmission owner, SCE. The potential cost to SCE, net of amounts -SCE expects to receive through :he PX, SCE's SCat the time, ,is estimated to be approximately $20 million to $25 million, including interest. On April 20, 2005, the FERC stayed its April 20, 2004 order during the pendency of SCE's appeal filed with the Court of Appeals for the D.C. Circuit. On February 7, 2006, the FERC advised SCE that the FERC will move the Court of Appeals for a voluntary remand so that the FERC may amend the order on appeal. A decision is expected in late 2006. The FERC may require SCE to pry these costs, but SCE does not believe this outcome is probable. If SCE is required to pay these costs, SCE may seek recovery in its reliability service rates', . , -

Navajo Nation Litigation -

In June 1999, the'Navajo Nation filed 'a complaint in the United States District Court for the' District of Columbia (D.C. District Court) against Peabody Holding Company (Peabody) and certain of its'affiliates, Salt River Project Agricultural Improvement'and Power District, and SCE-arising out of the coal supply agreement for Mohave. The complaint asserts claizns for, among other'things, violations of the federal' Racketee r Influenced and Corrupt Organizations statute,' interference with'fiduciary 'duties and contractual relations, fraudulent misrepresentation'by'nondisclosure,-and various contract-related claims.

The complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The'complaint seeksdamages of not less than

$600 mil lion, trebling of that amount,'and punitive damages of not less than $1 'billion, as well as a' declaration that Peabody's lease and contract rights to mine coal on Navajo Nation lands should be' terminated. SCE joined Peabody's motion to strike the Navajo Nation's complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C. District Court denied these motions for dismissal, except for Salt River Project Agricultural Improvement and Power District's motion for its separate dismissal from the lawsuit.

73

Notes to Consolidated Financial Statements Certain issues related to this case were addressed 'bythe United States Supreme Court in a separate legal proceeding filed by the Navajo Nation in-the United States Court of Federal Claims against the United States Department of Interior. In that action, the Navajo Nation claimed that the Government breached its fiduciary duty concerning negotiations relating to the coal lease involved in the Navajo Nation's lawsuit against SCE and Peabody. On March 4, 2003, 'the Supreme Court concluded, by majority decision, that there was no breach of a fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the Supreme Court's'conclusion, SCE and Peabody brought motions to dismiss or for summary judgment in the D.C. District Court action but the D.C. District Court denied the motions on April 13, 2004.

The Court of Appeals for the Federal Circuit, acting on a suggestion filed by the Navajo Nation on remand from the Supreme Court's March 4, 2003 decision held in an October 24, 2003 decision that the Supreme Court's decision was focused on three specific statutes or regulations and therefore did not' address the question of whether a network of other statutes, treaties and regulations imposed judicially enforceable fiduciary duties on the United States during the time period in question. On March 16, 2004, the Federal Circuit issued an order remanding the case against the Government to the Court of Federal Claims, which considered (1) whether the Navajo Nation previously waived its ."network of other laws" argument and, (2) if not, whether the Navajo Nation can establish that the Government breached any fiduciary duties pursuant to such "network." On December 20, 2005, the Court of Federal Claims issued its ruling and found that although there was no waiver, the Navajo Nation did not establish that a "network of other laws" created ajudicially enforceable trust obligation. The Navajo Nation filed a notice of appeal from this ruling on February 14, 2006. i Pursuant to a'joint request of the parties, the D.C. District Court granted a stay of the action in that court' to allow the parties to attempt to resolve, through facilitated negotiations, all issues associated with' Mohave. Negotiations are ongoing and the stay has been'continued until further order of the court.

SCE cannot predict with certainty the'outcome of the 1999 Navajo Nation's complaint against SCE, the' impact on the complaint of the Supreme Court's decision and the recent Court of Federal Clains ruling in the Navajo Nation's suit 'against the Government, or the impact of the complaint on the possibility of resumed operation of Mohave following the cessation of operation 'on December 31, 2005.

Nuclear Iiisiurance  ;

Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available

($300 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear 'incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre Unit I from this secondary level, effective June 1994. The current maximum deferred premium for each nuclear-incident is $101, million per reactor, but not more than $15 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear incident will be adjusted for inflation on a 5-year schedule. The next inflation adjustment will occur on August 31, 2008. Based on its ownership interests, SCE could be required to pay a maximum of $199 million per nuclear incident. However, it would have to pay no more than $30 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If

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- Southern California Edison Company the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary

$500 mil lion also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual ;

insurancs company owned by utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to $44 million per year. Insurance premiums are charged to operating expense.,',

Procureneientof Renewable Resources California law requires SCE to increase its procurement of 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, 2017. The Joint Energy Action Plan adopted in'2003 by the CPUC and the California Energy Commission (CEC) accelerated the deadline to 2010.

SCE entered into a contract with Calpine Energy Services, L.P. (Calpine) to purchase the output of:

certain existing geothermal facilities in northern California. In January 2003, the CPUC issued a resolution approving the contract. SCE interpreted the resolution as authorizing SCE to 'count all of the t output o. the geothermal facilities towards the obligation to increase SCE's procurement from renewa'ble resource, and counted the entire output of the facilities toward-its 1%obligation in 2003, 2004 and 2005.

On July 21, 2005, the CPUC issued a decision stating that SCE can only count procurement pursuant to -

the Calpine contract towards its 1%annual renewable procurement requirement if it is certified as "incremental" by the CEC. On February 1, 2006, the CEC certified approximately 25% and 17% of SCE's 2003 and 2004 procurement,'respectively, from the Calpine geothermal facilities as "incremental."

A similar outcome is anticipated with respect to the CEC's certification review. for 2005.

On August 26, 2005, SCE filed an application for rehearing and a petition for modification of the CPUC's July 21, 2005 decision On January.26, 2006, the CPUC denied SCE's application for rehearing of the decision. .The CPUC has not yet ruled on SCE's petition for modification. The petition for  :

modification seeks a clarification that SCE will not be subjected to penalties forrelying on the CPUC'st 2003 resolution in submitting compliance reports to the CPUC and planning its subsequent renewable I procurement activities. The petition for modification also seeks an express finding that the decision will be applied prospectively only; i.e.,-that no past procurement deficits will accrue for any prior period based on the decision.

If SCE is not successful in its attempt to modify the July 21, 2005 CPUC decision and can only count the output deemed "incremental" by the CEC, SCE could have deficits in meeting its renewable procurement obligations for 2003 and 2004. However, based on the CPUC's rules for compliance with renewable procurement targets, SCE believes that it will have until 2007 to make up these deficits before becoming subject to penalties for those years. The CEC's and the CPUC's treatment of the output from the

'geothertral facilities could also result in SCE being deemed to be out of compliance in 2005 and 2006.

Under current CPUC decisions, potential penalties for SCE's failure to achieve its renewable procurement obligations for any year will be considered by the CPUC in SCE's annual compliance filing.

On December 20, 2005, Calpine and certain of its affiliates initiated Chapter 11 bankruptcy proceedings in the United States Bankruptcy Court for the Southern District of New York. As part of those proceedings, Calpine sought to reject its contract with SCE as of the petition filing date. On 75

Notes to Consolidated Financial Statements January 27, 2006, after the matter had been withdrawn from the Bankruptcy Court's jurisdiction,'the United States District Court for the Southern District of New York denied Calpine's motion to reject the contract and ruled that the FERC has exclusive jurisdiction to alter the terms of the contract with SCE.

Calpine has appealed the District Court's ruling to the United States Court of Appeals forthe Second Circuit. Calpine may also file a petition with the FERC seeking authorization to reject the contract. The CPUC may take the position that any authorized rejection of the contract would cause SCE to be out of compliance with its renewable procurement obligations during any period in which renewable electricity deliveries are reduced or eliminated as a result of the rejection.,

Further, in December 2005, SCE made filings advising the CPUC that the need for transmission upgrades to interconnect new renewable projects and the time it will take under the current process to license and.t construct such transmission upgrades may prevent SCE from meeting its statutory renewables procurement obligations through 2010 and potentially beyond 2010 depending in part on-the results of a pending solicitation for new renewable resources. SCE has requested that the CPUC take several actions in order to expedite the licensing process for transmission upgrades. The CPUC may take the position:

that SCE's failure to meet the 20% goal by-2010 due to transmission constraints would cause SCE to be out of compliance with its renewable procurement obligations. .:;-

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Under the CPUC's current rules, the maximum penalty for failing to achieve renewables procurement targets is $25 million per year. SCE cannot predict with certainty whether it will be assessed penalties.'

Schedule Coordinator TariffDispute  ; - -;

SCE serves as a schedule coordinator for Los Angeles Department of Water & Power (DWP) over the ISO-controlled grid. In late 2003,-SCE began charging DWP under a tariff subject to refund for'FERC- y authorized charges incurred by SCE on the DWP's behalf. The scheduling coordinator charges are billed to DWP under aFERC tariff that remains subject to dispute. DWP has paid the amounts billed under-protest but requested the FERC declare that SCE was obligated to serve as the DWP's scheduling coordinator without charge. The FERC accepted SCE's tariff for filing, but held that therates charged to DWP have not been shown to be just and reasonable and thus made them subject to refund and further review at the FERC.As a result, SCE could be required to refund all or part'of the amounts collected from DWP under the tariff. During the fourth quarter of 2005'SCE accrued a $25iiiillion'charge to '

earnings for the potential refunds, reflected in the consolidated statements of income caption "Purchased power". If the FERC ultimately rules that SCE may not collect'the scheduling coordinator charges 'from DWP and requires the amounts collected to berefunded to DWP, SCE would attempt to recover the scheduling coordinator charges from all transmission grid customers through another regulatory .>- -

mechanism. However, the availability of other recovery mechanisms' is uncertain; and ultimate'recovery J of the scheduling coordinator charges cannot be assured.

Spent Nuclear Fuel  ; Ai;,, .  ; -

Under federal law, the United States Department of Energy (DOE) is responsible for the selection' and;'

construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive: -

waste. The DOE did not meet its obligation to begin acceptance of spent nuclear fuel not later'than;'

January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus'interest). SCE is also paying the'required quarterly fee equal to 0. I-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29,;2004, SCE, as operating agent, filed a complaint I against the DOE in the United States Court of Federal Claims seeking damages for DOE's failure to meet

'*76

Southern California Edison Company its obligation to begin accepting spent nuclear fuel from San Onofre. The case is currently stayed untilI March 31, 2006, when SCE will seek to lift the stay and go forvard with the litigation.

SCE has primary responsibility for the, interim storage of spent nuclearfuel generated at San Onofre.

Spent nuclear fuel is stored in. the San Onofre Units 2 and 3ispent fuel pools and the San Onofre .!

independent.spent fuel storage installation where all of Unit .1's spent fuel located at San Onofre is.

stored. There is now.sufficient space in the Unit 2 and 3 spent fuel pools to meet plant requirements through mid-2007 and mid-2008, respectively. In order to maintain a full core off-load capability, SCIE is planning to begin moving Unit 2 and 3 spent fuel into the independent spent fuel storage installation by early 20D7.  ;  ;.;;. *  :.,i; . l In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a dry cask storage facility . Arizona Public Service, as operating agent, plans to continuall-c*

load casks on a schedule to maintain full core off-load capability for all three units.

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Notes to Consolidated Financial Statements Note 10. *BusinessSegments .

.; . . I SCE's reportable business segments include the rate-regulated electric utility segment and the VIE segment. The VIEs were consolidated as of March 31; 2004. The VIEs are gas-fired power plants that sell both electricity and steam. The VIE segment consists of non-rate-regulated entities. SCE's - .

management has no control over the resources allocated to the VIE segment and does not make decisions about its performnance. Additional details on the VIE segment are shown under the heading "Variable Interest Entities" in Note 1. - -  : ;

SCE's business segment information including all line items with VIE activities is:

Xlectric I* ., .: 1 .

In millions,.^ .:Utility. IVlEs Eliminations SCE I ~.I. t .:

Balance Sheet Items as of December 31, 2005:

Cash $ 23 $ 120 4R $ 143 Accounts receivable-net 794 174 (I 19) 849 Inventory 202 18 220 Prepayments and other current assets 88 4 92 Nonutility property-net of depreciation 741 345 1,086 Other long-term assets 535 10 545 Total assets 24,151 671 (119) 24,703 Accounts payable 813 204 (I 19) 898 Other current liabilities 808 2 810 Long-term debt 4,615 54 4,669 Asset retirement obligations 2,608 13 2,621 Minority interest 398 398 Total liabilities and shareholder's equity 24,151 671 (119) 24,703 Balance Sheet Items as Of December 31, 2004:

Cash and equivalents $ 32 $ 90 $ 122

$104 Accounts receivable-net 569 153 618 Inventory 181 15 196 Prepayments and other current assets 43 3 46 (104)

Nonutility property-net of depreciation 583 377 960 Other long-termn assets 562 5 567 Total assets 22,751 643 23,290 (104)

Accounts payable 638 166 700 Other current liabilities 641 2 643 Long-term debt 5,171 54 5,225 (104)

Customer advances and other deferred credits 498 12 510 Minority interest 409 409 Total liabilities and shareholder's equity 22,751 643 23,290 78

Southern California Edison Company Electric In millions . Utility VIEs Eliminations*. SCE.

Income Statement Items for the Year-Ended December 31, 2005:

Operatin.: revenue $ 9,038 $1,397 $ (935) $ 9,5)0 Fuel 269 924 - 1,193 Purchased power 3,557 - (935) 2,622 Other op ration and maintenance 2,421 102 - 2,523 Depreciation, decommissioning and amortization 878 37 - 915 Total operating expenses 7,743 1,063 (935) 7,871 Operating income 1,295 334 - 1,629 Minority interest 334 - 334 Net income 749 - - 749 Income Statement Items for the Year-Ended December 31, 2004:

Operating revenue $ 8,163 $ 954 $ (669) $ 8,448 Fuel 232 578 - 810 Purchased power 3,001 - (669) 2,332 Other op ration and maintenance 2,389 68 - 2,4.57 Depreciation, decommissioning and amortization 832 28 - 8,50 Total operating expenses 6,430 674 (669) 6,435 Operating income 1,733 280 - 2,013 Minority interest - 280 - 2:30 Net income 921 - - 9:1

• VIE segment revenue includes sales to the electric utility segment, which is eliminated in revenue and purchased power in the consolidated statements of income.

Note II. Discontinued Operations In July 2003, the CPUC approved SCE's sale of certain oil storage and pipeline facilities to Pacific Terminals LLC for $158 million. In third quarter 2003, SCE recorded a $44 million after-tax gain to shareholders. In accordance with an accounting standard related to the impairment and disposal of long-lived assets, this oil storage and pipeline facilities unit's results have been accounted for as a discontinued operation in the 2003 financial statements. For 2003, revenue from discontinued operations was $20 million and pre-tax income was $82 million.

Note 12. Acquisition In March 2004, SCE acquired Mountainview Power Company LLC, which consisted of a power plant in early stages of construction in Redlands, California. SCE recommenced full construction of the approximately $600 million project. The Mountainview project is fully operational.

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Quarterly Financial Data (Unaudited) Southern California Edison Company 2005 2004 In millions . . . Total Fourth Third Second First Total Fourth Third Second First Operating revenue $9,500 $2,306 $3,084 S2,203 $1,908 $8,448 $1,920 $2,655 $2,176 $1,696 Operating income 1,629 . . 345 568 ,388 328 2,013 499 682 . 587. 245 Net income . 749 163 287, . 166 132 921 317 260. 243 101 Net income available for common stock 725 - 153 280 161 ;131 .915 ;315 . 259 242 .100 Common dividends declared 285 .

71 143 - 71 750 155 150 .145. 300 Totals may not add precisely due to rounding.

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Selected Financial and Operating Data: 2001 - 2005 Southern California Edison Company Dollars in millions 2005 2004 2003 2002 21001 Income statement data:

Operating revenue . $ 9,500 $ 8,448, $ 8,854 $ 8,706 $ 8,126 Operating expenses  : 7,871 6,435; 7,276 6,588 3.509 Purchas-d-power expenses 2,622 2,332 2,786 2,016 3.770 Income tax ;292 438 388 642 1.658 Provisions for regulatory adjustment clauses - net 435 (201) 1,138 , 1,502 (3.028)

Interest expense - net of amounts capitalized 360 409 457 .584 785 Net incc me from continuing operations 749 921 - 882 1,247 2.408 Net income 749 - 921 932 1,247 2.408 -

Net income available for common stock 725 . 915 922 1,228 2,386 Ratio of earnings to fixed charges 3.79 4.40 3.81 4.21 5.15 Balance sheet data:

Assets $ 24,703 $ 23,290 $ 21,771 $ 36,058 $ 22.453 Gross utility plant 19,232 17,981 16,991 16,232 :15,982 Accumulated provision for depreciation and decommissioning 4,763 '4,506 4,386 4,057 7,969 Short-term debt 88 200 - 2.127 Common shareholder's equity 4,930 4,521 4,355 4,384 3,146 Preferred and preference stock:

Not subject to mandatory redemption 729 '129 129 129 129 Subject to mandatory redemption - 139 141 147 151 Long-tetm debt 4,669 5,225 4,121 4,525 4.739 Capital structure:

Common shareholder's equity 47.7% 45.1% 49.8% 47.7% 38.5%

Preferred stock:

Not subject to mandatory redemption 7.1% 1.3% 1.5% 1.4% . 1.6%

Subject to mandatory redemption - 1.4% 1.6% 1.6%. . 1.9%

Long-term debt 45.2% 52.2% 47.1% 49.3% ,58.0%

Operating data:

Peak demand in megawatts (MW) 21,934 20,762 20,136 18,821 17,890 Generation capacity at peak (MW) 10,536 10,207 9,861 9,767 9,802 Kilowatt-hour deliveries (in millions) 100,992 97,273 92,763 79,693 78,524 Total energy requirement (kWh) (in millions) 78,772 78,738 77,158 71,663 83,495 Energy mix:

Therma.l 37.0% 33.7% 37.9% 40.2% , :2.5%

Hydro 6.5% 4.5% 5.2% 5.0% 3.6%

Purchased power and other sources 56.5% 61.8% 56.9% 54.8% (63.9%

Customers (in millions) 4.74 4.67 4.60 4.53 4.47 Full-time employees 14,041 13,454 12,698 12,113 11,663 81

Board of Directors John E.Bryson3; Ronald '.Olson l :; , I Audit Committee I " ' IJ I Chairman of the Board, Senior Partner, --. 2 Compensation and Executive Personnel.

President and Munger, Tolles and Olsori (law firm) Committee ..

Chief Executive Officer, Los Angeles, California 3 Executive Committee '

Edison International; A director since-l995 4 Finance Committee Chairman of the Board, Southern' 5 Nominating/Corporate Governance California Edison Company; '. (; James M.Rosser 3. -4 Committee ...

Chairman of the Board, Edison Capital President, 6 Pricing Committee A director from 1990-1999; California State University, Los Angeles 7 Pricing Comrimittee (Alternate Member) 2003 to present Los Angeles, California A director since 1985 France A. C6rdova 5 Chancellor, Richard T.Schlosberg. 11ii125 University of California, Riverside Retired President and , .,. .,. .,.

Riverside, California Chief Executive Officer, A director since 2004 The David and Lucile Packard Foundation (private family foundation)

Alan J. Fohrer aS San Antonio, Texas ,*-, -. .j I.-

Chief Executive Officer, A director since 2002 I II Southern California Edison Company I I I *. - j! - "

A director since 2002 Robert H.Smith 125 Robert H. Smith Invesrments Bradford M.Freeman : and Consulting Founding Partner,A (bariking and finriancial-related Freeman Spogli & Co. consulting servikesy.

(private investment company) Pasadena, California Los Angeles, California A director since 1987 A director since 2002 Thomas C.Sutton in Bruce Karatz 2 S- *' Chairman of the Board and Chairman and Chief Executive Officer, Chief Executive Officer, KB Home (homebuilding) Pacific Life Insurance Company I., -, ,,

Los Angeles, California 'Newport Beach, California A director since 2002 A director since 1995

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Luis G.Nogales 12.4.7

'Managing Partner, Nogales Investors, LLC (private equity investment company)

"Los AngelesCalifornia A director since 1993  ; *.  ;.

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Management Team John E.Bryson Robert C.Boada Barbara J. Parsky Ch airman of the Board Vice President and Treasurer Vice President, Corporate Communications Alan J. Fohrer William L.Bryan Chief Executive Officer Vice President, Kevin M.Payne Business Customer Division Vice President, John R.Fielder Enterprise Resource Planning President Ann P.Cohn Vice President and Frank J.Quevedo BrLce C.Foster Associate General Counsel Vice President, Senior Vice President, Equal Opportunity Regulatory Operations Jodi M. Collins Vice President, James T.Reilly Polly L.Gault Information Technology Vice President, Senior Vice President, Nuclear Engineering and Public Affairs Diane L.Featherstone Technical Services Vice President and General Auditor Ro iald L.Litzinger Anthony L.Smith Senior Vice President, Frederick J. Grigsby, Jr. Vice President, Trnsmission and Distribution Vice President, Tax Human Resources and Labor Relations Thomas M.Noonan Kenneth S.Stewart Senior Vice President and Harry B.Hutchison Vice President and Chief Financial Officer Vice President, Chief Ethics and Compliance Officer Customer Service Operations Stephen E.Pickett Linda G.Sullivan Senaior Vice President and Akbar Jazayeri Vice President and General Counsel RVicePresident,ari ff Controller Revenue and Tariffs Pedro J.Pizarro Raymond W.Waldo Se tior Vice President, Walter J. Johnston Vice President, Pcwer Procurement Vice President, Nuclear Generation Power Delivery Richard M. Rosenblum Se iior Vice President, Brian Katz Generation and Chief Nuclear Officer Vice President, Nuclear Oversight and Mahvash Yazdi Regulatory Affairs Seaior Vice President, Business Integration and James A. Kelly Chief Information Officer Vice President, Engineering and Technical Services Lynda L.Ziegler Senior Vice President, R.W.(Russ) Krieger, Jr.

Customer Service Vice President, Power Production Barbara E.Mathews Vice President, Associate General Counsel, Chief Governance Officer, and Corporate Secretary

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Shareholder Information Annual Meeting Transfer Agent and Registrar Inquiries may also be directed to:

The annual meeting of shareholders Wells Fargo Bank, N.A., which Mail will be held on Thursday, April 27, maintains shareholder records, is Wells Fargo Bank, N.A.

2006, at 10:00 a.m., Pacific Time, at the transfer agent and registrar for Shareowner Services Department the Pacific Palms Conference Resort; SCE's preferred and preference 161 North Concord Exchange Street One Industry Hills Parkway, City of stock. Shareholders may call South St. Paul, MN 55075-1139 Industry, California 91744. Wells Fargo Shareowner Services, (800) 347-8625, between 7 a.m. Fax Corporate Governance Practices and 7 p.m. (Central Time), Monday (651) 450-4033 A description of SCE's corporate gov- through Friday, to speak with a rep-ernance practices is available on our resentative (or to use the interactive Wells Fargo Shareowner Services' Web site at wwunedisoninr'estor.com. voice response unit 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day, u'w.ut ellsfargo.comlshareownerservices The SCE Board Nominating/ seven days a week) regarding:

Web Address Corporate Governance Committee www edisoninvestor.com periodically reviews the Company's

• stock transfer and name-change corporate governance practices and requirements; Online account information:

makes recommendations to the www.shareowneronline. com

• address changes, including Company's Board that the practices dividend payment addresses; be updated from time to time.

• electronic deposit of dividends; Stock and Trading Information

• taxpayer identification number Preferred Stock and Preference Stock submissions or changes; SCE's 4.08%, 4.24%, 4.32% and 4.78% iSeries of $25 par value

• duplicate 1099 and W-9 forms; cumulative preferred stock are listed

• notices of, and replacement of, on the American Stock Exchange.

lost or destroyed stock certificates Previous; day's closing prices, when and dividend checks; and stock was traded, are listed in the daily newspapers under the

• requests for access to online American Stock Exchange. Shares account information.

of SCE's Series A, Series B and Series C preference stock are not listed on an exchange.

I I

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One)

[XI ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2005

[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission File Number 1-2313 SOUTHERN CALIFORNIA EDISON COMPANY (Exact name of registrant as specified in its charter)

California 95-1240335 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.)

22414 Walnut Grove Avenue (P.O. Box 800)

Rosemead, California (Address of principal 91770 executive offices) (Zip Code)

Registrant's telephone number, including area code: (626) 302-1212 Securities registered pursuant to Section 12(b) of the Act:

Name of each exchange Title of..each class on which registered Capital Stock Cumulative Preferred American 4.08% Series 4.32% Series 4.24% Series 4.78% Series Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes El No 0 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes 0 No El

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 0 No 0 Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part m of this Form 10-K or any amendment to this Form 10-K. 0 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-12 of the Exchange Act. (Check One):

Large Accelerated Filer 0 Accelerated Filer 0 Non-accelerated filer 0 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes 0 No 0 As of June 30, 2005, there were 434,888,104 shares of Common Stock outstanding, all of which are held by the registrant's parent holding company. The aggregate market value of registrant's voting and non-voting common equity held by non-affiliates was zero. As of March 3, 2006, there were 434,888,104 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE Portions of the following documents listed below have been incorporated by reference into the parts of this report so indicated.

(1) Designated portions of the registrant's Annual Report to Shareholders for the year ended December 31, 2005 ................................................. Parts I and II (2) Designated portions of the Proxy Statement relating to registrant's 2006 Annual Meeting of Shareholders ................................................. Part m

TABLE OF CONTENTS Item Page Forward-Looking Statements .................... I Part I

1. Bu siness............................................................................................................................................

.I Regulation..................................................................................................................................2 Competition................................................................................................................................3 Properties....................................................................................................................................3 Nuclear Power Matters ........................................ 5 Purchased Power and Fuel Supply ...... 5..........................

Discontinued Operations ........................................ 6 Seasonality ........................................ 6 Environmental Matters ........................................ 6 Financial Information About Geographic Areas ....................................... 12 1A. Risk Factors ........................................ 12 1B. Unresolved Staff Comments ....................................... . 15

2. Properties ....................................... 15

3. Legal Proceedings ....................................... 16 Navajo Nation Litigation ....................................... 16 Department of the Army, Los Angeles District, Corps of Engineers/Notice of Violation of Clean Water Act ....................................... 16

4. Submission of Matters to a Vote of Security Holders ....................................... 16 Executive Officers of the Registrant ........................................ 17 Part II

5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ....................................... 19

6. Selected Financial Data ....................................... 19

7. Management's Discussion and Analysis of Financial Condition and Results of Operations ......... .. 19 7A. Quantitative and Qualitative Disclosures About Market Risk 0..........................

0

8. Financial Statements and Supplementary Data .................................................................... '20

9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ........... 20 9A. Controls and Procedures ................................................................... 20 9B. Other Information ................................................................... 20 Part III

10. Directors and Executive Officers of the Registrant ................................................................... 20

11. Executive Compensation ................................................................... 21

12. Security Ownership of Certain Beneficial Owners and Management .............................................. 21

13. Certain Relationships and Related Transactions ................................................................... 2.1

14. Principal Accounting Fees and Services 21 1...........................

15. Exhibits and Financial Statement Schedules ................................................................... 71 Financial Statements 21...........................

Report of Independent Registered Public Accounting Firm and Schedules Supplementing Financial Statements .22...........................

E xhibits ....................................................................................................................................... .22 Signatures .......................................................................................................................................... .27

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FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Southern California Edison Company's (SCE) current expectations and projections about future events based on SCE's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by SCE that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates,"

",estimates," "projects," "intends," "plans," "probable," may,' will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. See "Risk Factors" in Part I, Item IA of this report and "Introduction" in the MD&A for cautionary statements that accompany those forwarc.-looking statements and identify important factors that could cause results to differ. Readers should carefully review those cautionary statements as they identify important factors that could cause results to differ, or that otherwise could impact SCE or its subsidiaries.

Additional information about risks and uncertainties, including more detail about the factors described in this report, is contained throughout this report, in the Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) that appears in SCE's 2005 Annual Report to Shareholders (Annual Report), the relevant portions of which are filed as Exhibit 13 to this report, and which is incorporated by reference into Part II, Item 7 of this report, and in Notes to Consolidated Financial Statements (Notes to Financial Statements). Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect SCE's business. Forward-looking statements speak only as of the date they are made and SCE is riot obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE with the Securities and Exchange Commission (SEC).

PART I ITEM l. BUSINESS SCE was incorporated in 1909 under the laws of the State of California. SCE is a public utility primarily engaged in the business of supplying electric energy 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 include:; approximately 428 cities and communities and a population of more than 13 million people. In 2005, SCE's total operating revenue was derived as follows: 39% commercial customers, 33% residential customers, 9% resale sales, 7% industrial customers, 5% other electric revenue, 5% public authorities, and 2% agricultural and other customers. At December 31, 2005, SCE had consolidated assets of $24.7 billion and total shareholder's equity of $5.7 billion. SCE had 14,041 full-time employees at year-end 2005. Edison International owns all of the common stock of SCE. Except when otherwise stated, references to SCE mean SCE together with its subsidiaries on a consolidated basis.

Information about SCE is available on the intemet website maintained by Edison International at http:H/Aww.edisoninvestor.com. SCE makes available, free of charge on that internet website, its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after SCE electronically files such material with, or furnishes it to, the S;EC. Such reports are also available on the SEC's internet website at http://www.sec.gov. The I

information contained in our website, or connected to that site, is not incorporated by reference into this report.

Regulation 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, issuance of securities, and accounting practices. SCE's wholesale operations 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 retail transmission service pricing, accounting practices, and licensing of hydroelectric projects.

Additional information about the regulation of SCE by the CPUC and the FERC, and about SCE's competitive environment, appears in the MD&A under the heading "Regulatory Matters." Also see "-

Competition."

SCE is subject to the jurisdiction of the United States Nuclear Regulatory Commission with respect to its nuclear power plants. United States Nuclear Regulatory Commission regulations govern the granting of licenses for the construction and operation of nuclear power plants and subject those power plants to continuing review and regulation.

The construction, planning, and siting of SCE's power plants within California are subject to the jurisdiction of the California Energy Commission and the CPUC. SCE is subject to the rules and regulations of the California Air Resources Board, State of Nevada, and local air pollution control districts with respect to the emission of pollutants into the atmosphere; the regulatory requirements of the California State Water Resources Control Board and regional boards with respect to the discharge of pollutants into waters of the state; and the requirements of the California Department of Toxic Substances Control with respect to handling and disposal of hazardous materials and wastes. SCE is also subject to regulation by the United States Environmental Protection Agency (US EPA), which administers federal statutes relating to environmental matters. Other federal, state, and local laws and regulations relating to environmental protection, land use, and water rights also affect SCE.

The California Coastal Commission issued a coastal permit for the construction of the San Onofre Nuclear Generating Station (San Onofre) Units 2 and 3 in 1974. This permit, as amended, requires mitigation for impacts to fish and the San Onofre kelp bed. California Coastal Commission jurisdiction will continue for several years due to ongoing implementation and oversight of these permit mitigation conditions, consisting of restoration of wetlands and construction of an artificial reef for kelp. SCE has a coastal permit from the California Coastal Commission to construct a temporary dry cask spent fuel storage installation for San Onofre Units 2 and 3. The California Coastal Commission also has continuing jurisdiction over coastal permits issued for the decommissioning of San Onofre Unit 1, including for the construction of a temporary dry cask spent fuel storage installation for spent fuel from that unit.

The United States Department of Energy has regulatory authority over certain aspects of SCE's operations and business relating to energy conservation, power plant fuel use and disposal, electric sales for export, public utility regulatory policy, and natural gas pricing.

SCE is subject to CPUC affiliate transaction rules and compliance plans governing the relationship between SCE and its affiliates. On October 27, 2005, the CPUC issued an order instituting rulemaking (OIR) to allow the CPUC to re-examine the relationships of the major California energy utilities with their parent holding companies and non-regulated affiliates. The OIR was issued in part in response to the repeal of PUHCA 1935. Additional information about the OIR appears in the MD&A under the heading 2

"Regulatory Matters-Current Regulatory Developments-Holding Company Order Instituting Rulemaking."

In addition, the CPUC has issued affiliate transaction rules governing the relationships between SCE and its affiliates, including Edison International and its nonutility subsidiaries. SCE has filed compliance plans which set forth SCE's implementation of the CPUC's affiliate transaction rules. The rules and compliance plans are intended to maintain separateness between utility and nonutility activities and ensure that utility assets are not used to subsidize the activities of nonutility affiliates.

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. California law currently provides only limited opportunities for customers to choose to purchase power dlirectly from an energy service provider other than SCE. SCE also faces some competition from cities 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 lhe size of SCE's customer base, thereby creating upward pressure on SCE's rate structure to cover fixed costs, which in turn may cause more customers to leave SCE in order to obtain lower rates.

Properties SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, which deliver power from generating sources to the distribution network, consist of approximately 7,200 circuit miles of 33 kilovolt (kV), 55 kV, 66 kV, 115 kV, and 161 kV lines and 3,500 circuit miles of 220 kV lines (all located in California), 1,238 circuit miles of 500 kV lines (1040 miles in California, 86 miles in Nevada, and 112 miles in Arizona), and 851 substations. SCE's distribution system, which takes power from substations to the customer, includes approximately 60,300 circuit miles of overhead lines, 37,900 circuit miles of underground lines, 1.5 million poles, 569 distribution substations, 695,000 transformers, and 777,000 area and streetlights, all of which are located in California.

SCE oiTms and operates the following generating facilities: (1) an undivided 75.05% interest (1,614 megawatts (MW)) in San Onofre Units 2 and 3, which are large pressurized water nuclear units located on the California coastline between Los Angeles and San Diego; (2) 36 hydroelectric plants (1,153 MW) located in California's Sierra Nevada, San Bernardino and San Gabriel mountain ranges, three of which (2.7 MW) are no longer operational and will be decommissioned; and (3) a diesel-fueled generating plant (9 MW) located on Santa Catalina island off the southern California coast.

SCE also owns and operates an undivided 56% interest (885 MW net) in the Mohave Generating Station (Mohave), which consists of two coal-fueled generating units located in Clark County, Nevada near the Californiia border. The plant ceased operating on December 31, 2005. At this time, there is no definite return to service date. Additional information regarding Mohave appears in the MD&A under the heading "Regulatory Matters-Mohave Generating Station and Related Proceedings."

In addition, SCE acquired in 2004 Mountainview Power Company LLC, which consisted of a natural gas-fueled two unit power plant in the early stages of construction in Redlands, California. The first unit commenced commercial operations in December 2005, and the second unit commenced commercial operations in January 2006. The Mountainview plant has a generating capacity of 1,054 MW.

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SCE also owns an undivided 15.8% interest (601 MW) in Palo Verde Nuclear Generating Station (Palo Verde), which is located near Phoenix, Arizona, and an undivided 48% interest (710 MW) in Units 4 and 5 at Four Comers Generating Station (Four Comers), which is a coal-fueled generating plant located near the City of Farmington, New Mexico. The Palo Verde and Four Comers plants are operated by Arizona Public Service Company.

At year-end 2005, the SCE-owned generating capacity (summer effective rating) was divided approximately as follows: 43% nuclear, 23% hydroelectric, 20% natural gas, 14% coal, and less than 1%

diesel. The capacity factors in 2005 for SCE's nuclear and coal-fired generating units were: 98% for San Onofre; 76% for Mohave; 85% for Four Corners; and 77% for Palo Verde. For SCE's hydroelectric plants, generating capacity is dependent on the amount of available water. SCE's hydroelectric plants operated at a 49% capacity factor in 2005. These plants were operationally available for 91 % of the year.

The San Onofre units, Four Comers station, certain of SCE's substations, and portions of its transmission, distribution and communication systems are located on lands of the United States or others under (with minor exceptions) licenses, permits, easements or leases, or on public streets or highways pursuant to franchises. Certain of such documents obligate SCE, under specified circumstances and at its expense, to relocate 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 United States lands pursuant to 30- to 50-year FERC licenses that expire at various times between 2006 and 2039 (the remaining five plants are located entirely on private property and are not subject to FERC jurisdiction). 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 purposes greater consideration in the licensing process. SCE's applications for the relicensing of certain hydroelectric projects with an aggregate dependable operating capacity of approximately 209 MW are pending. Annual licenses have been issued to SCE hydroelectric projects that are undergoing relicensing and whose long-term licenses have expired. Federal Power Act Section 15 requires that the annual licenses be renewed until the long-term licenses are issued or denied.

Substantially all of SCE's properties are subject to the lien of a trust indenture securing first and refunding mortgage bonds, of which approximately $5.4 billion in principal amount was outstanding on December 31, 2005 (including the first mortgage bonds issued to secure a $1.7 billion revolving credit facility). Such lien and SCE's title to its properties are subject to the terms of franchises, licenses, easements, leases, permits, contracts, and other instruments under which properties are held or operated, certain statutes and governmental regulations, liens for taxes and assessments, and liens of the trustees under the trust indenture. In addition, such lien and SCE's title to its properties are subject to certain other liens, prior rights and other encumbrances, none of which, with minor or insubstantial exceptions, affect SCE's right to use such properties in its business, unless the matters with respect to SCE's interest in the Four Comers plant and the related easement and lease referred to below may be so considered.

SCE's rights in the Four Comers station, which is located on land of the Navajo Nation of Indians 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 the record systems of the Bureau of 4

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 the Four Corners station.

Nuclear Power Matters Information about operating issues related to San Onofre appears in the MD&A under the heading "Regulatory Matters-Current Regulatory Developments-San Onofre Nuclear Generating Station Steam Genera :ors." Information about Palo Verde steam generator replacements appears in the MD&A under the heading "Regulatory Matters-Current Regulatory Developments-Palo Verde Generating Station Steam Generators." Information about nuclear decommissioning can be found in Note 8 of Notes to Financial Statements. Information about nuclear insurance can be found in Note 9 of Notes to Financial Statements.

Purchased Power and Fuel Supply SCE obtains the power needed to serve its customers from its generating facilities and from purchases from qualifying facilities, independent power producers, the California Independent System Operator, and other utilities, In addition, power is provided to SCE's customers through purchases by the California Departrment of Water Resources (CDWR) under contracts with third parties. Sources of power to serve SCE's customers during 2005 were as follows: 33% purchased power; 23.5% CDWR; and 43.5% SCE-owned generation consisting of 14.3% nuclear, 22.7% coal, and 6.5% hydro. Additional information about SCE's power procurement activities appears in the MD&A under the heading "Regulatory Matters."

NaturalGas Supply SCE's natural gas requirements in 2005 were for start-up use at Mohave, to meet contractual obligaticins 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 SCE's new Mountainview gas-fired generation facility, which commenced operations in December 2005. All of the physical gas purchased by SCE in 2005 was purchased under North American Energy Standards Board agreements (master gas agreements) that define the terms and conditions of transactions with a particular supplier prior to any financial commitment.

SCE contracted for firm access rights onto the Southern California Gas Company system at Wheeler Ridge far 198,863 million British thermal units (MMBtu) per day in a 13-year contract entered into in August 1993, effective November 1, 1993. SCE has the unilateral right to renew this contract for an equivalent term upon the expiration of its initial term. SCE has not yet made a determination as to whether this contract will be extended. SCE also has firm transportation rights of 18,000 MMBtu per day on Southwest Gas Corp's pipeline to serve Mohave.

In 2005, SCE secured a one-year natural gas storage capacity contract with Southern California Gas Company for the 2005/2006 storage season. Storage capacity was secured to provide operation flexibility and to mitigate potential costs associated with the dispatch of SCE's tolling agreements. SCE has been in negotiations with Southern California Gas Company for additional storage but has not yet entered into a similar arrangement.

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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....................................................................................... 2008 Conversion................................................................................................ 2008 Enrichment................................................................................................ 2008 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....................................................................................... 2008 Conversion................................................................................................ 2008 Enrichment................................................................................................ 2010 Fabrication................................................................................................. 2015 Spent Nuclear Fuel Information about Spent Nuclear Fuel appears in Note 9 of Notes to Financial Statements.

Coal Supply SCE has purchased coal pursuant to long-term contracts to provide stable and reliable fuel supplies to its two coal-fired generating stations, the Four Comers and Mohave plants. SCE entered into a coal contract, dated September 1, 1966, with the Utah Construction & Mining Company, the predecessor to the current owner of the Navajo mine, the BBP Navajo Coal Company, to supply coal to Four Corners Units 4 and 5.

The initial term of this coal supply contract for the Four Comers plant was through 2004 and included extension options for up to 15 additional years. On January 1, 2005 SCE and the other Four Corners participants entered into a Restated and Amended Four Corners Fuel Agreement under which coal will be supplied 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. The coal supply contract for the Mohave plant expired on December 31, 2005, and the plant has ceased operating while coal and water issues are resolved. There is no definite return to service date. Additional information about the litigation affecting the coal supply contract for the Mohave plant appears in the MD&A under the heading "Other Developments-Navajo Nation Litigation."

Discontinued Operations Information about SCE's discontinued operations appears in Note 11 of Notes to Financial Statements.

Seasonality Due to warmer weather during the summer months, electric utility revenue during the third quarter of each year is generally significantly higher than other quarters.

Environmental Matters SCE is subject to environmental regulation by federal, state and local authorities in the jurisdictions in which it operates in the United States. This regulation, including the areas of air and water pollution, 6

waste management, hazardous chemical use, noise abatement, land use, aesthetics, and nuclear control, 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 believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results Df operations. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, future proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies could affect the costs and the manner in which SCE ccnducts its business and could cause it to make substantial additional capital or operational expenditures. There is no assurance that SCE would be able to recover these increased costs from its customers or that SCE's financial position and results of operations would not be materially adversely affected. SCE is unable to predict the extent to which additional regulations may affect its operations and capital expenditure requirements.

Typically, environmental laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a project. Meeting all the neczssary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital or operational expenditures. Furthermore, if SCE fails to comply with applicable environmental laws, it may be subject to injunctive relief, penalties and fines imposed by regulatory authorities.

The lavws and regulations discussed below primarily impact SCE's coal-fired, gas-fired and nuclear generation facilities. The air quality and climate change discussions primarily impact the coal-fired Mohave and Four Corners plants. Developments in the air quality and climate change areas may also have an impact on SCE's gas-fired Mountainview plant. However, the Mountainview plant was constructed with current pollution control technology so the impact of new regulations would likely have less of an impact on Mountainview than Mohave and Four Comers. The Mountainview plant is SCE's only gas-.

fired generation facility. The water quality discussion primarily impacts San Onofre.

Air Quzlity SCE's facilities are subject to various air quality regulations, including the Federal Clean Air Act and similar state and local statutes.

Mohave Shutdown In 1998, several environmental groups filed suit against the co-owners of the Mohave plant regarding alleged violations of emissions limits. In order to resolve the lawsuit and accelerate resolution of key environmental issues regarding the plant, the parties entered into a consent decree, which was approved by the Nevada federal district court in December 1999. The consent decree required the installation of certain air pollution control equipment prior to December 31, 2005 if the plant was to operate beyond that date. In addition, operation beyond 2005 required that agreements be reached with the Navajo Nation and the Hopi Tribe (Tribes) regarding post-2005 water and coal supply needs.

SCE's share of the costs of complying with the consent decree and taking other actions to allow operation of the Mohave plant beyond 2005 is estimated to be approximately $605 million. Agreement with the Tribes on water and coal supplies for Mohave was not reached by December 31, 2005, and it is not current] y known whether such an agreement will be reached. No agreement was reached to amend the terms of the federal court consent decree. As a result, Mohave ceased operation on December 31, 2005.

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For the Mohave plant to restart operation, it will be necessary for agreements to be reached with the Tribes on the water and coal supply issues, and for the terms of the consent decree to be met or modified.

Until there is a final resolution as to whether the Mohave plant will begin operating again, and what regulations will be in effect at that time, SCE cannot evaluate the potential impact of the air quality regulations discussed below on the operations of its facilities. Additional capital costs related to those regulations could be required in the future and they could be material, depending upon the final standards adopted.

Regional Haze In the event that the Mohave plant does restart operations, its operations may be subject to the US EPA's final rulemaking on regional haze, issued on June 15, 2005. Under the rule, by December 17, 2007, each state must file with the US EPA as part of its State Implementation Plan (SIP) plans for regional haze improvement. It is not known whether Nevada's regional haze SIP for Mohave will impose any additional emissions control requirements on the Mohave plant beyond meeting the provisions of the 1999 consent decree.

Mercury In the event of a Mohave restart, its operations may be subject to the US EPA's Clean Air Mercury Rule (CAMR), which was issued on March 15, 2005. CAMR creates a market-based cap-and-trade program to reduce mercury emissions from existing coal-fired power plants down to a national cap of 38 tons by 2010 and to 15 tons by 2018. States may join the trading program by adopting the CAMR model trading rules in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR's suggested cap-and-trade program. The CAMR allocates mercury emission credits to each plant, including Mohave, based on a model rule that states, including Nevada, may adopt.

Contemporaneous with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired power plants had to be regulated as a hazardous air pollutant pursuant to Section 112 of the federal Clean Air Act, which would have imposed technology-based standards.

Litigation has been filed challenging the rescission action, alleging that the US EPA erred in adopting a market-based program rather than technology-based emissions limitations. Litigation has also been filed to challenge the CAMR. Depending on the results of these challenges, the CAMR rules and timetables may change.

If Nevada adopts the US EPA's model allocations rule, SCE expects that Mohave would have sufficient mercury credits to meet operational needs until 2018, at which time estimated mercury credit allocations are approximately 50% lower than required for operations. States are required to adopt a mercury reduction method and submit their mercury SIP to the US EPA by November 2006. While Nevada has begun its scoping meetings for this rulemaking, it is not yet known what approach Nevada will take on its mercury regulation.

For SCE, these regulations will primarily impact its possible future operation of the Mohave plant.

Additional information regarding the shutdown of Mohave appears in the MD&A under the heading "Regulatory Matters-Current Regulatory Developments-Mohave Generating Station and Related Proceedings."

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NationalAmbient Air Quality Standards The ambient air quality standards for ozone and fine particulate matter adopted by the US EPA in July 1997 are another regulatory standard to which Mohave may be subject if it resumes operations. The US EPA designated non-attainment areas for the 8-hour ozone standard on April 30, 2004, and for the fine particulate standard on January 5, 2005. States are required to revise their implementation plans for the ozone and particulate matter standards within three years of the effective date of the respective non-attainment designations - by June 2007 for the 8-hour ozone SIP, and by April 2008 for the fine particulate SIP.

Clark County, Nevada, where the Mohave plant is located, has been designated a nonattainment area for the new 8-hour ozone national ambient air quality standard. Clark County is currently in the process of developing its SIP to demonstrate attainment of the 8-hour ozone standard. Depending on the control measures adopted for Clark County's 8-hour ozone SIP, Mohave may be required to reduce nitrogen oxide (NOx) emissions (NOx emissions are a precursor to ambient levels of ozone) below the levels resulting from the low NOx burner control technology required under the 1999 Mohave consent decree.

Until information is available regarding Clark County's SIP, SCE cannot fully evaluate the potential impact on Mohave if it resumes operations. Additional capital costs related to those regulations could be required in the future and they could be material, depending upon the final standards adopted.

Clean AlirAct InterstateRule At this time, the US EPA's Clean Air Act Interstate Rule (CAIR), does not have an impact on SCE's facilities. CAIR, issued by the US EPA on March 10, 2005, applies to 28 eastern states and the District of Columbia, and is intended to address ozone attainment issues by reducing regional sulfur dioxide and NOx ermissions. The CAIR has been challenged in court by state, environmental, and industry groups, which may result in changes to the substance of the rule and to the timetables for implementation. While the US EPA has not adopted a rule comparable to CAIR for the western United States, where SCE has facilities, SCE cannot predict what action the US EPA will take in the future with regard to the western United States, and what impact those actions would have on its facilities.

New Source Review Requirements Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address Clean Air Act New Source Review (NSR) compliance issues at the nation's coal-fired power plants. The NSR regulations impose certain requirements on facilities, such as electric generating stations, in the event that modifications are made to air emissions sources at the facility. The US EPA's strategy included both the filing of a number of suits against power plant owners, and issuance of a number of administrative notices of violation to power plant owners alleging NSR violations. SCE and its subsidiaries have not been named as a defendant in these lawsuits and have not received any administrative notices of violation alleging NSR violations at any facilities.

In October 2005, the US EPA announced a revised NSR strategy to take account of recent US EPA rulemalings, such as the CAIR and regional haze rules, affecting coal-fired power plants. Under the revised strategy, while the US EPA will continue to pursue filed cases and cases in active negotiation., it intends to shift its future enforcement focus from coal-fired power plants to other sectors where compliance assurance activities have the potential to produce significant environmental benefits.

Developments will continue to be monitored by SCE, to assess what implications, if any, they will have on the operation of power plants owned or operated by SCE, or on SCE's results of operations or financial position.

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Climate Change The Kyoto Protocol on climate change officially came into effect on February 16, 2005. Under the Kyoto Protocol, the United States would have been required, by 2008-2012, to reduce its greenhouse gas emissions, such as carbon dioxide, by 7% from 1990 levels. Under the Bush administration, however, the United States has chosen not to pursue ratification of the Kyoto Protocol. Instead, the Bush administration has proposed several alternatives to mandatory reductions of greenhouse gases.

There have been several petitions from states and other parties to compel the US EPA to regulate greenhouse gases under the Clean Air Act. Also, in 2004 several states and environmental organizations brought a complaint in federal court in New York, alleging that several electric utility corporations are jointly and severally liable under a theory of public nuisance for damages caused by their alleged contribution to global warming resulting from carbon dioxide emissions from coal-fired power plants owned and operated by these companies or their subsidiaries. SCE was not named as a defendant in the complaint. The case was dismissed and is currently on appeal with the United States Court of Appeals for the Second Circuit.

In California, Governor Schwarzenegger issued an executive order on June 1, 2005 setting forth targets for greenhouse gas reductions. The targets call for a reduction of greenhouse gas emissions to 2000 levels by 2010; a reduction of greenhouse gas emissions to 1990 levels by 2020; and a reduction of greenhouse gas emissions to 80% below 1990 levels by 2050.

The CPUC is addressing climate change related issues in various regulatory proceedings. In a decision pertaining to SCE's 2004 long-term procurement plan the CPUC is requiring a "carbon adder" of

$8-$25/ton of carbon dioxide to be used in the evaluation of fossil fuel generation bids for contracts of five years or longer. On October 6, 2005, the CPUC adopted a resolution directing the CPUC staff and general counsel to investigate adoption by the CPUC of a greenhouse gas emissions performance standard for investor-owned utilities procurement. On February 16, 2006, the CPUC issued a decision in the Procurement Incentive Framework proceeding, in which the CPUC states its intent to develop a load-based greenhouse gas emissions cap for SCE, and other load serving entities the CPUC asserts to be within its jurisdiction.

SCE will continue to monitor these developments relating to greenhouse gas emissions to determine their impacts on SCE's operations. Any legal obligation that would require SCE to reduce substantially its emissions of carbon dioxide could require extensive mitigation efforts at its Mohave plant if it resumes operations, and could raise considerable uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generating facilities. New regulations could also increase the cost of purchased power, which is generally borne by SCE's customers. Additional information regarding purchased power costs appears in the MD&A under the heading "Regulatory Matters."

Hazardous Substances and Hazardous Waste Laws Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating 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 to a governmental entity or to third parties for property damage, personal injury, natural resource damages, and investigation and remediation costs incurred by these 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), and the Resource Conservation and Recovery Act (RCRA), impose liability without regard to whether the owner 10

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 addition, the federal Toxic Substances Control Act (TSCA) and accompanying regulations govern the manufacturing, processing, distribution in commerce, use, and disposal of listed compounds, including polychlorinated biphenyls (PCBs), a toxic substance. Federal, state, and local laws, regulations and ordinances also govern the removal, encapsulation or disturbance of asbestos-containing materials when these materials are in poor condition or in the event of construction, remodeling, renovation or demolition of a building and other structures containing asbestos.

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 the laws and regulations identified herein.

The CIPUC allows SCE to recover in retail rates paid by its customers partial environmental remediation costs a: certain sites through an incentive mechanism. Additional information about these laws and regulations appears in Note 9 of Notes to Financial Statements and in the MD&A under the heading "Other Developments-Environmental Matters."

Water Quality 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 thermal component (heat) 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. SCE incurs additional expenses and capital expenditures in order to comply with guidelines and standards applicable to certain of its facilities.

Cooling Water Intake Structures On July 9, 2004, the US EPA published the final Phase II regulations implementing Section 316(b) of the Clean Water Act. The rulemaking establishes standards for cooling water intake structures at existing electrical generating stations that withdraw more than 50 million gallons of water per day and use more than 25% of that water for cooling purposes. The purpose of the regulations is to substantially reduce the number of aquatic organisms that are impinged against cooling water intake structures or drawn into cooling water systems.

While SCE believes that this rule, as drafted, would not have a material impact on SCE's operations at San Onofre, certain aspects of the rule that are being contested in the courts, such as the right to offset impacts through restoration, are important to SCE's expectation that compliance with the new rules will not req ire any physical or operational modifications at San Onofre. Until the challenges to the rulemaking have concluded, SCE cannot determine the full financial impact of this rule.

Electric and Magnetic Fields Electric and magnetic fields naturally result from the generation, transmission, distribution and use of electricity. Since the 1970s, concerns have been raised about the potential health effects of electric and magnetic fields (EMF). After 30 years of research, a health hazard has not been established to exist.

Potentially important public health questions remain about whether there is a link between EMF exposures in homes or work and some diseases, and because of these questions, some health authorities have identified EMF exposures as a possible human carcinogen.

11

In October 2002, the California Department of Health Services released to the CPUC and the public its report evaluating the possible risks from EMF. The conclusions in the report of the California Department of Health Services contrast with other recent reports by authoritative health agencies in that the California Department of Health Services has assigned a substantially higher probability to the possibility that there is a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis, and miscarriages.

On August 19, 2004, the CPUC issued an order instituting rulemaking to update the CPUC's policies and procedures related to EMF emanating from regulated utility facilities. Following submission of comments and information by all interested parties to the CPUC in 2004 and 2005, the administrative law judge issued a draft decision in December 2005, and the CPUC issued its final decision on January 26, 2006.

The decision concluded that a direct link between exposure to EMF and human health effects has yet to be proven, and affirms the CPUC's existing "low-cost/no-cost" EMF policies to mitigate EMF exposure for new utility transmission and substation projects.

Financial Information About Geographic Areas All of SCE's revenues for the last three fiscal years are attributed to SCE's country of domicile, the United States. All of SCE's assets are located in the United States.

ITEM IA. RISK FACTORS SCE's financial viability depends upon its ability to recover its costs in a timely mannerfrom its customers through regulated rates.

SCE is a regulated entity subject to CPUC 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, in its CPUC-approved rates 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 in rates an adequate return on capital, including long-term debt and equity. If SCE is unable to recover any material amount 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 revenues and earnings are substantially affected by regulatory proceedings known as general rate cases and cost of capital proceedings. General rate cases are expected to occur every three years. During those cases, the CPUC determines SCE's rate base (the value of assets on which SCE earns a rate of return for investors), depreciation rates, operation and maintenance costs, and administrative and general costs that SCE may recover from its customers through its rates. Cost of capital proceedings are conducted annually. During those cases, the CPUC authorizes SCE's capital structure and the return on common equity applicable to the rate base determined in the general rate case proceedings. More information about these proceedings is set forth in the MD&A under the heading "Regulatory Matters."

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

SCE obtains energy, capacity, and ancillary services needed to serve its customers from its own generating plants and contracts with energy producers and sellers. California law and CPUC decisions 12

allow SCE to recover in customer rates reasonable procurement costs incurred in compliance with an approved procurement plan. Nonetheless, SCE's cash flows remain subject to volatility resulting from its procuiement activities. In addition, SCE is subject to the risks of unfavorable or untimely CPUC decisions about the compliance of procurement activities with its 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 in rates, 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. 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.

SCE relies on access to the capitalmarkets. If SCE were unable to access capitalmarkets or the cost of capital were to substantiallyincrease, its liquidity and operationscould be adversely affected.

SCE's ability to make scheduled payments of principal and interest, refinance debt, and fund its operations and planned capital expenditure projects depends on its cash flow and access to the capital marke s. SCE's ability to arrange financing and the costs of such capital are dependent on numerous factor, including its 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:

• an economic downturn;

• capital market conditions generally;

• 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 additicnal capital from time to time may have a material adverse effect on SCE's liquidity and operations.

SCE is subject to numerous environmentallaws andregulationswith respect to operationof its facilities. New laws andregulationscould adversely affect SCE.

The oreration of SCE's power generation, transmission, and distribution facilities is subject to numerous environmental laws and regulations. Those laws and regulations require SCE to expend substantial sulms to mitigate or remove the effect of its operations on the environment and can impede the development of new facilities. Violations of environmental laws and regulations can result in fines, penalties and liability to third parties. In addition, new environmental laws, regulations and standards may be adopted that would impose substantial costs on SCE or impair its future operations. Environmental advocacy groups and regulatory agencies have been focusing considerable attention on carbon dioxide emissions and the effect of those emissions on global warming. The adoption of new laws and regulations to control ca:-bon 13

dioxide or other emissions could adversely affect the operation of SCE's generating plants and other facilities and result in additional costs that could adversely affect SCE's results of operations.

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 United States Nuclear Regulatory Commission regulates SCE's nuclear power plants. The construction, planning, and siting of SCE's power plants in California are also subject to the jurisdiction of the California Energy Commission and the CPUC.

Additional regulatory authorities with jurisdiction over some of SCE's operations include the California Air Resources Board, the California State Water Resources Control Board, the California Department of Toxic Substances Control, the California Coastal Commission, the United States Environmental Protection Agency, the United States Department of Energy, the Nuclear Regulatory Commission, and various local regulatory districts.

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.

There are inherent risks associated with operating nuclear power generatingfacilities.

Spentfuel storage capacity could be insufficient to permit long-term operationof SCE's nuclearplants.

SCE operates and is majority owner of the San Onofre Nuclear Generating Station and is part owner of the Palo Verde Nuclear Generating Station. The United States 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 the Palo Verde plant were unable to arrange and maintain sufficient capacity for interim spent-fuel storage now or in the future, it could hinder 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 insuranceand ratemakingarrangementsmay not protect SCEfully against lossesfrom a nuclear incident.

Federal law limits public liability from a nuclear incident to $10.8 billion. SCE and other owners of the San Onofre and Palo Verde nuclear generating stations have purchased the maximum private primary insurance available of $300 million per site. If the public liability limit is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators. In the event of such an under-insured nuclear incident, a 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 undercollection of SCE's costs.

14

SCE's financialcondition and results of operationscould be materially adversely affected if it is unable to successfully manage the risks inherent in operatingits facilities.

SCE owns and operates extensive electricity facilities that are interconnected to the United States wester electricity grid. 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;

• act; 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, or both, which may not be fully recovered through insurance, rates or other means in a timely manner or at all.

SCE's insurancecoveragemay not be sufficient under all circumstancesand SCE may not be able to obtain sufficient insurance.

SCE's Hnsurance 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 chznges 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.

SCE is subject to costs and other effects of legal proceedingsas well as changes in or additions to applicabletax laws, rates orpolicies, rates of inflation, and accounting standards.

SCE is subject to costs and other effects of legal and administrative proceedings, settlements, investigations and claims, as well as the effect of new, or changes in, tax laws, rates or policies, rates of inflation and accounting standards.

ITEM lB. UNRESOLVED STAFF COMMENTS None.

ITEM 2. PROPERTIES The principal properties of SCE are described above in Part I under the heading "Properties."

15

ITEM 3. LEGAL PROCEEDINGS Navajo Nation Litigation Information about the Navajo Nation litigation appears in the MD&A under the heading "Other Developments-Navajo Nation Litigation."

Department of the Army, Los Angeles District, Corps of Engineers/Notice of Violation of Clean Water Act In December 2004, the United States Army Corps of Engineers (Corps) sent SCE a Notice of Violation (Notice), alleging that SCE or its contractors had discharged fill material into wetlands adjacent to the Santa Ana River (River), in the City of Huntington Beach, CA (City). Under Sections 301 and 404 of the Clean Water Act, the discharge of fill material into waters of the United States is unlawful unless first permitted by the Corps pursuant to Section 404 of the Clean Water Act.

The Notice provided a general description of the area in question but did not specify the location of the violation. Following discussions and correspondence with the Corps, it was determined that the Corps was concerned about the actions of a licensee of SCE on an SCE-owned transmission right-of-way corridor located adjacent to the River. SCE's licensee, or its predecessor-in-interest, had obtained from the City a Conditional Use Permit (CUP) to locate landscape nursery operations within the right-of-way corridor. The CUP required the licensee to perform certain drainage and grading improvements to the property before locating nursery operations on site. During the course of the grading work, the licensee brought additional soil onto SCE's property for use as fill material.

Potential penalties for violation of Section 404 of the Clean Water Act include a maximum criminal fine of $50,000 per day and imprisonment for up to three years, and a maximum civil penalty of $25,000 per day of violation. To date, however, the Corps has not proposed to impose any specific fine or penalty on SCE with respect to the subject matter of the Notice.

In the process of investigating the matter, the Corps requested that SCE perform a wetlands delineation study of the property to determine whether the property in question qualifies as a wetland area subject to Corps jurisdiction. SCE has hired a consulting group to perform the wetlands delineation study, which indicates that there are no federally regulated wetlands or waters of the United States associated with the study area. SCE delivered the study to the Corps in January 2006. The Corps is in the process of evaluating the wetlands delineation study.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of shareholders of Edison International during the fourth quarter of 2005.

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Pursuantto Form 10-K's GeneralInstruction (GeneralInstruction) G(3), the following infornation is included as an additionalitem in Part1:

Executive Officers of the Registrant Age at Executive Officer"') December 31,2005 Company Position John E. Bryson 62 Chairman of the Board Alan J. Fohrer 55 Chief Executive Officer and Director John R. Fielder 60 President Ronald L. Litzinger 46 Senior Vice President. Transmission and Distribution Thomas M. Noonan 54 Senior Vice President and Chief Financial Officer Stephen E. Pickett 55 Senior Vice President and General Counsel Pedro, J. Pizarro 40 Senior Vice President, Power Procurement Richard M. Rosenblum 55 Senior Vice President. Generation Mahvash Yazdi 54 Senior Vice President, Business Integration, and Chief Information Officer Lynd aL. Ziegler 53 Senior Vice President, Customer Service Frederick J. Grigsby, Jr. 58 Vice President. Human Resources and Labor Relations Linda G. Sullivan 42 Vice President and Controller

(°) 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.

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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, Edison International and/or the nonutility company affiliates of SCE for more than five years. Those officers who have not held their present position with SCE for the past five years had the following business experience during that period:

Executive Officer Company Position Effective Dates John E. Bryson Chairman of the Board, SCE January 2003 to present Chairman of the Board, President, and Chief Executive January 2000 to present Officer, Edison International Chairman of the Board, Edison Capital"' January 2000 to present Chairman of the Board, EME(2) January 2000 to December 2002 Alan J. Fohrer Chief Executive Officer and Director, SCE January 2003 to present Chairman of the Board and Chief Executive Officer, SCE January 2002 to December 2002 President and Chief Executive Officer, EME(2 ) January 2000 to December 2001 John R Fielder President, SCE October 2005 to present Senior Vice President, Regulatory Policy and Affairs, February 1998 to October 2005 SCE Ronald L. Litzinger Senior Vice President, Transmission and Distribution, May 2005 to present SCE Vice President, Strategic Planning, EIX May 2004 to April 2005 Senior. Vice President and Chief Technical Officer, EME January 2002 to April 2004 Senior Vice President, Worldwide Operations, EME June 1999 to December 2001 Thomas M. Noonan Senior Vice President and Chief Financial Officer, SCE June 2005 to present Vice President and Controller, Edison International and March 1999 to May 2005 SCE Stephen E. Pickett Senior Vice President and General Counsel, SCE January 2002 to present Vice President and General Counsel, SCE January 2000 to December 2001 Pedro J. Pizarro Senior Vice President, Power Procurement, SCE May 2005 to present Vice President, Power Procurement, SCE January 2004 to April 2005 Vice President, Strategy and Business Development, SCE July 2001 to December 2003 Vice President, Technology Business Development, September 2000 to June 2001 Edison International Richard M. Senior Vice President, Generation, and Chief Nuclear November 2005 to present Rosenblum Officer, SCE Senior Vice President, Generation, SCE September 2005 to November 2005 Senior Vice President, Transmission & Distribution February 1998 to September 2005 Mahvash Yazdi Senior Vice President, Business Integration, and Chief September 2003 to present Information Officer, Edison International and SCE Senior Vice President and Chief Information Officer, January 2000 to September 2003 SCE and Edison International Lynda L. Ziegler Senior Vice President, Customer Service, SCE March 2006 to present 18

Executive Officer Company Position Effective Dates Vice President, Customer Programs and Services May 2005 to February 2006 Division, SCE

__ _ Director, Customer Programs and Services Division. SCE January 1999 to April 21)05 Frederick J. Grigsby, Vice President, Human Resources, Edison International January 2004 to present Jr. and SCE Vice President, Human Resources and Labor Relations, July 2001 to December :2003 SCE Linda G. Sullivan Vice President and Controller, Edison International and June 2005 to present SCE Assistant Controller, Edison International May 2002 to May 2005 Assistant Controller, SCE March 2005 to May 2005 Manager, Controllers Department, Edison International September 1999 to April 2002 Controller, Edison Select(3) September 1999 to August 2001

") Ed son Capital is a subsidiary of Edison International and has investments worldwide in energy and infirastructure projects and affordable housing projects located throughout the United States.

(2) EIvIE is a subsidiary of Edison International and is an independent power producer engaged in the business of owning or leasing, operating and selling energy and capacity from electric power generation facilities.

(3) Edison Select was a nonutility subsidiary of Edison International that was engaged in the business of offering retail products and services. Edison Select was sold in August 2001.

PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Certain information responding to Item 5 with respect to frequency and amount of cash dividends is included in SCE's Annual Report to Shareholders for the year ended December 31, 2005 (Annual Report), under Quarterly Financial Data on page 80 and is incorporated herein by this reference. As a.

result cf the formation of a holding company described above in Item 1, all of the issued and outstanding common stock of SCE is owned by Edison International and there is no market for such stock.

Item 201 (d) of Regulation S-K, "Securities Authorized For Issuance Under Equity Compensation Plans,"

is not applicable because SCE has no compensation plans under which equity securities of SCE are authorized for issuance.

ITEM 6. SELECTED FINANCIAL DATA Information responding to Item 6 is included in the Annual Report under "Selected Financial and Operating Data: 2001-2005" on page 81, and is incorporated herein by this reference.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Information responding to Item 7 is included in the Annual Report on pages I through 34 and is incorporated herein by this reference.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information responding to Item 7A is included in the MD&A under "Market Risk Exposures" on pages 19 through 21.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Certain information responding to Item 8 is set forth after Item 15 in Part III. Other information responding to Item 8 is included in the Annual Report on pages 37 through 41 and is incorporated herein by this reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.

ITEM 9A. CONTROLS AND PROCEDURES 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 Securities Exchange Act of 1934, as amended (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 controls and procedures are effective.

Change in Internal Control Over Financial Reporting There were no changes in SCE's internal control over financial reporting (as such term is defined in Rules 13a-15(f) or 15d-15(f) under the Exchange Act) during the fiscal quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, SCE's internal control over financial reporting.

For the reasons discussed in Note 1 of the Notes to Consolidated Financial Statements, SCE has not designed, established, or maintained internal control over financial reporting for four variable interest entities, referred to as "VIEs," that SCE was required to consolidate under an accounting interpretation issued by the Financial Accounting Standards Board. SCE's evaluation of internal control over financial reporting did not include these VIEs.

ITEM 9B. OTHER INFORMATION None.

PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information concerning executive officers of SCE is set forth in Part I in accordance with General Instruction G(3), pursuant to Instruction 3 to Item 401(b) of Regulation S-K. Other information responding to Item 10 will appear in SCE's definitive Proxy Statement (Proxy Statement) to be filed with the SEC in connection with SCE's Annual Shareholders' Meeting to be held on April 27, 2006, under the headings "Election of Directors, Nominees for Election" and "Code of Business Conduct and Ethics," and 20

is inco porated herein by this reference. The SCE Board of Directors has determined that Thomas C.

Sutton. the Chair of the Board Audit Committee, is a financial expert under SEC Guidelines and is independent under the New York Stock Exchange listing standards.

ITEM 11. EXECUTIVE COMPENSATION Information responding to Item 11 will appear in the Proxy Statement under the headings "Director Compensation," "Executive Compensation:-Sumnmary Compensation Table, Option/SAR Grants in 2005, Aggregated Option/SAR Exercises in 2005 and FY-End Option/SAR Values, Long-Term Incentive Plan Awards in Last Fiscal Year, Pension Plan Table, Other Retirement Benefits, and Employment Contra-ts and Termination of Employment Arrangements," and "Compensation and Executive Personnel Committees' Interlocks and Insider Participation," and is incorporated herein by this reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information responding to Item 12 will appear in the Proxy Statement under the headings "Stock Owner.;hip of Directors, Director Nominee, and Executive Officers" and "Stock Ownership of Certain Shareholders," and is incorporated herein by this reference.

Item 201(d) of Regulation S-K, "Securities Authorized For Issuance Under Equity Compensation Plans,"

is not applicable because SCE has no compensation plans under which equity securities of SCE are authorized for issuance.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information responding to Item 13 will appear in the Proxy Statement under the headings "Certain Relationships and Transactions," and is incorporated herein by this reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES Information responding to Item 14 will appear in the Proxy Statement under the heading "Independent Registe red Public Accounting Firm Fees," and is incorporated herein by this reference.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a)(1) Financial Statements The following items contained in the Annual Report are found on pages 1 through 79, and are incorporated herein by this reference.

Management's Discussion and Analysis of Financial Condition and Results of Operations Report of Independent Registered Public Accounting Firm Consolidated Statements of Income - Years Ended December 31, 2005, 2004 and 2003 Consolidated Statements of Comprehensive Income - Years Ended December 31, 2005, 2004, and 2003 Consolidated Balance Sheets - December 31, 2005 and 2004 Consolidated Statements of Cash Flows - Years Ended December 31, 2005, 2004 and 2003 Consolidated Statements of Changes in Common Shareholders' Equity - Years Ended December 31, 2005, 2004 and 2003 Notes to Consolidated Financial Statements 21

(a)(2) Report of Independent Registered Public Accounting Firm and Schedules Supplementing Financial Statements The following documents may be found in this report at the indicated page numbers:

Page Report of Independent Registered Public Accounting Firm on Financial Statement Schedules 23 Schedule II - Valuation and Qualifying Accounts for the Year Ended December 31, 2005 24 Year Ended December 31, 2004 25 Year Ended December 31, 2003 26 Schedules I and III through V, inclusive, are omitted as not required or not applicable.

(a)(3) Exhibits See Exhibit Index beginning on page 28 of this report.

SCE will furnish a copy of any exhibit listed in the accompanying Exhibit Index upon written request and upon payment to SCE of its reasonable expenses of furnishing such exhibit, which shall be limited to photocopying charges and, if mailed to the requesting party, the cost of first-class postage.

22

PICME/ATERIOUSE(COPERs X PncewaterhouseCoopers LLP 350 South Grand Avenue Los Angeles CA 90071 Telephone (213) 356 6001)

Facsimile (813) 637 4444 Report of Independent Registered Public Accounting Firm on Financial Statement Schedules To the Board of Directors and Shareholder of Southern California Edison Company Our audits of the consolidated financial statements referred to in our report dated March 6, 2006, appearing in the 2005 Annual Report of Southern California Edison Company (which report anc. consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

Los Angeles, California March 6, 2006 23

Southern California Edison Company SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 2005 Additions Balance at Charged to Charged to Balance Beginning of Costs and Other at End Description Period Expenses Accounts Deductions of Period (In millions)

Uncollectible Accounts:

Customers $ 24.0 $ 8.4 $ - $ 10.5 $ 21.9 All other 6.9 8.4 - 4.5 10.8 Total $ 30.9 $ 16.8 $ - $ 15.0(a) $ 32.7 (a) Accounts written off, net.

24

Southern California Edison Company SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 2004 Additions Balance at Charged to Charged to Balance Beginning of Costs and Other at End Description Period Expenses Accounts Deductions of Period (In millions)

Uncoll.-ctible Accounts:

Customers $ 23.7 $ 16.7 $ - $ 16.4 $ 24.0 All other 6.6 3.3 - 3.0 6.9 Total $ 30.3 $ 20.0 $ - $ 19.4(a) $ 30.9 (a) Accounts written off, net.

25

Southern California Edison Company SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 2003 Additions Balance at Charged to Charged to Balance Beginning of Costs and Other at End Description Period Expenses Accounts Deductions of Period (In millions)

Uncollectible Accounts:

Customers $ 30.0 $ 19.2 $ - $ 25.5 $ 23.7 All other 6.1 4.6 - 4.1 6.6 Total $ 36.1 $ 23.8 $ - $ 29.6(a) $ 30.3 (a) Accounts written off, net.

26

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

SOUTHERN CALIFORNIA EDISON COMPANY By:

Linda 6'. Sullivan Vice President and jer Date: March 7, 2006 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

Signature Title Principal Executive Officer: Chief Executive Officer and Director Alan J. Fohrer*

Principal Financial Officer: Senior Vice President and Thomas M. Noonan* Chief Financial Officer Control er or Principal Accounting Officer: Vice President and Controller Linda G. Sullivan Board of Directors:

John E. Bryson* Director France A. C6rdova* Director Bradford M. Freeman* Director Bruce Karatz* Director Luis G. Nogales* Director Ronald L. Olson* Director James M. Rosser* Director Richard T. Schlosberg, III* Director Robert H. Smith* Director Thomas C. Sutton* Director

• By:

in a G. Sullivan Vice President and Controller Date: March 7,2006 27

EXHIBIT INDEX Exhibit Number Description 3.1 Certificate of Restated Articles of Incorporation of Southern California Edison Company, effective March 2, 2006 3.2 Amended Bylaws of Southern California Edison Company, as Adopted by the Board of Directors effective October 20, 2005 (File No. 1-2313, filed as Exhibit 3.1 to Southern California Edison Company's Form 8-K dated October 20, 2005, and filed October 26, 2005)*

4.1 Southern California Edison Company First Mortgage Bond Trust Indenture, dated as of October 1, 1923 (Registration No. 2-1369)*

4.2 Supplemental Indenture, dated as of March 1, 1927 (Registration No. 2-1369)*

4.3 Third Supplemental Indenture, dated as of June 24, 1935 (Registration No. 2-1602)*

4.4 Fourth Supplemental Indenture, dated as of September 1, 1935 (Registration No.

2-4522)*

4.5 Fifth Supplemental Indenture, dated as of August 15, 1939 (Registration No.

2-4522)*

4.6 Sixth Supplemental Indenture, dated as of September 1, 1940 (Registration No.

2-4522)*

4.7 Eighth Supplemental Indenture, dated as of August 15, 1948 (Registration No.

2-761 0)*

4.8 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964 (Registration No. 2-22056)*

4.9 Eighty-Eighth Supplemental Indenture, dated as of July 15, 1992 (File No. 1-2313, Form 8-K dated July 22, 1992)*

4.10 Indenture, dated as of January 15, 1993 (File No. 1-2313, Form 8-K dated January 28, 1993)*

10.1** Form of 1981 Deferred Compensation Agreement (File No. 1-2313, filed as Exhibit 10.2 to Southern California Edison Company's Form 10-K for the year ended December 31, 1981)*

10.2** Form of 1985 Deferred Compensation Agreement for Executives (File No. 1-2313, filed as Exhibit 10.3 to Southern California Edison Company's Form 10-K for the year ended December 31, 1985)*

10.3** Form of 1985 Deferred Compensation Agreement for Directors (File No. 1-2313, filed as Exhibit 10.4 to Southern California Edison Company's Form 10-K for the year ended December 31, 1985)*

10.4** Director Deferred Compensation Plan as restated May 14, 2002 (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2002)*

10.4.1** Director Deferred Compensation Plan Amendment No. 1,effective January 1, 2003 (File No. 1-9936, filed as Exhibit 10.4.1 to Edison International's Form 10-K for the year ended December 31, 2002)*

10.5** Director Grantor Trust Agreement, dated August 1995 (File No. 1-9936, filed as Exhibit 10.10 to Edison International's Form 10-K for the year ended December 31, 1995)*

10.5.1** Director Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002 (File No. 1-9936, filed as Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 2002)*

10.(,** Executive Deferred Compensation Plan, as amended and restated January 1, 1998 (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form I 0-Q for the quarter ended March 31, 1998)*

10.6.1*.* Executive Deferred Compensation Plan Amendment No. 1, effective January 1, 2003 (File No. 1-9936, filed as Exhibit 10.6.1 to Edison International's Form I0-K for the year ended December 31, 2002)*

10.7 ** Executive Grantor Trust Agreement, dated August 1995 (File No. 1-9936, filed as Exhibit 10.12 to Edison International's Form 10-K for the year ended December 31, 1995)*

10.7.1** Executive Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002 (File No. 1-9936, filed as Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended June 30, 2002)*

10.8** Executive Supplemental Benefit Program, as amended January 30, 1990 (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended September 30, 1999)*

10.9** Dispute resolution amendment, adopted November 30, 1989 of 1981 Executive Deferred Compensation Plan and 1985 Executive and Director Deferred Compensation Plans (File No. 1-9936, filed as Exhibit 10.21 to Edison International's Form 10-K for the year ended December 31, 1998)*

10.10** Executive Retirement Plan as restated effective April 1, 1999 (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended September 30, 1999)*

10.10.1** Executive Retirement Plan Amendment 2001-1, effective March 12, 2001 (File No.

1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2001)*

10.10.2** Executive Retirement Plan Amendment 2002-1, effective January 1, 2003 (File No.

1-9936, filed as Exhibit 10.10.2 to Edison International's Form 10-K for the year ended December 31, 2002)*

10.11** Executive Incentive Compensation Plan, effective January 1, 1997 (File No. 1-9936, filed as Exhibit 10.12 to Edison International's Form 10-K for the year ended December 31, 1997)*

10.12** Executive Disability and Survivor Benefit Program, effective January 1, 1994 (File No. 1-9936, filed as Exhibit 10.22 to Edison International's Form 10-K for the year ended December 31, 1994)*

10.13** Retirement Plan for Directors, as amended February 19, 1998 (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form I0-Q for the quarter ended June 30, 1998)*

10.14** Officer Long-Term Incentive Compensation Plan as amended January 1, 1998 (File No. 1-9936, filed as Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended March 31, 1998)*

10.1.5** Equity Compensation Plan as restated effective January 1, 1998 (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 1998)*

10.1:5.1** Equity Compensation Plan Amendment No. 1, effective May 18, 2000 (File No. 1-9936, filed as Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 2000)*

10.165** 2000 Equity Plan, effective May 18, 2000 (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2000)*

10.17** Terms and conditions for 1996 long-term compensation awards under the Officer Long-Term Incentive Compensation Plan (File No. 1-9936, filed as Exhibit 10.16.2 to Edison International's Form 10-K for the year ended December 31, 1996)*

10.18** Terms and conditions for 1997 long-term compensation awards under the Officer Long-Term Incentive Compensation Plan (File No. 1-9936, filed as Exhibit 10.16.3 to Edison International's Form 10-K for the year ended December 31, 1997)*

10.19** Terms and conditions for 1998 long-term compensation awards under the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 1998)*

10.20** Terms and conditions for 1999 long-term compensation awards under the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 1O-Q for the quarter ended March 31, 1999)*

10.21** Terms and conditions for 2000 basic long-term incentive compensation awards under the Equity Compensation Plan, as restated (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 2000)*

10.22** Terms and conditions for 2000 special stock option awards under the Equity Compensation Plan and 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended June 30, 2000)*

10.23** Terms and conditions for 2001 retention incentives under the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.5 to Edison International's Form 10-Q for the quarter ended March 31, 2001)*

10.24** Terms and conditions for 2001 exchange offer deferred stock units under the Equity Compensation Plan (File No. 1-9936, filed as Attachment C of Exhibit (a)(1) to Edison International's Schedule TO-I dated October 26, 2001)*

10.25** Terms and conditions for 2002 long-term compensation awards under the Equity Compensation Plan and 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2002)*

10.26** Terms and conditions for 2003 long-term compensation awards under the Equity Compensation Plan and 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2003)*

10.27** Terms and conditions for 2004 long-term compensation awards under the Equity Compensation Plan and 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form I 0-Q for the quarter ended March 31, 2004)*

10.28** Terms and conditions for 2005 long-term compensation award under the Equity Compensation Plan and 2000 Equity Plan (File No. 1-9936, filed as Exhibit 99.2 to Edison International's Form 8-K dated December 16, 2004 and filed on December 22, 2004)*

10.29** Terms and conditions for 2006 long-term compensation awards under the Equity Compensation Plan and 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.29 to Edison International's Form 10-K for the year ended December 31, 2005)*

10.30** Director Nonqualified Stock Option Terms and Conditions under the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2002)*

10.31** Director 2004 Nonqualified Stock Option Terms and Conditions under the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2004.)*

10.32** Estate and Financial Planning Program as amended April 23, 1999 (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended June 30, 1999)*

10.33** Option Gain Deferral Plan as restated September 15, 2000 (File No. 1-9936, filed as Exhibit 10.25 to Edison International's Form 10-K for the year ended December 31, 2000)*

10.34** Resolution regarding the computation of disability and survivor benefits prior to age 55 for Alan J. Fohrer dated February 17, 2000 (File No. 1-9936, filed as Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 2000)*

10.35** Executive Severance Plan as adopted effective January 1, 2001 (File No. 1-9936, filed as Exhibit 10.34 to Edison International's Form 10-K for the year ended December 31, 2001)*

10.35** Amendment to 1985 Deferred Compensation Plan Agreement for Executives and Deferred Compensation Plan Deferred Compensation Agreement with John E.

Bryson, dated December 31, 2003 (File No. 1-2313, filed as Exhibit 10.34 to Southern California Edison Company's Form 10-K for the year ended December 31, 2003)*

10.3 7** Agreement between Edison International and Southern California Edison Company, dated December 31, 2003, addressing responsibility for the prospective costs of participation of John E. Bryson under the 1985 Deferred Compensation Plan Agreement for Executives, dated September 27, 1985, as amended, and the Deferred Compensation Plan Deferred Compensation Agreement, dated November 28, 1984, as amended (File No. 1-2313, filed as Exhibit 10.35 to Southern California Edison Company's Form 10-K for the year ended December 31, 2003)*

10.3,3** Amendment to 1985 Deferred Compensation Plan Agreement for Directors with James M. Rosser, dated December 31, 2003 (File No. 1-2313, filed as Exhibit 10.36 to Southern California Edison Company's Form 10-K for the year ended December 31, 2003)*

10.3'?** Amendment to 1985 Deferred Compensation Plan Agreement for Executives and Deferred Compensation Plan Deferred Compensation Agreement with Harold B. Ray dated December 31, 2003 (File No. 1-2313, filed as Exhibit 10.37 to SCE Form 10-K for the year ended December 31, 2003)*

10.40** Edison International Director Compensation Schedule, adopted May 19, 2005, as amended (File No. 1-9936, filed as Exhibit 10.48 to Edison International's Form 10-K for the year ended December 31, 2005)*

10.41** Edison International Director Nonqualified Stock Options 2005 Terms and Conditions (File No. 1-9936, filed as Exhibit 99.3 to Edison International's Form 8-K dated May 19, 2005, and filed on May 25, 2005)*

10.42* Retirement Agreement, dated as of August 25, 2005, between Southern California Edison Company and Robert Foster (File No. 1-2313, filed as Exhibit 10.1 to Southern California Edison Company's Form 8-K dated August 25, 2005 and filed on August 26, 2005)*

10.43** Consulting Agreement, dated as of August 25, 2005, between Southern California Edison Company and Robert Foster (File No. 1-2313, filed as Exhibit 10.2 to Southern California Edison Company's Form 8-K dated August 25, 2005, and filed on August 26, 2005)*

10.44" Legal Fees Reimbursement, dated September 2005 between Southern California Edison Company and Robert Foster (File No. 1-2313, filed as Exhibit 10.3 to Southern California Edison Company's Form 10-Q for the quarter ended September 30, 2005)*

10.45** Edison International Director Nonqualified Stock Options 2005 Terms and Conditions (File No. 1-2313, filed as Exhibit 99.3 to Edison International's Form 8-K dated May 19, 2005, and filed on May 25, 2005)*

10.465** Consulting Agreement, dated as of December 14, 2005, between Southern California Edison Company and Harold B. Ray (File No. 1-2313, filed as Exhibit 10.2 to Southern California Edison Company's Form 8-K dated December 15, 2005, and filed on December 21, 2005)*

10.47** Director Deferred Compensation Plan Authorization of Edison International and Southern California Edison Company (File No. 1-2313, to Southern California Edison Company's Form 8-K dated December 30, 2004, and filed on January 5, 2005)*

10.48** Form of Indemnity Agreement between Southern California Edison Company and its Directors and any officer, employee or other agent designated by the Board of Directors (File No. 1-2313, filed as Exhibit 10.5 to Southern California Edison Company's Form 10-Q for the period ended June 30, 2005, and filed on August 9, 2005)*

10.49** Edison International Executive Perquisites (File No. 1-9936, filed as Exhibit 10.56 to Edison International's Form 10-K for the year ended December 31, 2005)*

10.50** Deferred Compensation Program Amendments (File No. 1-9936, filed as Exhibit 10.55 to Edison International's Form 10-K for the year ended December 31, 2005)*

10.51 ** Southern California Edison Company Named Executive Officer Base Salaries for 2006 10.52.1 Amended and Restated Agreement for the Allocation of Income Tax Liabilities and Benefits among Edison International, Southern California Edison Company and The Mission Group dated September 10, 1996 (File No. 1-9936, filed as Exhibit 10.3 to Edison International's Form I0-Q for the quarterrended September 30, 2002)*

10.52.2 Administrative Agreement re Tax Allocation Payments among Edison International, Southern California Edison Company, The Mission Group, Edison Capital, Mission Energy Holding Company, Edison Mission Energy, Edison O&M Services, Edison Enterprises, and Mission Land Company dated July 2, 2001 (File No. 1-9936, filed as Exhibit 10.3.4 to Edison International's Form I0-Q for the quarter ended September 30, 2002)*

10.53 Amended and Restated Credit Agreement, dated December 15, 2005 among Southern California Edison Company and JPMorgan Chase Bank, N.A., as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, and Credit Suisse First Boston, Lehman Commercial Paper, Inc., and Wells Fargo Bank, N.A., as Documentation Agents (File No. 1-2313, to Southern California Edison Company's Form 8-K dated December 15, 2006 and filed on December 21, 2005)*

12 Computation of Ratios of Earnings to Fixed Charges 13 Selected portions of the Annual Report to Shareholders for year ended December 31, 2005 23 Consent of Independent Registered Public Accounting Firm -

PricewaterhouseCoopers LLP 24.1 Power of Attorney 24.2 Certified copy of Resolution of Board of Directors Authorizing Signature 31.1 Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act 31.2 Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act 32 Statement Pursuant to 18 U.S.C. Section 1350

• Incorporated by reference pursuant to Rule 12b-32.

• • Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)3.