SOUTHRN CALIFORNIA EDISON COMPANY LOGO



                                                                           2004  Annual Report








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



       Contents

 1        Management's Discussion and Analysis of Financial Condition and Results of Operations
44        Report of Independent Registered Public Accounting Firm
45        Consolidated Statements of Income
45        Consolidated Statements of Comprehensive Income
46        Consolidated Balance Sheets
48        Consolidated Statements of Cash Flows
49        Consolidated Statements of Changes in Common Shareholder's Equity
50        Notes to Consolidated Financial Statements
92        Quarterly Financial Data
93        Selected Financial and Operating Data:  2000-2004




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

This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) contains
forward-looking statements.  These statements are based on Southern California Edison's (SCE) knowledge of
present facts, current expectations about future events and assumptions about future developments.
Forward-looking statements are not guarantees of performance; they are subject to risks and uncertainties that
could cause actual future outcomes and results of operations to be materially different from those set forth in
this discussion.  Important factors that could cause actual results to differ are discussed throughout this MD&A,
including in the management overview and the discussions of liquidity and market risk exposures.

The MD&A is presented in 11 major sections.  The MD&A begins with (1) a management overview, which includes a
description of how SCE earns revenue and income and a brief review of the company's consolidated earnings for
2004, and a summary of issues for 2004 and 2005.  The remaining sections of the MD&A include:  (2) Liquidity; (3)
Market Risk Exposures; (4) Regulatory Matters; (5) Other Developments; (6) Results of Operations and Historical
Cash Flow Analysis; (7) Dispositions and Discontinued Operations; (8) Acquisition; (9) Critical Accounting
Policies and Estimates; (10) New Accounting Principles; and (11) Commitments.

MANAGEMENT OVERVIEW

Background

SCE is an investor-owned utility company providing electricity to retail customers in central, coastal and
southern California.  SCE is regulated by the California Public Utilities Commission (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 two groups: base rates and cost-recovery rates.

Base Rates:  Revenue arising from base rates is designed to provide SCE a reasonable opportunity to recover its
costs and earn an authorized return on the net book value of SCE's 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.
Base rates related to SCE's generation and distribution functions are authorized by the CPUC through a general
rate case (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
"Regulatory Matters--Transmission and Distribution--2003 General Rate Case Proceeding" 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 costs, other than cost-recovery
costs (see below), do impact profitability.


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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 stock.

Current CPUC ratemaking also provides for performance incentives or penalties for differences between actual
results and GRC-determined standards of reliability and employee safety.

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 decision is subject to refund.  SCE's current
authorized annual revenue requirement of approximately $260 million recovers the costs associated with its
transmission function and earns a reasonable return on its $1.1 billion transmission rate base.

Cost-Recovery Rates:  Revenue requirements to recover SCE's costs of fuel, purchased power, demand-side
management programs, nuclear decommissioning costs, 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 50% 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 in these
categories in future proceedings, under- or over-collections in these balancing accounts can build rapidly due to
fluctuating prices (particularly in power procurement) and can greatly impact cash flows.  Rates are adjusted, as
necessary, 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.

As described below under "Regulatory Matters--Generation and Power Procurement--CDWR Power Purchases and Revenue
Requirement Proceedings," the California Department of Water Resources (CDWR) began purchasing power on behalf of
utility customers in 2001, during the California energy crisis.  In addition to billing its customers for SCE's
power procurement activities, SCE also bills and collects from its customers for power purchased and sold by the
CDWR, CDWR bond-related charges and direct access exit fees.  These amounts are remitted to the CDWR as they are
collected and are not recognized as revenue by SCE.  As a result, these transactions should have no impact on
SCE's earnings.

For a discussion of important issues related to the rate-making process, see the "Regulatory Matters" section.

SCE's 2004 Consolidated Earnings

SCE's recorded earnings were $915 million in 2004, compared to $922 million in 2003.  The decrease in earnings
was primarily due to a decrease in operating earnings reflecting the expiration of SCE's performance incentive
mechanisms for San Onofre Nuclear Generating Station (San Onofre), partially offset by higher revenue net of
operating expenses and the net benefits from the resolution of several regulatory and prior years' tax issues.
For a detailed review and analysis of the consolidated results of operations and historical cash flows, see
"Results of Operations and Historical Cash Flow Analysis" section.

SCE 2004 Issues - Overview

In 2004, SCE's primary management focus was on numerous business issues that could have materially affected SCE's
earnings, cash flow, or business risk.  The following is a brief review of SCE's performance on its 2004 key
business issues.


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o    In July 2004, the CPUC issued a final decision in SCE's 2003 GRC, authorizing an annual increase of $73
     million in base rates and providing for base rate adjustments in 2004 and 2005.  The CPUC's decision is
     retroactive to May 22, 2003.  In the decision, the CPUC approved nearly all of SCE's requested capital
     spending.  Moreover, the CPUC adopted a mechanism to adjust base rates based on SCE's forecast of capital
     expenditures and operating and maintenance escalation for 2004 and 2005.

o    All of SCE's major business functions (distribution, transmission and generation) had significant
     demands for capital investment.  During 2004, SCE's new account additions totaled 68,400.  In 2004, SCE
     spent approximately $2.0 billion in capital expenditures, including $285 million related to the acquisition
     of the Mountainview project.  At year-end 2004, SCE's rate base was $9.4 billion.  With the 2003 GRC
     decision, SCE substantially increased the replacement of distribution poles, transformers and other
     infrastructure during 2004.  This is part of a long-term effort known as the Infrastructure Replacement
     Program, which is designed to step up the level of infrastructure replacement to maintain existing levels of
     system reliability.  A significant portion of SCE's existing distribution infrastructure was installed
     during the post-World War II population boom.

o    During 2004, SCE took major steps in implementation of its transmission expansion plans to meet customer
     load-growth requirements, including:

     o        Completed the reconstruction of the Sylmar Converter Station.  This $120 million project (SCE's share is
              $60 million), allows 3,100 megawatt (MW) of power to flow to southern California;

     o        Obtained regulatory approval to spend $125 million to upgrade SCE's Devers/Palo Verde 1 transmission
              line.  This project will add 505 MW by 2006;

     o        Filed an application with the California Independent System Operator (ISO) for approval to construct the
              $680 million Devers/Palo Verde 2 transmission line.  This application was approved on February 24,
              2005.  If approved by other regulatory agencies, the line would add 1,200 MW of power to southern
              California by 2009;

     o        Filed an application with the CPUC to construct the $224 million Antelope Area Transmission project.
              This project will expand SCE's transmission system, allowing additional suppliers of wind energy
              from the Tehachapi wind region (near Mohave, California).

o    Generation capital spending increased dramatically in 2004.  SCE made significant progress in the
     construction of the 1,054 MW Mountainview project.  At year-end 2004, the project was about 50% completed
     and was on schedule to complete construction by the end of the first quarter 2006.  At SCE's San Onofre
     site, security upgrades driven by the Nuclear Regulatory Commission required $54 million of capital
     spending, slightly above what had been budgeted for 2004.  Also during 2004, San Onofre Unit 3 experienced
     an extended outage due to the replacement of the pressurizer heater sleeves as a result of degradation.
     This outage reduced the 2004 capacity factor of Unit 3 to 74%.

o    In February 2004, SCE filed an application with the CPUC to replace the San Onofre steam generators and
     to adopt the estimated reasonable replacement cost of $510 million (SCE's share).  In September 2004, SCE
     signed a contract for the fabrication of new steam generators.  See "Regulatory Matters--Generation and Power
     Procurement--San Onofre Nuclear Generating Station."


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o    During 2004, SCE and its co-owners of the Mohave Generating Station (Mohave), a 1,580 MW coal-fired
     plant (SCE has a 56% ownership), continued negotiations to find a reasonable path to continue Mohave
     operations beyond 2005.  Under the terms of a consent decree, the Mohave owners must install certain
     pollution-control equipment in order to operate beyond 2005.  Before the investment can be evaluated by the
     co-owners, future coal and water supply issues must be resolved.  See "Regulatory Matters--Generation and
     Power Procurement--Mohave Generating Station and Related Proceedings."

o    SCE has numerous concerns associated with providing power for its bundled service customers.  As
     discussed in the "--Background" section, SCE recovers only reasonable costs associated with procuring power
     for its customers, with no markup or profit.  Because of the substantial costs associated with power
     procurement, SCE spends considerable management focus to ensure that both customer and shareholder risks are
     reasonably protected.  During 2004, SCE supported Assembly Bill 2006, which would have created a fairer and
     more durable regulatory framework associated with generation investments and purchased-power costs.
     Although the bill was passed by the State Legislature, it was vetoed by the Governor of California.
     However, in the CPUC's decisions affecting power procurement, meaningful progress was made towards a fairer
     regulatory framework supporting power procurement.  In particular, the CPUC:

     o        recognized the financial implications of debt equivalence (the fixed financial obligations resulting
              from long-term power-purchase contracts) when evaluating competitive bids on power-purchase
              contracts, and also provided a mechanism to begin mitigating its impact;

     o        extended the power procurement trigger mechanism, allowing for adjustment in procurement rates should
              currently authorized rates cause revenue to exceed or under run actual costs by 5% of SCE prior
              year's procurement costs (see "Market Risk Exposures--Commodity Price Risk"); and

     o        provided stranded cost recovery for long-term power procurement arrangements.

o    SCE has identified that resource adequacy requirements, anticipated closure of Mohave at the end of
     2005, reduction in deliveries of CDWR allocated-contract power, expiration of qualifying facilities (QF)
     contracts, and peak-load growth of 1.5% to 2% per year would require SCE to seek substantial amounts of
     incremental capacity.  During 2004, SCE conducted a number of competitive solicitations to meet its resource
     requirements, as specified by regulatory rules.  Based on the results of SCE's 2004 solicitations, SCE
     expects to meet its 2005 requirements and has significantly reduced its estimate of the amount of resources
     needed to meet the requirements for 2006 and 2007.  SCE also is seeking additional suppliers of renewable
     power to attain CPUC-mandated levels.  At year-end 2004, SCE obtained approximately 18% of its power
     supplies from renewable resources.  SCE must achieve 20% by 2010, or could be subject to penalties.

o    During 2004, SCE remained concerned about high customer rates, which were a contributing factor that led
     to the deregulation of the electric services industry during the mid-1990s.  At the beginning of 2004, SCE's
     system average rate for bundled service customers was 12.5(cent)-per-kilowatt-hour (kWh).  As of December 31
     2004, that rate was 12.2(cent)-per-kWh.  On April 14, 2005, SCE expects to implement new rates that will result in
     a system average of 13.0(cent)-per-kWh.  The expected rate increase is due to higher gas prices and increased
     power purchases resulting from resource adequacy requirements and a reduction in CDWR power deliveries.  On
     a cents-per-kWh basis, SCE's average rate is above the national average, but similar to other investor-owned
     electric utilities in California.


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o    During 2004, a new issue emerged that affected SCE's performance.  SCE found that a number of employees
     had falsified customer data which was reported to the CPUC in support of certain performance incentive
     rewards.  Upon further investigation, SCE also discovered that it had not appropriately collected or
     maintained data on employee safety which is also tied to a CPUC performance incentive reward.  SCE reported
     its findings to the CPUC, terminated and disciplined certain employees, and committed to the CPUC to either
     refund or not seek any performance incentives in the affected areas.  SCE recorded a $29 million pre-tax
     earnings charge in 2004 to account for the anticipated refund of the previously received performance
     incentive rewards.  SCE is committed to implementing programs that greatly strengthen the ethics and
     compliance programs and culture at SCE.

SCE 2005 Issues - Overview

This overview discusses key business issues facing SCE in 2005.  It is not intended to be an exhaustive
discussion, but a summary of current or developing corporate issues.  It includes items that could materially
affect SCE's earnings, cash flow, or business risk.  The issues discussed in this overview are described in more
detail in the remainder of this "Southern California Edison Company" section.

In October 2004, Edison International adopted a comprehensive multi-year strategic plan.  For the remaining
years, 2005-2009, the plan provides for SCE to incur $9.4 billion in capital expenditures which would increase
SCE's rate base from $9.4 billion at year-end 2004 to $14.2 billion by year-end 2009.  To achieve this projected
growth, SCE must have all regulatory approvals to spend the forecasted capital, and the people, processes, and
systems to implement the authorized capital expenditures.  Pursuant to the plan, SCE expects to spend $1.6
billion on capital projects in 2005 and expects to have a rate base of $10.2 billion at year-end 2005.  Through
the 2003 GRC decision, ratemaking for SCE's 2005 capital expenditures already is in place.  Significant
investments in 2005 are expected to include:

o    $200 million related to transmission projects.

o    $1.1 billion related to distribution projects.

o    $300 million related to generation projects, including the completion of the construction of the
     Mountainview project.

In order to achieve this growth for 2005 and beyond, SCE needs to make meaningful progress on several
transmission projects including:

o    Devers/Palo Verde 1 transmission line upgrades.

o    Rancho Vista Substation, Devers/Palo Verde 2 transmission line, and Antelope Transmission project, all
     of which were approved by the ISO in 2005.  The CPUC approval process must now be initiated.

2005 is an important year for several generation projects.  The Mountainview project will be substantially
completed in 2005, with an anticipated in-service date during the first quarter of 2006.  During 2005, the CPUC
is expected to render a final decision on SCE's San Onofre steam generator replacement application.  In addition,
future ownership of San Onofre is affected by co-owners opting out of steam generator investments.  This could
result in SCE assuming a greater financial responsibility for steam generator replacement and increased ownership
interest.  See "Regulatory Matters--Generation and Power Procurement--San Onofre Nuclear Generating Station." The
future of Mohave still remains uncertain.  SCE will continue to seek a solution permitting extension of Mohave's
operation beyond 2005 on commercially reasonable terms, or provide for its permanent shutdown.  A commitment to


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extend Mohave's operation and the possible $1.1 billion capital expenditures (SCE's share is $605 million), is
not included in SCE's capital forecast.  See "Regulatory Matters--Generation and Power Procurement--Mohave
Generating Station and Related Proceedings."

In December 2004, SCE filed an application with the CPUC for its 2006 GRC.  The application requests the CPUC to
increase base rates by $370 million, primarily for capital-related expenditures to accommodate customer and load
growth and substantially higher operation and maintenance expenditures particularly in SCE's transmission and
distribution business unit.  The application also seeks base rate increases for 2007 and 2008, permitting
escalation for operating expenditures and planned capital expenditures.  If the schedule is maintained, a final
decision is expected at year-end 2005.  See "Regulatory Matters--Transmission and Distribution--2006 General Rate
Case Proceeding."  Adoption of the capital forecast incorporated in SCE's 2006 GRC is essential to meeting the
targets incorporated in SCE's strategic plan.

In 2004, SCE commenced a broad initiative to redesign key work processes associated with capital expenditures
within the transmission and distribution business unit.  The initiative, known as business process integration,
is designed to modify existing work processes which focus on individual business units and replace them with
integrated work processes spanning the entire utility.  This initiative should produce efficiency of business
systems, reduction of capital requirements and streamlined business processes.  SCE has incorporated expected
savings from business process integration in its 2006 GRC forecast.

In 2005, SCE will continue to focus on meeting the CPUC's new minimum planning reserve margin of 15-17% above its
average-year peak load.  In January 2004, the CPUC adopted this minimum planning reserve margin for all
load-serving entities, including SCE, which supplies power to about 85% of the retail load served by its
transmission and distribution system.  In October 2004, the CPUC accelerated the effective date for the minimum
planning reserve margin from 2008 to 2006.  SCE has met the minimum planning reserve margin for 2005.  However,
as power-purchase contracts expire, generating plants retire, and load grows, SCE anticipates the need to sign
additional power-purchase contracts in the years ahead to meet the minimum planning reserve requirement beyond
2005.  The ISO, CPUC and the California Energy Commission have identified SCE's service territory as an area in
which new generation will soon be needed.  SCE will continue to advocate to State officials the need for a market
and regulatory framework that will support developers' efforts to obtain financing for new generation projects.
Over time, a robust resource adequacy framework implemented through stable capacity markets may achieve this
goal; in the interim, developers may not be able to obtain financing without long-term contracts with
creditworthy load-serving entities.  Long-term contracts with new generators are likely to be more costly than
short-term contracts with existing generators.  However, load-serving entities are not in a position to sign
these more costly, long-term contracts for new generation in an environment in which their retail customers can
elect another service provider.  SCE will continue working with State officials to find transitional and
long-term solutions to this fundamental problem that treat all load-serving entities equitably and are workable
even if the State expands competitive retail markets.

LIQUIDITY

SCE's liquidity is primarily affected by under- or over-collections of procurement-related costs, collateral and
mark-to-market requirements associated with power-purchase contracts, and access to capital markets or external
financings.  At December 31, 2004, SCE's credit and long-term senior secured issuer ratings from Standard &
Poor's and Moody's Investors Service were BBB and A3, respectively.  On February 16, 2005, Standard & Poor's
raised SCE senior secured credit rating to BBB+ from BBB.  On September 17, 2004, Moody's Investors Service
assigned SCE a short-term credit rating of P2 in connection with SCE's launch of a new $700 million commercial
paper program.


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Standard & Poor's had previously issued SCE a short-term credit rating of A2.  As of December 31, 2004, SCE had $88 million
in commercial paper outstanding.

As of December 31, 2004, SCE had cash and equivalents of $122 million ($90 million relates to cash held by SCE's
consolidated Variable Interest Entities (VIEs)).  As of December 31, 2004, long-term debt, including current
maturities of long-term debt, was $5.5 billion.  As of December 31, 2004, SCE posted approximately $75 million
($65 million in cash and $10 million in letters of credit) as collateral to secure its obligations under
power-purchase contracts and to transact through the ISO for imbalance energy.  SCE's collateral requirements can
vary depending upon the level of unsecured credit extended by counterparties, the ISO's credit requirements,
changes in market prices relative to contractual commitments, and other factors.  At December 31, 2004, SCE had a
$700 million senior secured credit facility with an expiration date of December 2006.  The credit facility was
not utilized, except for $98 million supporting the commercial paper outstanding and the letters of credit as
mentioned above.  Subsequently, in February 2005, the $700 million credit facility was replaced with a $1.25
billion senior secured 5-year revolving credit facility.  As of February 28, 2005, SCE's new credit facility
supported $306 million of commercial paper outstanding and $10 million in letters of credit, leaving $934 million
available under its credit facility.

SCE's 2005 estimated cash outflows consist of:

o    Approximately $246 million of rate reduction notes that are due at various times in 2005, but which have
     a separate cost recovery mechanism approved by state legislation and CPUC decisions;

o    Projected capital expenditures primarily to replace and expand distribution and transmission
     infrastructure and construct and replace generation assets;

o    Dividend payments to SCE's parent company;

o    Fuel and procurement-related costs; and

o    General operating expenses.

SCE expects to meet its continuing obligations, including cash outflows for power-procurement undercollections
(if incurred), through cash and equivalents on hand, operating cash flows and short-term borrowings, when
necessary.  Projected capital expenditures are expected to be financed through cash flows and the issuance of
long-term debt and preferred stock.

In December 1997, $2.5 billion of rate reduction 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 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 or Edison International.  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


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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.

SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its
distribution and transmission infrastructure and construct and replace generation assets.  In 2004, SCE spent
$2.0 billion, including the acquisition and construction of the Mountainview project.  SCE expects its capital
expenditures to be $1.6 billion, $1.8 billion and $1.9 billion in 2005, 2006 and 2007, respectively.  In the 2003
GRC the CPUC approved nearly all of SCE's requested capital spending for the 2003 through 2005 period.  SCE is
seeking regulatory approval, in its 2006 GRC, to continue its infrastructure program for the 2006 through 2009
period.

The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International (see "Edison
International (Parent):  Liquidity" for further discussion).  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 a 13-month weighted-average calculation.  At
December 31, 2004, SCE's 13-month weighted-average common equity component of total capitalization was 50.5%.  At
December 31, 2004, SCE had the capacity to pay $222 million in additional dividends based on the 13-month
weighted-average method.  Based on recorded December 31, 2004 balances, SCE's common equity to total
capitalization ratio, for rate-making purposes, was 50.4%.  SCE had the capacity to pay $213 million of
additional dividends to Edison International based on December 31, 2004 recorded balances.  The CPUC has
authorized SCE to increase the amount of preferred stock in its authorized capital structure from 5% to 9% of
total capitalization.  Correspondingly, SCE will use the proceeds to fund capital expenditures.  The exact amount
and timing of such issuances is dependent upon many factors, including market conditions.

In January 2005, SCE issued $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 8% first and refunding mortgage bonds due February 2007 (Series 2003A) and $650 million
of the $966 million 8% first and refunding mortgage bonds due February 2007 (Series 2003B).

SCE has debt covenants that require certain interest coverage, interest and preferred dividend coverage, and debt
to total capitalization ratios to be met.  At December 31, 2004, SCE was in compliance with these debt covenants.

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

MARKET RISK EXPOSURES

SCE's primary market risks include fluctuations in interest rates, commodity prices and volume, and counterparty
credit.  Fluctuations in interest rates can affect earnings and cash flows.  However, fluctuations in commodity
prices and volumes and counterparty credit losses temporarily affect cash flows, but should not affect earnings
due to recovery through regulatory mechanisms.  SCE uses derivative financial instruments to manage its market
risks, but prohibits the use of these instruments for speculative purposes.

Interest Rate Risk

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used
for liquidity purposes and to fund business operations, as well as 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


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future business requirements, market conditions and other factors.  In addition, SCE's authorized return on
common equity (11.6% for 2004 and 11.4% for 2005), 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, 2004, SCE did not believe that its short-term debt and current portion of long-term debt and
preferred stock was subject to interest rate risk, due to the fair market value being approximately equal to the
carrying value.

At December 31, 2004, the fair market value of SCE's long-term debt was $5.6 billion.  A 10% increase in market
interest rates would have resulted in a $186 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 $206 million increase in the fair market value
of SCE's long-term debt.  At December 31, 2004, the fair market value of SCE's preferred stock subject to
mandatory redemption was $140 million.  A 10% increase and decrease in market interest rates would have resulted
in a $2 million decrease and increase, respectively, in the fair market value of SCE's preferred stock subject to
mandatory redemption.

Commodity Price Risk

In 2004, SCE's purchased-power expense was approximately 36% of SCE's total operating expenses.  SCE recovers its
reasonable power procurement costs through regulatory mechanisms established by the CPUC.  The California Public
Utilities Code provides that the CPUC shall adjust rates, or order refunds, to amortize undercollections or
overcollections of power procurement costs.  Under a trigger mechanism, the CPUC must adjust rates if the
undercollection or overcollection exceeds 5% of SCE's prior year's procurement costs, excluding revenue collected
for the CDWR.  The CPUC issued a decision on December 16, 2004, that keeps the trigger mechanism in effect during
the term of long-term contracts, or 10 years, whichever is longer.  As a result of these regulatory mechanisms,
changes in energy prices may impact SCE's cash flows but should have no impact on earnings.

On January 1, 2003, SCE resumed power procurement responsibilities for its customers.  SCE forecasts that it will
have a net-long position (generation supply exceeds expected load requirements) in the majority of hours during
2005.  SCE's net-long position arises primarily from "must-take" deliveries under CDWR contracts allocated to
SCE's customers.  SCE has incorporated a 2005 price and volume forecast from expected sales of net-long power in
its 2005 revenue forecast used for setting rates.  If actual prices or volumes vary from forecast, SCE's cash
flow would be temporarily impacted, but should not affect earnings.  For 2006, SCE forecasts that it will have a
net-short position (expected load requirements exceed generation supply) at certain times.  SCE's forecast
net-short position increases from year-to-year, assuming no new generation supply is added, as existing contracts
expire, SCE generating plants retire, and load grows.  However, the CPUC has set resource adequacy requirements
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--Generation and
Power Procurement--Generation Procurement Proceedings").  Accordingly, SCE anticipates continued generation
contracting over time to maintain the minimum reserve margin.  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 direct access customers (customers who choose
to purchase power directly from an electric service provider other than SCE but then decided 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 increase rates.


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SCE anticipates purchasing additional capacity and/or ancillary services to meet its peak-energy requirements in
2005 and beyond if its net-short position is significantly higher than SCE's current forecast.  As of December
31, 2004, SCE entered into power tolling arrangement and forward physical contracts to mitigate its exposure to
energy prices in the spot market.  The fair market value of the power tolling arrangements as of December 31,
2004, was a liability of $6 million.  A 10% increase in energy prices would have resulted in a $49 million
increase in the fair market value.  A 10% decrease in energy prices would have resulted in a $37 million decrease
in the fair market value.  The fair market value of the forward physical contracts as of December 31, 2004, was
an asset of $8 million.  A 10% increase in energy prices would have resulted in a $1 million increase in the fair
market value.  A 10% decrease in energy prices would have resulted in a $2 million decrease in the fair market
value.

SCE is also exposed to increases in natural gas prices related to its QF contracts, fuel tolling arrangements,
and owned gas-fired generation, including the Mountainview project (expected to be on-line in 2006).  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 December 31, 2004, 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, 2004, was a liability of $11 million.  A 10%
increase in gas prices would have resulted in a $21 million increase in the fair market value.  A 10% decrease in
gas prices would have resulted in a $21 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.

SCE's gas expenses and gas hedging costs, as well as its purchased-power costs, are recovered through a balancing
account known as the Energy Resource Recovery Account (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.  Certain SCE activities, such as contract
administration, SCE's duties as 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 maximum disallowance cap
of $37 million for these activities.

Pursuant to 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 coordination with SCE, has hedged a portion of
its expected natural gas requirements for the gas tolling contracts allocated to SCE.  Increases in gas prices
over time, 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.


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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 should not affect earnings.

REGULATORY MATTERS

This section of the MD&A describes SCE's regulatory matters in three main subsections:

o    generation and power procurement;

o    transmission and distribution; and

o    other regulatory matters.

Generation and Power Procurement

CPUC Litigation Settlement Agreement

In October 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC which sought full
recovery of its electricity procurement costs incurred during the energy crisis.  A key element of the 2001 CPUC
settlement agreement was the establishment of a $3.6 billion regulatory balancing account, called the
Procurement-Related Obligations Account (PROACT), as of August 31, 2001 (which was fully recovered by August
2003).

Energy Resource Recovery Account Proceedings

In an October 2002 decision, the CPUC established the ERRA as the rate-making mechanism to track and recover
SCE'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) new 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 in "Management Overview--Background," 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.  As these costs are subsequently incurred, they will be tracked and recovered
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 procurement costs, SCE can request an
emergency rate adjustment in addition to the annual forecast and reasonableness ERRA applications.

2004 ERRA Forecast

SCE submitted an ERRA forecast application on October 3, 2003, in which it forecast a procurement-related revenue
requirement for the 2004 calendar year of $2.3 billion.  The CPUC issued a decision on


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April 22, 2004, approving SCE's 2004 forecast revenue requirement and rates for both generation and distribution
services.

ERRA Reasonableness Review for the Period September 1, 2001 through June 30, 2003

On October 3, 2003, SCE submitted its first ERRA reasonableness review application requesting that the CPUC find
its procurement-related operations during the period from September 1, 2001 through June 30, 2003 to be
reasonable.  The CPUC's Office of Ratepayer Advocates (ORA) was allowed to review the accounting calculations
used in the PROACT mechanism.  The ORA recommended disallowances that totaled approximately $14 million of costs
recovered through the PROACT mechanism during the period from September 1, 2001 through June 30, 2003.  In April
2004, SCE reached an agreement with the ORA (subject to CPUC approval) to reduce the PROACT disallowances to
approximately $4 million.  On January 27, 2005, the CPUC issued a decision approving the agreement.  The $4
million, which is mainly comprised of ISO grid management charges and employee-related retraining costs, will be
refunded to ratepayers through a credit to the ERRA.

The January 27, 2005 CPUC decision also provides that SCE's administration of its procurement contracts will be
subject to reasonableness review under the "reasonable manager" standard.  However, the CPUC decision provides
that the review of SCE's daily dispatch of its generation resources will be subject to a compliance review, not a
reasonableness review, and will only include a review of spot market transactions in the day-ahead, hour-ahead
and real-time markets.  The decision found that SCE's daily dispatch decisions during the record period complied
with the CPUC's standard, and that its administration of its contracts was reasonable in all respects.  It
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 pre-tax net regulatory gain of
$118 million in 2004.

ERRA Reasonableness Review for the Period July 1, 2003 through December 31, 2003

On April 1, 2004, SCE submitted its second ERRA reasonableness review application requesting that the CPUC find
its procurement-related operations during the period from July 1, 2003 through December 31, 2003, to be
reasonable.  In addition, SCE requested recovery of a $10 million reward for Palo Verde Nuclear Generating
Station (Palo Verde) Unit 3 efficient operation and $5 million in electric energy transaction administration
costs.

On January 17, 2005, the CPUC issued a decision finding that SCE's administration of its power purchase
agreements and its daily decisions dispatching its procurement resources were reasonable and prudent.  The
decision also found that the revenue and expenses recorded in SCE's ERRA account during the record period were
reasonable and prudent, and approved SCE's requested recovery of the items discussed above.

2005 ERRA Forecast

SCE submitted an ERRA forecast application on August 2, 2004, in which it forecasted a procurement-related
revenue requirement for the 2005 calendar year of $3.0 billion, an increase of $733 million over 2004.  The
forecast increase is primarily due to a reduction in expected power purchases by the CDWR.  On February 2, 2005,
the CPUC issued a proposed decision adopting SCE's requested revenue requirement for the 2005 calendar year.  A
final decision is expected in March 2005.


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CDWR Power Purchases and Revenue Requirement Proceedings

In accordance with an emergency order by the Governor of California, the CDWR began making emergency power
purchases for SCE's customers on January 17, 2001.  In February 2001, a California law was enacted which
authorized the CDWR to:  (1) enter into contracts to purchase electric power and sell power at cost directly to
SCE's retail customers; and (2) issue bonds to finance those electricity purchases.  The CDWR's total statewide
power charge and bond charge revenue requirements are allocated by the CPUC among the customers of SCE, Pacific
Gas and Electric (PG&E) and San Diego Gas & Electric (SDG&E) (collectively, the investor-owned utilities).
Amounts billed to SCE's customers for electric power purchased and sold by the CDWR (approximately $2.5 billion in
2004) are remitted directly to the CDWR and are not recognized as revenue by SCE and therefore have no impact on
SCE's earnings.

In December 2004, the CPUC issued its decision on how the CDWR's power charge revenue requirement for 2004
through 2013, when the last CDWR contract expires, will be allocated among the investor-owned utilities.  The
CPUC rejected a settlement agreement among PG&E, the Utility Reform Network (TURN), and SCE and which the ORA
supported.  However, the CPUC's final decision adopts key attributes of that settlement agreement.  It adopts a
cost-follows-contract allocation to each of the investor-owned utilities of the unavoidable portion of costs
incurred under CDWR contracts.  A previous CPUC decision allocated the avoidable portion of the costs on a
cost-follows-contract basis.  Allocating the avoidable and unavoidable portions on a cost-follows-contract basis
provides the investor-owned utilities the appropriate incentives to operate and administer the contracts that
have been allocated to them.  In addition, in order to fairly allocate the total burden of the CDWR contracts
among the investor-owned utilities, the decision adjusts the cost-follows-contract allocation of the total costs
(avoidable and unavoidable) such that the above-market cost burden associated with the contracts is allocated as
follows:  44.8% to PG&E's customers, 45.3% to SCE's customers, and 9.9% to SDG&E's customers.  The CPUC's
December 2004 decision is based on the above market cost analysis that SCE presented in its initial testimony in
December 2003.

In response to an application filed by SDG&E, the CPUC issued an order granting limited rehearing of the December
2004 decision.  The rehearing permits parties to present alternative methodologies and updated data for the
calculation of above market costs associated with the CDWR contracts.  A schedule has not been adopted for the
rehearing, but it is expected to take place in the second quarter of 2005.  SDG&E has also filed a petition for
modification of the decision urging the CPUC to replace the adopted methodology with a methodology that would
retain the cost-follows-contract allocation of the avoidable costs, but would allocate the unavoidable costs
associated with the contracts:  42.2% to PG&E's customers, 47.5% to SCE's customers, and 10.3% to SDG&E's
customers.  Such an allocation would decrease the total costs allocated to SDG&E's customers and increase the
total costs allocated to SCE's customers.  The CPUC is expected to act on the petition in March 2005.

Direct Access and Community Choice Aggregation

From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an
electric service provider other than SCE (thus becoming direct access customers) or continue to purchase power
from SCE.  In September 2001, the CPUC suspended the right of retail end-use customers to acquire direct access
service until the CDWR no longer procures power for retail end-user customers.  In addition, a 2002 California
law authorized community choice aggregation which is a form of direct access that allows local governments to
combine the loads of its residents, businesses, and municipal facilities in a community-wide electricity buyers
program and to create an entity called a community choice aggregator.


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As a result of these customer options, the CPUC issued decisions or opened proceedings to establish various
charges (exit fees) for customers who (1) switch to another electric service provider, (2) switch to a municipal
utility; or (3) install onsite generation facilities or arrange to purchase power from another entity that
installs such facilities.  Separately, the CPUC opened a proceeding to identify issues relating to the
implementation of community choice aggregation and adopted a similar exit fee approach for customers who switch
to community choice aggregation service.  The charges recovered from these customers are used to reduce SCE's
rates to bundled service customers and have no impact on earnings.  These decisions and proceedings affect SCE's
ability to predict the size of its customer base, the amount of bundled service load for which it must procure or
generate electricity, its net-short position, and its ability to plan for resource requirements.

Generation Procurement Proceedings

SCE resumed power procurement responsibilities for its net-short position (expected load requirements exceed
generation supply) on January 1, 2003, pursuant to CPUC orders and California statutes passed in 2002.  The
current regulatory and statutory framework requires SCE to assume limited responsibilities for CDWR contracts
allocated by the CPUC, and provide full power procurement responsibilities on the basis of annual short-term
procurement plans, long-term resource plans and increased procurement of renewable resources.  Currently, the
CPUC and the California Energy Commission are working together to set rules for various aspects of generation
procurement which are described below.

Procurement Plan

Resource Planning Component of the Procurement Plan

On April 1, 2004, the CPUC instituted a resource planning proceeding that, among other things, will coordinate
consideration of long-term resource plans.  On July 9, 2004, SCE filed testimony on its long-term procurement
plan, which includes a substantial commitment to cost-effective energy efficiency and an advanced load-control
program.  A CPUC decision approving SCE's long-term procurement plan was issued in December 2004.  The decision
required all long-term procurement to be conducted through all-source solicitations; allowed the consideration of
debt equivalence in the bid evaluation process; and required the use of a greenhouse gas adder as a bid
evaluation component.  The decision also extended the utilities' authority to procure longer-term products and
lifted the affiliate ban on long-term power products.  SCE's next long-term procurement plan will be filed in
2006.

Assembly Bill 57 Component of the Procurement Plan

In December 2003, the CPUC adopted a 2004 short-term procurement plan for SCE which established a target level
for spot market purchases equal to 5% of monthly need, and allowed SCE to enter into contracts of up to five
years.  Currently, SCE is operating under this approved short-term procurement plan.  To the extent SCE procures
power in accordance with the plan, SCE receives full-cost recovery of its procurement transactions pursuant to
Assembly Bill 57.  Accordingly, the plan is referred to as the Assembly Bill 57 component of the procurement
plant.

Each quarter, SCE is required to file a report with the CPUC demonstrating that SCE's procurement-related
transactions associated with serving the demands of its bundled electricity customers were in conformance with
SCE's adopted short-term procurement plan.  SCE has submitted seven quarterly compliance filings covering the
period from January 1, 2003 through September 30, 2004, including its third quarter 2004 compliance filing on
November 1, 2004.  To date, however, the CPUC has only issued one resolution approving SCE's first compliance
report for the period January 1, 2003 to March 31, 2003.  While SCE believes that all of its procurement
transactions were in compliance with its adopted


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short-term procurement plan, SCE cannot predict with certainty whether or not the CPUC will agree with SCE's
interpretation regarding some elements.

Resource Adequacy Requirements

Under the framework adopted in the CPUC's January 22, 2004 decision, all load-serving entities in California have
an obligation to procure sufficient resources to meet their customers' needs.  On October 28, 2004, the CPUC
issued a decision clarifying the January 2004 decision.  The October 2004 decision requires load-serving entities
to ensure that adequate resources have been contracted to meet that entity's peak forecasted energy resource
demand and an additional planning reserve margin of 15-17% of that peak load by June 1, 2006.  Currently, the
decision requires SCE to demonstrate that it has contracted 90% of its May-September 2006 resource adequacy
requirement by September 30, 2005.  As the May-September period approaches, SCE will be required to fill out the
remaining 10% of its resource adequacy requirement one month in advance of expected need.  The October 28, 2004
decision also clarified that although the first compliance filing will only cover May-September 2006, the 15-17%
planning reserve margin is a year-round requirement.  In its October 2004 decision, the CPUC also decided that
long-term CDWR contracts allocated to the investor-owned utilities during the 2001 energy crisis are to be fully
counted for resource adequacy purposes, and that deliverability standards developed during subsequent phases will
be applied to such contracts.  These deliverability standards, as well as a wide range of other issues, including
scheduling and load forecasting, will be addressed in a separate phase of the proceeding which is expected to be
completed by mid-2005.  SCE expects to meet its resource adequacy requirements by the deadlines set forth in the
decision.

Avoided Cost Proceeding

SCE purchases electric energy and capacity from various QFs pursuant to contracts that provide for payment at
avoided cost, as determined by the CPUC.  On April 22, 2004, the CPUC opened a rulemaking to develop, review and
update methodologies for determining avoided costs, including the methodologies SCE uses to pay its QFs.  Among
other things, the rulemaking is to consider modifications to the current methodology for short-run avoided cost
energy pricing and the current as-available capacity pricing.  The rulemaking also proposes to develop a long-run
avoided cost pricing methodology for QFs.  Hearings are scheduled for May 2005.  Although the rulemaking may
affect the amounts paid to QFs and customer rates, changes to pricing methodology should not affect SCE's
earnings as such costs are recovered from ratepayers, subject to reasonableness review.

Extension of QF Contracts and New QF Contracts

SCE has 270 power-purchase contracts with QFs, a number of which will expire in the next five years.  On
September 30, 2004, the CPUC issued a ruling requesting proposals and comments on the development of a long-term
policy for expiring QF contracts and new QFs.  SCE filed its response to the ruling on November 10, 2004, in
which it proposed to purchase electricity from QFs by (1) allowing QFs to compete in SCE's competitive
solicitations; (2) conducting bilateral negotiations for new contracts or contract extensions with QFs; or (3)
offering an energy-only contract at market-based avoided cost prices.  Hearings are scheduled for May 2005.

Procurement of Renewable Resources

As part of SCE's resumption of power procurement, and in accordance with a California statute passed in 2002, SCE
is required to increase its procurement of renewable resources by at least 1% of its annual electricity sales per
year so that 20% of its annual electricity sales are procured from renewable resources by no later than
December 31, 2017.  At year-end 2004, SCE obtained approximately 18% of its power


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supplies from renewable resources.  In June 2003, the CPUC issued a decision adopting preliminary rules and
guidance on renewable procurement-related issues, including penalties for noncompliance with renewable
procurement targets.  In June 2004, the CPUC issued two decisions adopting additional rules on renewable
procurement: a decision adopting standard contract terms and conditions and a decision adopting a market-price
methodology.  In July 2004, the CPUC issued a decision adopting criteria for the selection of least-cost and
best-fit renewable resources.  In December 2004, an assigned commissioner's ruling and scoping memo was issued
establishing a schedule for addressing various renewable procurement-related issues that were not resolved by
prior rulings and decision and directing the utilities to file renewable procurement plans addressing their 2005
renewable procurement goals and a plan for renewable procurement over the period 2005-2014.  SCE's 2005 renewable
procurement plan was filed on March 7, 2005.

SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and
conducted negotiations with bidders regarding potential procurement contracts.  On March 8, 2005, SCE filed an
advice letter with the CPUC requesting approval of 6 renewable contracts.  SCE expects a CPUC decision on its
advice letter by the second quarter of 2005.  The procedures for measuring renewable procurement are still being
developed by the CPUC.  Based upon the current regulatory framework, SCE anticipates that it will comply, even
without new renewable procurement contracts, with renewable procurement mandates through at least 2005.  Beyond
2005, SCE will either need to sign new contracts and/or extend existing renewable QF contracts.

CDWR Contract Allocation and Operating Order

The CDWR power-purchase contracts entered into as a result of the California energy crisis have been allocated on
a contract-by-contract basis among SCE, PG&E and SDG&E, in accordance with a 2002 CPUC decision.  SCE only
assumes scheduling and dispatch responsibilities and acts only as a limited agent for the CDWR for contract
implementation.  Legal title, financial reporting and responsibility for the payment of contract-related bills
remain with the CDWR.  The allocation of CDWR contracts to SCE significantly reduces SCE's residual-net short and
also increases the likelihood that SCE will have excess power during certain periods.  SCE has incorporated CDWR
contracts allocated to it in its procurement plans.  Wholesale revenue from the sale of excess power, if any, is
prorated between the CDWR and SCE.

SCE's maximum annual disallowance risk exposure for contract administration, including administration of
allocated CDWR contracts and least cost dispatch of CDWR contract resources, is $37 million.  In addition, gas
procurement, including hedging transactions, associated with CDWR contracts is included within the cap.

On January 28, 2005, the CPUC opened a new phase of its procurement proceeding to consider the reallocation of
certain CDWR contracts.  Evidentiary hearings may be held later this year.

Mohave Generating Station and Related Proceedings

On May 17, 2002, SCE filed an application with the CPUC to address certain issues (mainly coal and slurry-water
supply issues) facing any future extended operation of Mohave, which is partly owned by SCE.  Mohave obtains all
of its coal supply from the Black Mesa Mine in northeast Arizona, located on lands of the Navajo Nation and Hopi
Tribe (the Tribes).  This coal is 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.


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Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water
supply issues, SCE's application stated that SCE would probably be unable to extend Mohave's operation beyond
2005.  The uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave co-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.

On December 2, 2004 the CPUC issued a final decision on the application.  Principally, the decision: (1) directs
SCE to continue the ongoing negotiations and other efforts toward resolving the post-2005 coal and water supply
issues; (2) directs SCE to conduct a study of potential generation resources that might serve as alternatives or
complements to Mohave including solar generation and coal gasification; (3) provides an opportunity for SCE to
recover in future rates certain Mohave-related costs that SCE has already incurred or is expected to incur by
2006, including certain preliminary engineering costs, water study costs and the costs of the study of potential
Mohave alternatives; and (4) authorizes SCE to establish a rate-making account to track certain worker
protection-related costs that might be incurred in 2005 in preparation for a temporary or permanent Mohave
shutdown after 2005.

In parallel with the CPUC proceeding, negotiations have continued among the relevant parties in an effort to
resolve the coal and water supply issues.  Since November 2004, the parties have engaged in negotiations
facilitated by a professional mediator, but no final resolution has been reached.  In addition, agencies of the
federal government are now conducting both a hydro-geological study and an environmental review regarding a
possible alternative groundwater source for the slurry water; these studies, projected to cost approximately $6
million, are being funded by SCE and the other Mohave co-owners subject to the terms and conditions of a 2004
memorandum of understanding among the Mohave co-owners, the Tribes and the federal government.

The outcome of the coal and water negotiations and SCE's application are not expected to 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.  The outcome of this matter is not expected to have a material impact on earnings.

For additional matters related to Mohave, see "Other Developments--Navajo Nation Litigation."

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 cost was deferred and recorded in regulatory assets as a long-term receivable to be collected from
customer revenue.  This treatment was based on SCE's expectation that any unrecovered book value at the end of
2005 would be recovered in future rates (together with a reasonable return) through a balancing account
mechanism, as presented in its May 17, 2002 application and discussed in its supplemental testimony filed in
January 2003.

San Onofre Nuclear Generating Station

San Onofre Steam Generators

Like other nuclear power plants with steam generators of the same design and material properties, San Onofre
Units 2 and 3 have experienced degradation in their steam generators.  Based on industry experience and analysis
of recent inspection data, SCE has determined that the existing San Onofre


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Units 2 and 3 steam generators may not enable continued reliable operation of the units beyond their scheduled
refueling outages in 2009-2010.  SCE currently estimates that the cost of replacing the steam generators would be
about $680 million, of which SCE's 75% share would be about $510 million.  On February 27, 2004, SCE filed an
application with the CPUC seeking a decision that it is reasonable for SCE to replace the San Onofre Units 2 and
3 steam generators and establishing appropriate ratemaking for recovery in rates of the reasonable cost of the
replacement project.  In June 2004, the CPUC established a schedule providing for a final CPUC decision in
September 2005.  Evidentiary hearings were held between January 31, 2005, and February 11, 2005.

The ORA has proposed that the CPUC disallow recovery of between 28.75% and 32.5% of the costs of steam generator
replacement project costs or, in the alternative, require SCE to bear an equivalent percentage of the assumed
replacement power costs if the steam generator replacement does not go forward and, as a result, San Onofre Units
2 and 3 experience reduced or suspended periods of operation in the future.  ORA contends that SCE should incur
one of these alternative consequences due to its alleged imprudence in failing to pursue claims against the
manufacturer of the steam generators or its successors and/or in providing a broader release to the manufacturer
than was allegedly appropriate.  Assuming currently estimated project costs, including construction financing
costs, a 32.5% proposed disallowance could be about $260 million.  SCE is vigorously opposing ORA's proposed
disallowance as unwarranted and confiscatory.  TURN has also recommended that the CPUC find SCE's failure to
pursue claims against the steam generator manufacturer and providing a broader release to the manufacturer than
was allegedly appropriate to be unreasonable.  However, TURN has not recommended that the CPUC adopt a specific
disallowance amount.  A CPUC decision on the proposed disallowance is expected at the same time as the CPUC's
decision on SCE's application for steam generator replacement.

On September 30, 2004, SCE entered into a contract for steam generator fabrication.  By the time of the CPUC's
scheduled decision in September 2005, SCE anticipates that it will have incurred approximately $50 million in
steam generator fabrication and associated project costs.  SCE will seek recovery of these costs in the event
that the CPUC does not authorize SCE to go forward with steam generator replacement.  If the CPUC authorizes SCE
to go forward with steam generator replacement, SCE will recover all of these costs that are reasonably incurred
as part of the steam generator replacement capital costs.

Under the San Onofre operating agreement among the co-owners, a co-owner may elect to reduce its ownership share
in lieu of paying its share of the cost of repairing an "operating impairment," as such term is defined in the
San Onofre operating agreement.  SCE has declared an "operating impairment" in connection with the need for steam
generator replacement.  SDG&E and the City of Anaheim have elected to reduce their respective 20% and 3.16%
ownership shares rather than participate in the steam generator replacement project.  The other co-owner, the
City of Riverside (which owns 1.79% of the units), has elected to participate in the project.  If steam generator
replacement proceeds, SDG&E's and the City of Anaheim's ownership shares of San Onofre Units 2 and 3 will, upon
completion of the project, be reduced in accordance with the formula set forth in the operating agreement.  Under
the formula, the City of Anaheim's share of San Onofre Units 2 and 3 will be reduced to zero percent.  SDG&E
disputed the proper application of the formula.  As a result, the matter was subject to arbitration.  The
arbitrator's decision was issued on February 18, 2005.  Assuming the cost of steam generator replacement is not
significantly lower than currently estimated, under the arbitrator's decision, SDG&E's ownership share would also
be reduced to zero percent under the arbitrator's decision.  Under the terms of the operating agreement, the
decision of the arbitrator is subject to approval by the CPUC.  The transfer of all or any portion of SDG&E's and
the City of Anaheim's respective ownership share as a result of their election not to participate in steam
generator replacement will require Nuclear Regulatory Commission approval.  The transfer of all or any portion of
SDG&E's ownership share to SCE will also require CPUC approval.


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San Onofre Reactor Vessel Heads

During the ongoing San Onofre Unit 3 refueling outage in the fourth quarter of 2004, SCE conducted a planned
inspection of the Unit 3 reactor vessel head and found indications of degradation.  Although the indications were
far below the level at which leakage would occur, SCE repaired these indications using readily available tooling
and a Nuclear Regulatory Commission-approved repair technique.  While this was San Onofre's first experience of
this kind of degradation to the reactor vessel head, the detection and repair of similar degradation is now
common in the industry.  SCE plans to replace the Unit 2 and 3 reactor vessel heads during the planned refueling
outages in 2009-2010.

San Onofre Pressurizer Heater Sleeve Replacement

San Onofre Units 2 and 3 each include a pressurizer tank that contains 30 heater penetrations fabricated from the
same material used in the steam generator tubes.  These penetrations, also known as sleeves, are 13-inch long
sections of pipe welded into the bottom of the pressurizer.  During the recent Unit 3 outage, SCE performed
inspections of two sleeves and found evidence of degradation.  Degradation of the pressurizer sleeves has been a
concern in the nuclear industry for some time, and SCE had been planning to replace all of the sleeves in both
units during their next scheduled refueling outages in 2005 and 2006, respectively.  With the discovery of sleeve
degradation, SCE decided to move the planned replacement of 29 of the 30 Unit 3's sleeves forward from 2006 into
the 2004 outage.  This extra work extended the outage from 55 days to 92 days.  This outage reduced the 2004
capacity factor of Unit 3 to 74%.  The CPUC will review the reasonableness of outage-related capital costs and
replacement power costs in future rate-making proceedings.  SCE believes the costs are reasonable, recovery of
the costs should be authorized, and the acceleration of the needed repairs should not impact earnings.

Palo Verde Steam Generators

The steam generators at the Palo Verde, in which SCE owns a 15.8% interest, have material properties that are
similar to the San Onofre units.  During 2003, the Palo Verde Unit 2 steam generators were replaced.  In
addition, the Palo Verde owners have approved the manufacture of two additional sets of steam generators for
installation in Units 1 and 3.  The Palo Verde owners expect that these steam generators will be installed in
Unit 1 in 2005 and in Unit 3 in the 2007 to 2008 time frame.  SCE's share of the costs of manufacturing and
installing all the replacement steam generators at Palo Verde is estimated to be about $115 million; SCE expects
to recover these costs through the rate-making process.

Inspections of Palo Verde Units 1, 2 and 3 reactor vessel heads were performed during scheduled refueling and
maintenance outages in 2003 and 2004 and no indications of leakage or degradation were found.

Transmission and Distribution

2003 General Rate Case Proceeding

On May 3, 2002, SCE filed its application for a 2003 GRC, requesting an increase of $286 million in SCE's base
rate revenue requirement, which was subsequently revised to an increase of $251 million.  The application also
proposed an estimated base rate revenue decrease of $78 million in 2004, and a subsequent increase of
$116 million in 2005.  The forecast reduction in 2004 was largely attributable to the expiration of the San Onofre
incremental cost incentive pricing (ICIP) rate-making mechanism at year-end 2003 and a forecast of increased
sales.


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Management's Discussion and Analysis of Financial Condition and Results of Operations
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The CPUC issued a final decision on SCE's 2003 GRC application on July 8, 2004, authorizing an annual increase of
approximately $73 million in base rates, retroactive to May 22, 2003 (the date a final CPUC decision was
originally scheduled to be issued).  The decision also authorized a base rate revenue decrease of $49 million in
2004, and a subsequent increase of $84 million in 2005.  During the second quarter of 2004, SCE recorded a
pre-tax net regulatory gain of $180 million as a result of the implementation of the 2003 GRC decision, primarily
relating to the recognition of revenue from the rate recovery of pension contributions during the time period
that the pension plan was fully funded, the resolution of the allocation of costs between transmission and
distribution for 1998 through 2000, partially offset by the deferral of revenue previously collected during the
ICIP mechanism for dry cask storage.  The gain was included in the caption "provisions for regulatory adjustment
clauses--net" on the income statement.

Because processing of the GRC took longer than initially scheduled, in May 2003, the CPUC approved SCE's request
to establish a memorandum account to track the revenue requirement increase during the period between May 22,
2003 and the date a final decision was adopted.  In July 2004, SCE submitted an advice filing to record the
amount in this memorandum account and recorded an approximate $55 million pre-tax gain in the third quarter of
2004 included in the caption "operating revenue" on the income statement.  In addition, during the third quarter
of 2004 SCE recorded approximately $48 million in pre-tax gains related to the 1997-1998 generation-related
capital additions ($31 million, which is included in the caption "provisions for regulatory adjustment
clauses--net" on the income statement) and the related rate recovery ($17 million, which is included in the caption
"operating revenue" on the income statement).

The amount recorded in the GRC memorandum account is being recovered in rates together with the 2004 revenue
requirement authorized by the CPUC in the GRC decision.  The GRC rate increase was combined with other rate
changes from pending rate proceedings and became effective August 5, 2004.

2006 General Rate Case Proceeding

On December 21, 2004, SCE filed its application for a 2006 GRC, requesting an increase of $370 million in SCE's
2006 base rate revenue requirement, primarily for capital-related expenditures to accommodate customer and load
growth and substantially higher operation and maintenance expenditures particularly in SCE's transmission and
distribution business unit.  SCE also requested that the CPUC authorize continuation of SCE's existing post-test
year rate-making mechanism, which would result in base rate revenue increases of $159 million and $122 million in
2007 and 2008, respectively.  If the CPUC approves these requested increases and allocates them to ratepayer
groups on a system average percentage change basis, the total increase over current base rates is estimated to be
10%.  A decision on SCE's 2006 GRC is expected in December 2005.

2005 Cost of Capital

SCE's annual cost of capital applications with the CPUC are required to be filed in May of each year, with
decisions rendered in such proceedings becoming effective January 1 of the following year.  On May 10, 2004, SCE
filed an application requesting the CPUC to maintain for 2005 the currently authorized 11.60% return on common
equity for SCE's CPUC-jurisdictional assets.  SCE also requested a change in its authorized capital structure to
offset the effects of debt equivalence of power-purchase agreements and revised SCE's projected costs of
long-term debt and preferred stock.  SCE's overall request projected a decrease in revenue requirements of
approximately $28 million.

On December 16, 2004, the CPUC issued a final decision granting an 11.4% return on common equity and debt
equivalent recognition through a higher preferred equity capitalization ratio.  The decision


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resulted in a $47 million decrease in revenue requirements due to lower interest costs and the reduced return on
equity and an overall rate of return of 9.07% on CPUC-jurisdictional assets.

Transmission Proceeding

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 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 unrecovered costs since 1998.  After the
three California utilities appealed the decisions to the United States Court of Appeals for the D.C. Circuit, the
FERC filed a motion with the D.C. Circuit Court seeking voluntary remand to permit issuance of a further order.
On February 12, 2004, the D.C. Circuit Court granted the FERC's motion and remanded the record back to the FERC
for further consideration.  On May 6, 2004, the FERC issued its order reaffirming its earlier decisions.  SCE and
the other two California utilities are pursuing the appeal before the D.C. Circuit Court, and filed their opening
briefs with the D.C. Circuit Court on October 12, 2004.  Oral argument is set for May 9, 2005.

Wholesale Electricity and Natural Gas Markets

In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of
electricity in the California Power Exchange 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.  Under the 2001 CPUC
settlement agreement, mentioned in "--Generation and Power Procurement--CPUC Litigation Settlement Agreement," 90%
of any refunds actually realized by SCE net of costs will be refunded to customers, except for the El Paso
Natural Gas Company settlement agreement discussed below.

El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including
SCE, PG&E, the State of California and various consumer class action representatives) settling various claims
stated in proceedings at the FERC and in San Diego County Superior Court that El Paso had manipulated interstate
capacity and engaged in other anticompetitive behavior in the natural gas markets in order to unlawfully raise
gas prices at the California border in 2000-2001.  The United States District Court has issued an order approving
the stipulated judgment and the settlement agreement has become effective.  Pursuant to a CPUC decision, SCE will
refund to customers amounts received under the terms of the El Paso settlement (net of legal and consulting
costs) through its ERRA mechanism.  In June 2004, SCE received its first settlement payment of $76 million.
Approximately $66 million of this amount was credited to purchased-power expense, and will be refunded to SCE's
ratepayers through the ERRA over the next 12 months, and the remaining $10 million was used to offset SCE's
incurred legal costs.  Additional settlement payments totaling approximately $127 million are due from El Paso
over a 20-year period.  As a result, SCE recorded a receivable and corresponding regulatory liability of $65
million in 2004 for the discounted present value of the future payments (discounted at an annual rate of 7.86%).
Amounts El Paso refunds to the CDWR will result in reductions in the CDWR's revenue requirement allocated to SCE
in proportion to SCE's share of the CDWR's power charge revenue requirement.

On July 2, 2004, the FERC approved a settlement agreement between SCE, SDG&E and PG&E and The Williams Cos. and
Williams Power Company, providing for approximately $140 million in refunds


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Management's Discussion and Analysis of Financial Condition and Results of Operations
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and other payments to the settling purchasers and others against some of Williams' power charges in 2000-2001.
In August 2004, SCE received its $37 million share of the refunds and other payments under the Williams
settlement.

On April 26, 2004, SCE, PG&E, SDG&E and several California state governmental entities agreed to settlement terms
with West Coast Power, LLC and its owners, Dynegy Inc. and NRG Energy, Inc. (collectively, Dynegy).  The
settlement terms provide for refunds and other payments totaling $285 million, with a proposed allocation to SCE
of approximately $42 million.  The Dynegy settlement terms were approved by the FERC on October 25, 2004 and SCE
received its $42 million share of the settlement proceeds in November 2004.

On July 12, 2004, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Duke Energy
Corporation and a number of its affiliates (collectively Duke).  The settlement terms agreed to with the Duke
parties provide for refunds and other payments totaling in excess of $200 million, with a proposed allocation to
SCE of approximately $45 million.  The Duke settlement was approved by the FERC on December 7, 2004 and SCE
received its $45 million share of the settlement proceeds in January 2005.

On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Mirant
Corporation and a number of its affiliates (collectively Mirant), all of whom are debtors in a Chapter 11
bankruptcy proceeding pending in Texas.  Among other things, the settlement terms provide for expected cash and
equivalent refunds totaling $320 million, of which SCE's allocated share is approximately $68 million.  The
settlement also provides for an allowed, unsecured claim totaling $175 million in the bankruptcy of one of the
Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim.  The actual value of
the unsecured claim will be determined as part of the resolution of the Mirant parties' bankruptcies.  The Mirant
settlement was submitted to the FERC for its approval on January 31, 2005 and was submitted to the Mirant
bankruptcy court for its approval on February 23, 2005.

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 from energy providers and
allocating them in accordance with the terms of the CPUC litigation settlement agreement.  The resolution
accordingly provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA will be
allocated to recovery of SCE's litigation costs and expenses in the FERC refund proceedings described above and
as a shareholder incentive pursuant to the CPUC litigation settlement agreement.  Remaining amounts for each
settlement are to be refunded to ratepayers through the ERRA mechanism.  In 2004, SCE recorded in the caption
"Other nonoperating income" on the income statement a total of $12 million as shareholder incentives related to
refunds received in 2004.

Other Regulatory Matters

Catastrophic Event Memorandum Account

The catastrophic event memorandum account (CEMA) is a CPUC-authorized mechanism established in 1991 that allows
SCE to immediately start the tracking of all of its incremental costs associated with declared disasters or
emergencies and to subsequently receive rate recovery of its reasonably incurred costs upon CPUC approval.
Incremental costs associated with restoring utility service; repairing, replacing or restoring damaged utility
facilities; and complying with governmental agency orders are tracked in the CEMA.  SCE currently has a CEMA for
the bark beetle emergency and a CEMA associated with the fires that occurred in SCE territory in October 2003.
Costs tracked through the CEMA mechanism may be recovered in future rates after SCE's filing of a request with
the CPUC, a


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showing of their reasonableness and approval by the CPUC with no impact on earnings. However, cash flow will be
impacted due to the timing difference between expenditures and rate recovery.

Bark Beetle CEMA

On March 7, 2003, the Governor of California issued a proclamation declaring a state of emergency in Riverside,
San Bernardino and San Diego counties where an infestation of bark beetles has created the potential for
catastrophic forest fires.  The proclamation requested that the CPUC direct utilities with transmission lines in
these three counties to assist local jurisdictions in responding to this emergency by ensuring that all dead,
dying and diseased trees and vegetation are completely cleared from their utility rights-of-way to mitigate the
risk of fire.  SCE's role in this effort is to support the State of California, federal and local agencies by
hiring contractors who are capable of removing these trees and vegetation in a vast area for the purpose of
protecting against potential damage that may occur from fires and the collapse or falling of these tress into
SCE's electrical lines and facilities.  SCE estimates that it may incur over $100 million in incremental expenses
over the next several years to remove over 350,000 of these trees.  This cost estimate is subject to significant
change, depending on a number of evolving circumstances, including, but not limited to the spread of the bark
beetle infestation, the speed at which trees can be removed, and tree disposal costs.  As of December 31, 2004,
the bark beetle CEMA had a balance of $131 million.  On September 23, 2004, the CPUC issued a resolution on SCE's
advice filing granting recovery of the majority of the $18 million bark beetle related costs recorded in 2003.
The CPUC disallowed approximately $500,000 in recorded costs based on the assertion that such costs were already
recovered in rates under SCE's routine line-clearing program.  The CPUC also modified its original authorization
and now requires future bark beetle CEMA filings to be applications instead of advice letters.  SCE estimates
that it will spend approximately $40 million on this project in 2005 and approximately $45 million in both 2006
and 2007.  SCE will submit an application to recover the 2004 costs in 2005.

Fire-Related CEMA

In October and November of 2003, wildfires damaged SCE's electrical infrastructure, primarily in the
San Bernardino Mountains of southern California where an estimated 2,085 power poles 2,059 services,
371 transformers, 557,033 of overhead conductors and 25,822 feet of underground cable were replaced or repaired.
SCE notified the CPUC that it initiated a CEMA on October 21, 2003 to track the incremental costs to repair and
restore its infrastructure.  As of December 31, 2004, the fire-related CEMA had a balance of $12 million.  The
total costs associated with the fire-related CEMA, as of December 31, 2005, are expected to be $16 million.  SCE
filed an application with the CPUC on December 2, 2004 to seek recovery of its fire-related costs over a one-year
period commencing January 1, 2006.  In addition, SCE is requesting that the CPUC find reasonable $28 million of
incremental capital expenditures, which would be recovered in rates over the useful life of the particular asset.

Holding Company Proceeding

In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions
authorizing utilities to form holding companies and initiated an investigation into, among other things:
(1) whether the holding companies violated CPUC requirements to give first priority to the capital needs of their
respective utility subsidiaries; (2) any additional suspected violations of laws or CPUC rules and decisions; and
(3) whether additional rules, conditions, or other changes to the holding company decisions are necessary.


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

On January 9, 2002, the CPUC issued an interim decision interpreting the CPUC requirement that the holding
companies give first priority to the capital needs of their respective utility subsidiaries.  The decision stated
that, at least under certain circumstances, holding companies are required to infuse all types of capital into
their respective utility subsidiaries when necessary to fulfill the utility's obligation to serve its customers.
The decision did not determine whether any of the utility holding companies had violated this requirement,
reserving such a determination for a later phase of the proceedings.  On February 11, 2002, SCE and Edison
International filed an application before the CPUC for rehearing of the decision.  On July 17, 2002, the CPUC
affirmed its earlier decision on the first priority requirement and also denied Edison International's request
for a rehearing of the CPUC's determination that it had jurisdiction over Edison International in this
proceeding.  On August 21, 2002, Edison International and SCE jointly filed a petition in California state court
requesting a review of the CPUC's decisions with regard to first priority requirements, and Edison International
filed a petition for a review of the CPUC decision asserting jurisdiction over holding companies.  PG&E and SDG&E
and their respective holding companies filed similar challenges, and all cases have been transferred to the First
District Court of Appeals in San Francisco.

On May 21, 2004, the Court of Appeal issued its decision in the two consolidated cases, and denied the utilities'
and their holding companies' challenges to both CPUC decisions.  The Court of Appeal held that the CPUC has
limited jurisdiction to enforce in a CPUC proceeding the conditions agreed to by holding companies incident to
their being granted authority to assume ownership of a CPUC-regulated utility.  The Court of Appeal held that the
CPUC's decision interpreting the first priority requirement was not reviewable because the CPUC had not made any
ruling that any holding company had violated the first priority requirement.  However, the Court of Appeal
suggested that if the CPUC or any other authority were to rule that a utility or holding company violated the
first priority requirement, the utility or holding company would be permitted to challenge both the finding of
violation and the underlying interpretation of the first priority requirement itself.  On June 30, 2004, Edison
International and the other utility holding companies filed with the California Supreme Court a petition for
review of the Court of Appeal decision as to jurisdiction over holding companies, but they and the utilities did
not file a challenge to the decision as to the first priority issue.  On September 1, 2004, the California
Supreme Court denied the petition for review.  The Court of Appeal's decision, as to jurisdiction, is now final.

The original order instituting the investigation into whether the utilities and their holding companies have
complied with CPUC decisions and applicable statutes remains in effect.  However, on February 11, 2005, an
administrative law judge ruling was issued which provides that any party to the proceedings that believes the
proceedings should remain open has 30 days to file comments listing matters that remain to be decided and
explaining why they must be resolved at the CPUC rather than in another forum.  The CPUC indicated that if
comments are not received in the 30 day time period, a decision closing the proceeding will be prepared for CPUC
consideration and no further comment will be allowed.  At this time, SCE is not aware whether or not comments
have been received or whether the CPUC has taken further action.

Investigation Regarding Performance Incentives Rewards

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 or
disallowances of past and potential PBR rewards for customer


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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.

Customer Satisfaction

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 distribution business 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 about
$10 million for 2003.

SCE has been conducting an internal investigation and keeping the CPUC informed of its progress.  On June 25,
2004, SCE submitted to the CPUC a PBR customer satisfaction investigation report, which concluded that employees
in the design organization of the transmission and distribution business unit deliberately altered customer
contact information in order to affect the results of customer satisfaction surveys.  At least 36 design
organization personnel engaged in deliberate misconduct including alteration of customer information before the
data were transmitted to the independent survey company.  Because of the apparent scope of the misconduct, SCE
proposed to refund to ratepayers $7 million of the  PBR rewards previously received and forego 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 (1997-2003).  In addition, during its investigation, SCE
determined that it could not confirm the integrity of the method used for obtaining customer satisfaction survey
data for meter reading.  Thus, SCE also proposed to refund 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 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 GRC.

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 were disciplined for misconduct.

Employee Injury and Illness Reporting

In light of the problems uncovered with the customer satisfaction surveys, SCE is conducting 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.


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

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.  Under the PBR
mechanism, rewards and/or penalties for the years 1997 through 2003 were based upon a total incident rate, which
included two equally weighted measures: Occupational Safety and Health Administration (OSHA) recordable incidents
and first aid incidents.  The major issue disclosed in the investigative findings to the CPUC was that SCE failed
to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.
SCE's investigation also found reporting inaccuracies for OSHA recordable incidents, but the impact of these
inaccuracies did not have a material effect on the PBR mechanism.

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 is taking other remedial action to address the issues identified, including revising its organizational
structure and overall program for environmental, health and safety compliance.  Additional actions, including
disciplinary action against specific employees identified as having committed wrongdoing, may result once the
investigation is completed.  SCE submitted a report 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.  However, SCE anticipates that the CPUC will be submitting data requests and seeking additional
information in the near future.

System Reliability

In light of the problems uncovered with the PBR mechanisms discussed above, SCE is conducting an investigation
into the third PBR metric, system reliability.  Since the inception of PBR payments in 1997, SCE has received
$8 million in rewards and has applied for an additional $5 million reward based on frequency of outage data for
2001.  For 2002, SCE's data indicates that it earned no reward and incurred no penalty.  Based on the application
of the PBR mechanism, as adopted, SCE's data would result in penalties of $5 million and $1 million, for 2003 and
2004, respectively.  These penalties have not yet been assessed.  As a result of SCE's data and calculations, SCE
has accrued a $6 million charge in the caption "Other nonoperating deductions" on the income statement in 2004.

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

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.  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 electric and magnetic fields
exposures in homes or work and some diseases, and because of these questions, some health authorities have
identified electric and magnetic fields exposures as a possible human carcinogen.


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In October 2002, the California Department of Health Services released to the CPUC and the public its report
evaluating the possible risks from electric and magnetic fields.  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 electric and magnetic fields 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 a rulemaking to update the CPUC's policies and
procedures related to electromagnetic fields emanating from regulated utility facilities.  SCE and other
interested parties submitted comments to clarify the issues to be addressed in the proceeding in December 2004
and January 2005.  It is anticipated that the CPUC will schedule a prehearing conference in the near future.  SCE
cannot predict with certainty the outcome of this proceeding.

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 effect of past
operations on the environment.

Environmental Remediation

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

SCE's recorded estimated minimum liability to remediate its 24 identified sites is $82 million.  In third quarter
2003, SCE sold certain oil storage and pipeline facilities.  This sale caused a reduction in SCE's recorded
estimated minimum environmental liability.  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
uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to
$123 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 30 immaterial 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 $27 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


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Management's Discussion and Analysis of Financial Condition and Results of Operations
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expects to recover costs incurred at its remaining sites through customer rates.  SCE has recorded a regulatory
asset of $55 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.

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 $13 million to $25 million.  Recorded costs for 2004 were $14
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.

Clean Air Act

The Clean Air Act requires power producers to have emissions allowances to emit sulfur dioxide.  Power companies
receive emissions allowances from the federal government and may bank or sell excess allowances.  SCE has had and
expects to continue to have excess allowances under Phase II of the Clean Air Act.

In 1999, SCE and other co-owners of Mohave entered into a consent decree to resolve a federal court lawsuit that
had been filed alleging violations of various emissions limits.  This decree, approved by a federal court in
December 1999, required certain modifications to the plant in order for it to continue to operate beyond 2005 to
comply with the Clean Air Act.

SCE's share of the costs of complying with the consent decree and taking other actions to continue operation of
Mohave beyond 2005 is estimated to be approximately $605 million. SCE has received from the State of Nevada a
permit to install the necessary pollution-control equipment.  If the station is shut down at that time, the
shutdown is not expected to have a material adverse impact on SCE's financial position or results of operations,
assuming the remaining book value of the station (approximately $8 million as of December 31, 2004) and the
related regulatory asset (approximately $78 million as of December 31, 2004), and plant closure and
decommissioning-related costs are recoverable in future rates.  SCE cannot predict with certainty what effect any
future actions by the CPUC may have on this matter.  See "Regulatory Matters--Generation and Power
Procurement--Mohave Generating Station and Related Proceedings" for further discussion of the Mohave issues.

SCE's facilities in the United States are subject to the Clean Air Act's new source review (NSR) requirements
related to modifications of air emissions sources at electric generating stations.  Over the past five years, the
United States Environmental Protection Agency (U.S. EPA) has initiated investigations of numerous electric
utilities seeking to determine whether these utilities engaged in activities in violation of the NSR
requirements, brought enforcement actions against some of those utilities, and reached settlements with some of
those utilities.  The U.S. EPA has made information requests concerning SCE's Four Corners station.  Other than
these requests for information, no


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                                                                                Southern California Edison Company
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enforcement-related proceedings have been initiated against any SCE facilities by the U.S. EPA relating to NSR
compliance.

Over this same period, the U.S. EPA has proposed several regulatory changes to NSR requirements that would
clarify and provide greater guidance to the utility industry as to what activities can be undertaken without
triggering the NSR requirements.  Several of these regulatory changes have been challenged in the courts.  As a
result of these developments, the U.S. EPA's enforcement policy on alleged NSR violations is currently
uncertain.

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.

SCE's projected environmental capital expenditures over the next three years are:  2005 - $407 million; 2006 -
$444 million; and 2007 - $530 million.  The projected environmental capital expenditures are mainly for
undergrounding certain transmission and distribution lines.

Federal Income Taxes

Edison International has reached a tentative settlement with the Internal Revenue Service (IRS) on tax issues and
pending affirmative claims relating to its 1991 to 1993 tax years currently under appeal.  This settlement, which
should be finalized in 2005, is expected to result in a net earnings benefit for SCE of approximately $70 million.

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting
deficiencies, including deficiencies asserted against SCE, in federal corporate income taxes with respect to
audits of its 1994 to 1996 and 1997 to 1999 tax years, respectively.  Many of the asserted tax deficiencies are
timing differences and, therefore, amounts ultimately paid (exclusive of interest and penalties), if any, would
benefit SCE as future tax deductions.

The IRS Revenue Agent Report for the 1997 to 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.

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.

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 claims for, among other things, violations of the federal Racketeer Influenced and
Corrupt Organizations statute, interference with fiduciary duties and


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Management's Discussion and Analysis of Financial Condition and Results of Operations
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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 for its separate dismissal from the lawsuit.

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 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 analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for
summary judgment in the D.C. District Court action.  On April 13, 2004, the D.C. District Court denied SCE's and
Peabody's April 2003 motions to dismiss or, in the alternative, for summary judgment.  The D.C. District Court
subsequently issued a scheduling order that imposed a December 31, 2004 discovery cut-off.  Pursuant to a joint
request of the parties, the D.C. District Court granted a 120-day stay of the action 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.

The United States Court of Appeals for the D.C. Circuit, acting on a suggestion on remand filed by the Navajo
Nation, held in an October 24, 2003 decision that the Supreme Court's March 4, 2003 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.  The Government and the Navajo Nation both filed petitions for rehearing of the
October 24, 2003 D.C. Circuit Court decision.  Both petitions were denied on March 9, 2004.  On March 16, 2004,
the D.C. Circuit Court issued an order remanding the case against the Government to the Court of Federal Claims,
which conducted a status conference on May 18, 2004.  As a result of the status conference discussion, the Navajo
Nation and the Government are in the process of briefing the remaining issues following remand.  Peabody's motion
to intervene as a party in the remanded Court of Federal Claims case was denied.

SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of
the Supreme Court's decision in the Navajo Nation's suit against the Government on this complaint, or the impact
of the complaint on the operation of Mohave beyond 2005.

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 Statement of Cash Flows.


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Results of Operations

Income from Continuing Operations

SCE income from continuing operations in 2004 were $921 million, compared to income of $882 million in 2003
and income of $1.2 billion in 2002.  SCE's 2002 income included a $480 million benefit related to the
implementation of the CPUC utility-related generation (URG) decision.  Excluding a $480 million benefit in 2002
related to a regulatory decision on SCE's utility-retained generation, SCE's income from continuing operations
was $767 million in 2002.  The $39 million increase between 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 customer growth and increased capital expenditures were authorized in the 2003 GRC decision.  The $115
million increase between 2003 and 2002, excluding the $480 million benefit, results from the net effect of the
resolution of several regulatory proceedings in 2003 and 2002.  The 2003 proceedings include the CPUC decision on
the allocation of certain costs between state and federal regulatory jurisdictions, tax impacts from the FERC
rate case, and the final disposition of the PROACT which had been created to record the recovery of SCE's
procurement-related obligations.  The positive effects of these factors on 2003 income were partially offset by
the implementation in 2002 of the CPUC's URG decision and PBR rewards received in 2002.  SCE's results also
included higher depreciation expense and lower net interest income, partially offset by higher FERC and PBR
revenue.

Operating Revenue

SCE's retail sales represented over approximately 85% of operating revenue.  Due to warmer weather during the
summer months, operating revenue during the third quarter of each year is generally significantly higher than
other quarters.

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

     In millions                      Year ended December 31,               2004 vs. 2003           2003 vs. 2002
----------------------------------------------------------------------------------------------------------------

     Operating revenue
         Rate changes (including surcharges)                                $   (707)                $  (677)
         Direct access credit                                                     --                     471
         Sales volume changes                                                   (159)                    (60)
         Sales for resale                                                        164                     394
         SCE's variable interest entities                                        285                      --
         Other (including intercompany transactions)                              11                      20
----------------------------------------------------------------------------------------------------------------
     Total                                                                  $   (406)                $   148
----------------------------------------------------------------------------------------------------------------


Total operating revenue decreased by $406 million in 2004 (as shown in the table above).  The reduction in
operating revenue due to rate changes resulted from the implementation of a CPUC-approved customer rate reduction
plan effective August 1, 2003 and the recognition of revenue in 2003 from a CPUC-authorized surcharge collected
in 2002 used to recover costs incurred in 2003.  There was no surcharge revenue recognized in 2004.  The
operating revenue reduction related to rate changes also reflects an increase in distribution rates and a further
decrease in generation rates, effective in August 2004, resulting from the implementation of the 2003 GRC, and an
allocation adjustment for the


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Management's Discussion and Analysis of Financial Condition and Results of Operations
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CDWR energy purchases recorded in 2003.  The decrease in electric revenue resulting from sales volume changes was
mainly due to the CDWR providing a greater amount of energy to SCE's customers in 2004, as compared to 2003 (see
discussion below), 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 represents the recognition of revenue resulting from the consolidation of SCE's
variable interest entities on March 31, 2004 (see "Critical Accounting Policies and Estimates" and "New
Accounting Principles").

Total operating revenue increased by $148 million in 2003 (as shown in the table above).  The reduction in
operating revenue due to rate changes resulted from the implementation of a CPUC-approved customer rate-reduction
plan effective August 1, 2003, partially offset by the recognition of revenue from a CPUC-authorized temporary
surcharge collected between June and December 2002, used to recover costs incurred in 2003.  The increase in
operating revenue due to direct access credits resulted from a net 1(cent)-per-kWh decrease in credits given to direct
access customers.  The reduction in electric revenue resulting from changes in sales volume was mainly due to an
increase in the amount allocated to the CDWR for bond and direct access exit fees (see discussion below),
partially offset by an increase in kWh sold due to warmer weather in 2003 as compared to 2002.  Sales for resale
revenue increased due to a greater amount of excess energy at SCE in 2003 as compared to 2002.

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 15, 2002) and direct access
exit fees (beginning January 1, 2003) are remitted to the CDWR and are not recognized as revenue by SCE.  These
amounts were $2.5 billion, $1.7 billion, and $1.4 billion for the years ended December 31, 2004, 2003, and 2002,
respectively.

Operating Expenses

Fuel Expense

Fuel expense increased $575 million in 2004 primarily due to the consolidation of SCE's variable interest
entities resulting in the recognition of fuel expense of $578 million (see "New Accounting Principles").

Purchased-Power Expense

Purchased-power expense decreased $454 million in 2004 and increased $770 million in 2003.  The 2004 decrease was
mainly due to the consolidation of SCE's variable interest entities which resulted in a $669 million reduction in
purchased-power expense (see "New Accounting Principles") and the receipt of approximately $190 million in
settlement agreement payments between SCE and sellers of electricity and natural gas.  See "Regulatory
Matters--Transmission and Distribution--Wholesale Electricity and Natural Gas Markets" for a discussion of the
settlements reached.  The decrease was 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. The 2003 increase was mainly due to higher expenses
resulting from SCE's resumption of power procurement on January 1, 2003.  The higher expenses resulted from an
increase in the number of bilateral contracts entered into during 2003 and an increase in energy purchased in
2003.  The increase also includes higher expenses related to power purchased by SCE from QFs, mainly due to
higher spot natural gas prices in 2003 as compared to 2002.


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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 5.37(cent)-per-kWh.  Average spot natural
gas prices were higher during 2004 as compared to 2003, and were higher during 2003, as compared to 2002.

Provisions for Regulatory Adjustment Clauses - Net

Provisions for regulatory adjustment clauses - net decreased $1.3 billion in 2004 and $364 million in 2003.  The
2004 decrease was mainly due to the collection of the 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 approximately $335 million of regulatory adjustments, related to the
implementation of SCE's 2003 GRC decision (see "Regulatory Matters--Transmission and Distribution--2003 General
Rate Case Proceeding") and ERRA-related adjustments resulting from a CPUC decision received in January 2005 (see
"Regulatory Matters--Generation and Power Procurement--Energy Resource Recovery Account Proceedings"), and the
deferral of costs for future recovery in the amount of approximately $100 million associated with the bark beetle
infestation (see "Regulatory Matters--Other Regulatory Matters--Catastrophic Event Memorandum Account").  The
decrease was partially offset by approximately $190 million in settlement agreement payments received and
refunded to ratepayers and shareholder incentives (see "Regulatory Matters--Transmission and
Distribution--Wholesale Electricity and Natural Gas Markets"), the favorable resolution of certain regulatory cases
recorded in the third quarter of 2003 (as discussed below), and an allocation adjustment of approximately
$110 million for CDWR energy purchases recorded in 2003.  The 2003 decrease was mainly due to lower
overcollections used to recover SCE's PROACT balance, the implementation of the CPUC-authorized customer
rate-reduction plan, a net increase in energy procurement costs and favorable resolution of several regulatory
proceedings.  The 2003 proceedings include the CPUC decision on the allocation of certain costs between state and
federal regulatory jurisdictions and the final disposition of the PROACT.  The 2003 decrease was partially offset
by the implementation of the CPUC decision related to URG and the PBR mechanism, as well as the impact of other
regulatory actions recorded in 2002.

As a result of the URG decision received in 2002, SCE reestablished regulatory assets previously written off
(approximately $1.1 billion) related to its nuclear plant investments, purchased-power settlements and
flow-through taxes, and decreased the PROACT balance by $256 million, all retroactive to January 1, 2002.  The
impact of the URG decision is reflected in the 2002 financial statements as a credit (decrease) to the provisions
for regulatory adjustment clauses of $644 million, partially offset by an increase in deferred income tax expense
of $164 million, for a net credit to earnings of $480 million.  As a result of the CPUC decision that modified
the PBR mechanism, SCE recorded a $136 million credit (decrease) to the provisions for regulatory adjustment
clauses in the second quarter of 2002, to reflect undercollections in CPUC-authorized revenue resulting from
changes in retail rates.

Other Operation and Maintenance Expense

Other operating and maintenance expense increased $385 million in 2004 and $137 million in 2003.  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 (see "Regulatory Matters--Other Regulatory
Matters--Catastrophic Event Memorandum Account"), 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 Corners coal facility and additional costs for 2003 incentive
compensation due to upward revisions in the computation in 2004.


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Management's Discussion and Analysis of Financial Condition and Results of Operations
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These increases were partially offset by a decrease in postretirement benefits other than pensions, including the
effects of adopting the Medicare Prescription Drug, Improvement and Modernization Act of 2003 in the third
quarter of 2004 (see "New Accounting Principles" for further discussion) and lower worker's compensation claims
in 2004.  The 2003 increase was mainly due to higher health-care costs, higher spending on certain
CPUC-authorized programs, higher transmission access charges and costs incurred in 2003 related to the removal of
dead, dying and diseased trees and vegetation associated with the bark beetle infestation.

Depreciation, Decommissioning and Amortization Expense

Depreciation, decommissioning and amortization expense decreased $22 million in 2004 and increased $102 million
in 2003.  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.  The 2003 increase was mainly due to an increase in depreciation expense associated with
SCE's additions to transmission and distribution assets, an increase in nuclear decommissioning expense,
partially offset by a change in the amortization period for SCE's San Onofre recorded in the third quarter of
2002 based on the implementation of a CPUC decision.

Other Income and Deductions

Interest and Dividend Income

Interest and dividend income decreased $80 million in 2004 and $162 million in 2003, mainly due to the absence of
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.  The 2003 decrease was also due to lower interest income from lower
average cash balances, compared to the same period in 2002.

Interest Expense - Net of Amounts Capitalized

Interest expense - net of amounts capitalized decreased $48 million in 2004 and $127 million in 2003.  The 2004
decrease was mainly 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 2003 decrease was due to higher interest
expense in 2002 resulting from the 2001 and early 2002 suspension of payments for purchased power (these
suspended payments were paid in March 2002), as well as lower interest expense on SCE's long-term debt resulting
from the early retirement of debt.  In 2003 dividend payments on certain preferred securities were reclassified
to interest expense.  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 and 2002 are not included in interest expense - net of amounts
capitalized in the consolidated statements of income.

Other Nonoperating Deductions

Other nonoperating deductions increased $46 million in 2004 and $41 million 2003.  The 2004 increase was mainly
due to a $29 million pre-tax charge for the anticipated refund of the previously received performance incentive
rewards as well as the accrual of $6 million in system reliability penalties (see "Regulatory Matters--Other
Regulatory Matters--Investigation Regarding Performance Incentive Rewards").  The 2003 increase was due to the
resolution of regulatory matters accrued for in 2002.


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                                                                                Southern California Edison Company
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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 (see "Critical Accounting Policies and Estimates" and "New Accounting
Principles").

Income Taxes

Income taxes increased $50 million in 2004 and decreased $254 million in 2003.  The 2004 increase was primarily
due to an increase in pre-tax income and the favorable resolution of a FERC rate case recorded by SCE in 2003.
The increase was partially offset by adjustments made in 2004 to accrued tax liabilities to reflect the receipt
of an IRS audit report and progress achieved in settlement negotiations for issues relating to prior year tax
liabilities.  The 2003 decrease was primarily due to reductions in pre-tax income, the favorable resolution of
tax audit issues, and the favorable resolution of a FERC rate case, partially offset by the reestablishment of
tax-related regulatory assets upon implementation of the URG decision recorded in 2002.

SCE's federal and state statutory tax rate was 40.37% for 2004 and 40.551% for the other years presented.  The
lower effective tax rate of 32.2% in 2004 was primarily due to adjustments to tax liabilities relating to prior
years, property-related flow through items and other property-related adjustments.  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
favorable resolution of tax audit issues.

Income from Discontinued Operations

SCE's income from discontinued operations in 2003, included a $44 million (after-tax) gain on the sale of SCE's
fuel oil pipeline business and operating results of $6 million.

Historical Cash Flow Analysis

Cash Flows from Operating Activities

Net cash provided by operating activities was $2.3 billion in 2004, $2.6 billion in 2003 and $548 million in
2002.  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 1, 2003.  The 2003 increase
in cash provided by operating activities from continuing operations was mainly due to SCE's March 2002 repayment
of past-due obligations.  The change during both periods was also due to timing of cash receipts and
disbursements related to working capital items.

Cash Flows from Financing Activities

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.

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 7.25% 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


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

October 2018, and $100 million of junior 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 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 million 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.

During the first quarter of 2002, SCE paid $531 million of matured commercial paper and remarketed $196 million
of the $550 million of pollution-control bonds repurchased during December 2000 and early 2001.  Also during the
first quarter of 2002, SCE replaced the $1.65 billion credit facility with a $1.6 billion financing and made a
payment of $50 million to retire the entire credit facility.  Throughout the year, SCE paid approximately $1.2
billion of maturing long-term debt.  The $1.6 billion financing included a $600 million, one-year term loan due
March 3, 2003.  SCE prepaid $300 million of this loan in August 2002.

Cash Flows from 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 $1.7 billion, $1.2 million and $1.0 billion in 2004, 2003
and 2002, respectively, primarily for transmission and distribution assets, including approximately $70 million
in 2004 for nuclear fuel acquisitions.  In addition, investing activities in 2004 include $285 million of
acquisition costs related to the Mountainview project.

Nuclear decommissioning costs are recovered in utility rates.  These costs are expected to be funded from
independent decommissioning trusts that receive SCE contributions of approximately $32 million per year.  The
fair value of decommissioning SCE's nuclear power facilities is $2.2 billion as of December 31, 2004, based on
site-specific studies performed in 2001 for San Onofre and Palo Verde.  As of December 31, 2004, the
decommissioning trust balance was $2.7 billion.  The CPUC has set certain restrictions related to the investments
of these trusts.  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.  SCE's


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                                                                                Southern California Edison Company
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costs to decommission San Onofre Unit 1 are paid from the nuclear decommissioning trust funds.  These withdrawals
from the decommissioning trusts are netted with the contributions to the trust funds in the Consolidated
Statements of Cash Flows.

DISPOSITIONS AND DISCONTINUED OPERATIONS

On July 10, 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.  Due to immateriality, the results of this unit for 2002 have not
been restated and are reflected as part of continuing operations.  For 2003, revenue from discontinued operations
was $20 million and pre-tax income was $82 million.

ACQUISITION

On March 12, 2004, SCE acquired Mountainview Power Company LLC, which owns a power plant under construction in
Redlands, California.  SCE recommenced full construction of the approximately $600 million project, which is
expected to be completed in early 2006.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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 require the
use of material judgments and estimates.

Asset Impairment

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.

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 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 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.

During the fourth quarter of 2002, SCE assessed the impairment of Mohave due to the probability of a plant
shutdown 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.  However, in accordance with accounting standards for rate-regulated
enterprises, this incurred cost was deferred and recorded in regulatory assets as a long-term receivable to be
collected from customer revenue.  This treatment was based on SCE's expectation that any unrecovered book value
at the end of 2005 would be recovered in future rates (together with a reasonable return) through a balancing
account mechanism.  See "Regulatory Matters--Generation and Power Procurement--Mohave Generating Station and
Related Proceedings," and "--Rate Regulated Enterprises."


Page 37


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



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 of the jurisdictions 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.

Management continually evaluates its income tax exposures and provides for allowances and/or reserves as deemed
necessary.

Pensions and Postretirement Benefits Other Than Pensions

Pension and other postretirement obligations and the related effects on results of operations are calculated
using actuarial models.  Two critical assumptions, discount rate and expected return on assets, are important
elements of plan expense and liability measurement.  Additionally, health care cost trend rates are critical
assumptions for postretirement 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.

The discount rate enables SCE to state expected future cash flows at a present value on the measurement date.  At
the December 31, 2004 measurement date, SCE used a discount rate of 5.5% for pensions and 5.75% for
postretirement benefits other than pensions (PBOP) that represented the market interest rate for high-quality
fixed income investments.

To determine the expected long-term rate of return on pension plan assets, current and expected asset allocations
are considered, as well as historical and expected returns on plan assets.  The expected rate of return on plan
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 12.2%, 5.0% and 11.9% for the one-year, five-year and ten-year periods ended
December 31, 2004, respectively.  Actual time-weighted, annualized returns on the PBOP plan assets were 11.4%,
1.2% and 10.1% over these same periods.  Accounting principles provide that differences between expected and
actual returns are recognized over the average future service of employees.


Page 38


                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

At December 31, 2004, SCE's pension plans had a $3.0 billion projected benefit obligation (PBO), a $2.6 billion
accumulated benefit obligation (ABO) and $3.0 billion in plan assets.  A 1% decrease in the discount rate would
increase the PBO by $246 million, and a 1% increase would decrease the PBO by $266 million, with corresponding
changes in the ABO.  A 1% decrease in the expected rate of return on plan assets would increase pension expense
by $28 million.

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 or income calculated in accordance with accounting standards is
accumulated in a regulatory asset or liability, and will, over time, be recovered from or returned to customers.
As of December 31, 2004, this cumulative difference amounted to a regulatory liability of $114 million, meaning
that the rate-making method has resulted in recognizing $114 million more in expense than the accounting method
since implementation of the pension accounting standard in 1987.

Under accounting standards, if the ABO 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 ABO.  This
assessment is performed annually.

At December 31, 2004, SCE's PBOP plans had a $2.1 billion PBO and $1.4 billion in plan assets.  Total expense for
these plans was $87 million for 2004.  Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of December 31, 2004 by $307 million and annual aggregate service and
interest costs by $27 million.  Decreasing the health care cost trend rate by one percentage point would decrease
the accumulated obligation as of December 31, 2004 by $248 million and annual aggregate service and interest
costs by $21 million.

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.  In May 2004, the Financial Accounting Standards Board (FASB) issued accounting guidance
related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.  SCE adopted this guidance
effective July 1, 2004, which resulted in a decrease of $116 million to SCE's accumulated benefit obligation for
postretirement benefits other than pensions.  SCE's 2004 expense decreased approximately $8 million as a result
of the subsidy.  According to proposed federal regulations, SCE's retiree health care plans provide prescription
drug benefits that are deemed to be actuarially equivalent to Medicare benefits.  Accordingly, SCE recognized the
subsidy in the measurement of its accumulated obligation and recorded an actuarial gain.

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.  Due to timing and other differences in the collection of revenue, these principles allow an incurred
cost that 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 specific incurred cost or a similar
incurred cost to SCE or other rate-regulated entities in California,


Page 39


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

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 expected
to allow SCE to earn a reasonable rate of return, management believes that existing regulatory assets and
liabilities are probable of recovery.  This determination reflects the current political and regulatory climate
in California and is subject to change in the future.  If future recovery of costs ceases to be probable, all or
part of the regulatory assets and liabilities would have to be written off against current period earnings.  At
December 31, 2004, the Consolidated Balance Sheets included regulatory assets of $3.8 billion and regulatory
liabilities of $3.8 billion.  Management continually evaluates the anticipated recovery of regulatory assets,
liabilities, and revenue subject to refund and provides for allowances and/or reserves as deemed necessary.

SCE applied judgment in the use of the above principles when it: (1) restored $480 million (after-tax) of
generation-related regulatory assets based on the URG decision in the second quarter of 2002; and (2) established
a $61 million regulatory asset related to the impaired Mohave in the fourth quarter of 2002.  In all instances,
SCE recorded corresponding credits to earnings upon concluding that such incurred costs were probable of recovery
in the future.  See further discussion in "Regulatory Matters--Generation and Power Procurement--Mohave Generating
Station and Related Proceedings" section.

NEW ACCOUNTING PRINCIPLES

A new accounting standard requires companies to use the fair value accounting method for stock-based
compensation.  SCE currently uses the intrinsic value accounting method for stock-based compensation.  SCE will
adopt the new method effective July 1, 2005.  The difference in expense, net of tax, between the two methods is
$4 million.  SCE is reviewing the new standard and has not yet selected a transition method for adoption of the
new standard.

In December 2004, the FASB issued guidance (Staff Position 109-1) on accounting for a tax deduction resulting
from the American Jobs Creation Act of 2004.  The primary objective of this Position is to provide guidance on
accounting for the provision within the American Jobs Creation Act of 2004 that provides a tax deduction on
qualified production activities.  Under this Position, recognition of the tax deduction on qualified production
activities, which include the production of electricity, is reported in the year it is earned.  This FASB Staff
Position had no material impact on SCE's financial statements.  SCE is evaluating the effect that the
manufacturer's deduction will have in subsequent years.

In December 2003, the FASB issued a revision to an accounting Interpretation (originally issued in January 2003),
Consolidation of VIEs.  The primary objective of the Interpretation is to provide guidance on the identification
of, and financial reporting for, VIEs, where control may be achieved through means other than voting rights.
Under the Interpretation, the enterprise that is expected to absorb or receive the majority of a VIE's expected
losses or residual returns, or both, must consolidate the VIE unless specific exceptions apply.  This
Interpretation was effective for special purpose entities, as defined by accounting principles generally accepted
in the United States, as of December 31, 2003, and all other entities as of March 31, 2004.

SCE has 270 long-term power-purchase contracts with independent power producers that own QFs.  SCE was required
under federal law to sign such contracts, which typically require SCE to purchase 100% of the power produced by
these facilities under terms and pricing controlled by the CPUC.  SCE conducted a review of its QF contracts and
determined that SCE has variable interests in 12 contracts with gas-fired cogeneration plants that are potential
VIEs and that contain variable pricing provisions based on the price of natural gas and for which SCE does not
have sufficient information to determine if the projects qualify for a scope exception.  SCE requested from the
entities that hold these contracts the financial information


Page 40


                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

necessary to determine whether SCE must consolidate these projects.  All 12 entities declined to provide SCE with
the necessary financial information.  However, four of the 12 contracts are with entities 49%-50% owned by a
related party, Edison Mission Energy (EME).  EME is an indirect wholly owned subsidiary of SCE's parent company,
Edison International.  Although the four related-party entities have declined to provide their financial
information to SCE, Edison International has access to such information and has provided combined financial
statements to SCE.  SCE has determined that it must consolidate the four power projects partially owned by EME
based on a qualitative analysis of the facts and circumstances of the entities, including the related-party
nature of the transaction.  SCE will continue to attempt to obtain information for the other eight projects in
order to determine whether they should be consolidated by SCE.

The remaining 258 contracts will not be consolidated by SCE under the new accounting standard, since SCE lacks a
variable interest in these contracts or the contracts are with governmental agencies, which are generally
excluded from the standard.

SCE analyzes its potential variable interests by calculating operating cash flows.  A fixed-price contract to
purchase electricity from a power plant does not transfer sufficient risk to SCE to be considered a variable
interest.  A contract with a non-natural-gas-fired plant that is based on the price of natural gas is also not a
variable interest.  SCE has other power contracts with non-QF generators.  SCE has determined that these
contracts are not significant variable interests.

COMMITMENTS AND INDEMNITIES

SCE's commitments for the years 2005 through 2009 and thereafter are estimated below:

In millions                                  2005         2006         2007         2008         2009    Thereafter
-------------------------------------------------------------------------------------------------------------------

Long-term debt maturities and
   sinking fund requirements(1)             $ 503      $ 1,168      $ 1,580        $ 255        $ 418    $ 5,704
Fuel supply contract payments                 173           58           65           59           36        454
Purchased-power capacity payments             898          725          648          421          394      3,059
Unconditional purchase obligations              5            5            5            5            6         43
Estimated noncancelable lease payments         48           45            9            8            5          9
Preferred stock redemption
   requirements                                 9            9           74           56           --         --
Employee benefit plans contributions(2)       109          126          127           --           --         --
-------------------------------------------------------------------------------------------------------------------

--------------
(1)  Amount includes scheduled principal payments for debt outstanding as of December 31, 2004, assuming
     long-term debt is held to maturity, and related forecast interest payments over the applicable period of the
     debt.

(2)  Amount includes estimated contributions to the pension plans and postretirement benefits other than
     pensions.  The estimated contributions beyond 2007 are not available.

Fuel Supply Contracts

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.


Page 41



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

Power Purchase 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 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 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 provider, whether or not the transmission
line is operable.

Leases

SCE has operating leases, primarily for vehicles, with varying terms, provisions and expiration dates.
Additionally, in accordance with an accounting standard, certain power contracts in which SCE takes virtually all
of the power from specific power plants are classified as operating leases.

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.





Page 42


[THIS PAGE LEFT INTENTIONALLY BLANK]








Page 43


-------------------------------------------------------------------------------------------------------------------
Report of Independent Registered Public Accounting Firm                         Southern California Edison Company




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 changes in common shareholder's equity present fairly, in all material
respects, the financial position of Southern California Edison Company and its subsidiaries at December 31, 2004
and 2003, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2004 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 1 to the consolidated financial statements, the Company changed the manner in which it
accounts for asset retirement costs as of January 1, 2003, financial instruments with characteristics of both
debt and equity as of July 1, 2003, and variable interest entities as of March 31, 2004.





/s/ PricewaterhouseCoopers LLP


Los Angeles, California
March 15, 2005




Page 44



-------------------------------------------------------------------------------------------------------------------
Consolidated Statements of Income                                               Southern California Edison Company


In millions                    Year ended December 31,                2004              2003               2002
-------------------------------------------------------------------------------------------------------------------
Operating revenue                                                 $   8,448          $   8,854          $  8,706
-------------------------------------------------------------------------------------------------------------------

Fuel                                                                    810                235               243
Purchased power                                                       2,332              2,786             2,016
Provisions for regulatory adjustment clauses - net                     (201)             1,138             1,502
Other operation and maintenance                                       2,457              2,072             1,935
Depreciation, decommissioning and amortization                          860                882               780
Property and other taxes                                                177                168               117
Net gain on sale of utility plant                                        --                 (5)               (5)
-------------------------------------------------------------------------------------------------------------------

Total operating expenses                                              6,435              7,276             6,588
-------------------------------------------------------------------------------------------------------------------

Operating income                                                      2,013              1,578             2,118
Interest and dividend income                                             20                100               262
Other nonoperating income                                                84                 72                75
Interest expense - net of amounts capitalized                          (409)              (457)             (584)
Other nonoperating deductions                                           (69)               (23)               18
-------------------------------------------------------------------------------------------------------------------

Income from continuing operations before tax
   and minority interest                                              1,639              1,270             1,889
Income tax                                                              438                388               642
Minority interest                                                       280                 --                --
-------------------------------------------------------------------------------------------------------------------

Income from continuing operations                                       921                882             1,247
Income from discontinued operations - net of tax                         --                 50                --
-------------------------------------------------------------------------------------------------------------------


Net income                                                              921                932             1,247
Dividends on preferred stock
   subject to mandatory redemption                                       --                  5                13
Dividends on preferred stock
   not subject to mandatory redemption                                    6                  5                 6
-------------------------------------------------------------------------------------------------------------------

Net income available for common stock                             $     915          $     922          $  1,228
-------------------------------------------------------------------------------------------------------------------




Consolidated Statements of Comprehensive Income

In millions                    Year ended December 31,                2004              2003               2002
-------------------------------------------------------------------------------------------------------------------

Net income                                                        $     921          $     932          $  1,247
Other comprehensive income (loss), net of tax:
   Minimum pension liability adjustment                                  (1)                (4)               (5)
   Amortization of cash flow hedges                                       3                  1                11
-------------------------------------------------------------------------------------------------------------------

Comprehensive income                                              $     923          $     929          $  1,253
-------------------------------------------------------------------------------------------------------------------



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


Page 45


-------------------------------------------------------------------------------------------------------------------
Consolidated Balance Sheets

In millions                                          December 31,                       2004                2003
-------------------------------------------------------------------------------------------------------------------
ASSETS
-------------------------------------------------------------------------------------------------------------------
Cash and equivalents                                                               $      122          $      95
Restricted cash                                                                            61                 66
Receivables, less allowances of $31 and $30
   for uncollectible accounts at respective dates                                         618                602
Accrued unbilled revenue                                                                  320                273
Fuel inventory                                                                              8                 10
Materials and supplies                                                                    188                168
Accumulated deferred income taxes - net                                                   134                563
Regulatory assets                                                                         553                299
Prepayments and other current assets                                                       72                 62
-------------------------------------------------------------------------------------------------------------------
Total current assets                                                                    2,076              2,138
-------------------------------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision
   for depreciation of $34 and $24 at respective dates                                    583                116
Property of variable interest entities - net                                              377                 --
Nuclear decommissioning trusts                                                          2,757              2,530
Other investments                                                                         170                150
-------------------------------------------------------------------------------------------------------------------
Total investments and other assets                                                      3,887              2,796
-------------------------------------------------------------------------------------------------------------------
Utility plant, at original cost:
   Transmission and distribution                                                       15,685             14,861
   Generation                                                                           1,356              1,388
Accumulated provision for depreciation                                                 (4,506)            (4,386)
Construction work in progress                                                             789                601
Nuclear fuel, at amortized cost                                                           151                141
-------------------------------------------------------------------------------------------------------------------
Total utility plant                                                                    13,475             12,605
-------------------------------------------------------------------------------------------------------------------
Regulatory assets                                                                       3,285              3,725
Other deferred charges                                                                    567                507
-------------------------------------------------------------------------------------------------------------------

Total deferred charges                                                                  3,852              4,232
-------------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------------







-------------------------------------------------------------------------------------------------------------------
Total assets                                                                       $   23,290          $  21,771
-------------------------------------------------------------------------------------------------------------------




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


Page 46


-------------------------------------------------------------------------------------------------------------------
                                                                                 Southern California Edison Company


In millions, except share amounts                    December 31,                       2004                2003
-------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
-------------------------------------------------------------------------------------------------------------------

Short-term debt                                                                    $       88          $     200
Long-term debt due within one year                                                        246                371
Preferred stock to be redeemed within one year                                              9                  9
Accounts payable                                                                          700                497
Accrued taxes                                                                             357                476
Accrued interest                                                                          115                107
Customer deposits                                                                         168                152
Book overdrafts                                                                           232                189
Regulatory liabilities                                                                    490                659
Other current liabilities                                                                 643                972
-------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                               3,048              3,632
-------------------------------------------------------------------------------------------------------------------
Long-term debt                                                                          5,225              4,121
-------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net                                                 2,865              2,726
Accumulated deferred investment tax credits                                               126                136
Customer advances and other deferred credits                                              510                428
Power-purchase contracts                                                                  130                213
Preferred stock subject to mandatory redemption                                           139                141
Accumulated provision for pensions and benefits                                           417                330
Asset retirement obligations                                                            2,183              2,084
Regulatory liabilities                                                                  3,356              3,234
Other long-term liabilities                                                               232                242
-------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                            9,958              9,534
-------------------------------------------------------------------------------------------------------------------
Total liabilities                                                                      18,231             17,287
-------------------------------------------------------------------------------------------------------------------
Commitments and contingencies (Notes 2, 9 and 10)
Minority interest                                                                         409                 --
-------------------------------------------------------------------------------------------------------------------
Common stock (434,888,104 shares outstanding at each date)                              2,168              2,168
Additional paid-in capital                                                                350                338
Accumulated other comprehensive loss                                                      (17)               (19)
Retained earnings                                                                       2,020              1,868
-------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity                                                       4,521              4,355
-------------------------------------------------------------------------------------------------------------------
Preferred stock not subject to mandatory redemption                                       129                129
-------------------------------------------------------------------------------------------------------------------
Total shareholders' equity                                                              4,650              4,484
-------------------------------------------------------------------------------------------------------------------




Total liabilities and shareholders' equity                                         $   23,290          $  21,771
===================================================================================================================



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


Page 47


-------------------------------------------------------------------------------------------------------------------
Consolidated Statements of Cash Flows

In millions                    Year ended December 31,                   2004              2003             2002
-------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Income from continuing operations                                     $   921         $     882         $  1,247
Adjustments to reconcile to net cash provided by operating activities:
   Depreciation, decommissioning and amortization                         860               882              780
   Other amortization                                                      90               101              106
   Minority interest                                                      280                --               --
   Deferred income taxes and investment tax credits                       514              (104)            (640)
   Regulatory assets - long-term                                          442               535           (6,738)
   Regulatory liabilities - long-term                                     (69)              (48)           8,589
   Other assets                                                           (77)              122               98
   Other liabilities                                                       18              (364)             135
   Receivables and accrued unbilled revenue                                (9)              185              480
   Inventory, prepayments and other current assets                        (10)               78              (86)
   Regulatory assets - short-term                                        (254)           13,268           (1,252)
   Regulatory liabilities - short-term                                   (169)          (12,486)             876
   Accrued interest and taxes                                            (111)             (223)            (191)
   Accounts payable and other current liabilities                        (152)             (181)          (2,856)
-------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities                               2,274             2,647              548
-------------------------------------------------------------------------------------------------------------------

ash flows from financing activities:
Long-term debt issued and issuance costs                                1,747               (11)             (32)
Long-term debt repaid                                                    (966)           (1,263)          (1,200)
Bonds remarketed - net                                                    350                --              191
Redemption of preferred stock                                              (2)               (6)            (100)
Rate reduction notes repaid                                              (246)             (246)            (246)
Nuclear fuel financing - net                                               --                --              (59)
Short-term debt financing - net                                          (112)               (4)            (527)
Change in book overdrafts                                                  43                65               77
Shares purchased for stock-based compensation                             (60)              (13)              (3)
Proceeds from stock option exercises                                       29                 3               --
Minority interest                                                        (290)               --               --
Dividends paid                                                           (756)             (955)             (40)
-------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities                                    (263)           (2,430)          (1,939)
-------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Capital expenditures                                                   (1,678)           (1,153)          (1,037)
Acquisition costs related to nonutility generation plant                 (285)               --               --
Proceeds from sale of discontinued operations                              --               146               --
Contributions to and earnings from
   nuclear decommissioning trusts - net                                  (109)              (86)             (12)
Sales of investments in other assets                                        9                13               18
-------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities                                  (2,063)           (1,080)          (1,031)
-------------------------------------------------------------------------------------------------------------------
Effect of consolidation of variable interest entities                      79                --               --
-------------------------------------------------------------------------------------------------------------------
Net change in cash of discontinued operations                              --               (34)              --
-------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents                            27              (897)          (2,422)
Cash and equivalents, beginning of year                                    95               992            3,414
-------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of year-continuing operations               $   122         $      95         $    992
===================================================================================================================


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


Page 48


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

                                                                           Accumulated                    Total
                                                          Additional          Other                      Common
                                              Common        Paid-in       Comprehensive   Retained    Shareholder's
In millions                                    Stock        Capital       Income (Loss)   Earnings       Equity
--------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001                 $ 2,168        $ 336           $  (22)      $   664         $ 3,146
--------------------------------------------------------------------------------------------------------------------

Net income                                                                                 1,247           1,247
Minimum pension liability adjustment                                            (9)                           (9)
   Tax effect                                                                    4                             4
Amortization of cash flow hedges                                                 4                             4
   Tax effect                                                                    7                             7
Dividends accrued on preferred stock
   subject to mandatory redemption                                                           (13)            (13)
Dividends accrued on preferred stock
   not subject to mandatory redemption                                                        (6)             (6)
Shares purchased for stock-based compensation                  (3)                                            (3)
Non-cash stock-based compensation                               8                                              8
Capital stock expense and other                                (1)                                            (1)
--------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002                 $ 2,168        $ 340           $  (16)      $ 1,892         $ 4,384
--------------------------------------------------------------------------------------------------------------------
Net income                                                                                   932             932
Minimum pension liability adjustment                                            (7)                           (7)
   Tax effect                                                                    3                             3
Amortization of cash flow hedges                                                 2                             2
   Tax effect                                                                   (1)                           (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 subject 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                                              2
-------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2003                 $ 2,168        $ 338           $  (19)      $ 1,868         $ 4,355
--------------------------------------------------------------------------------------------------------------------
Net income                                                                                   921             921
Minimum pension liability adjustment                                            (1)                           (1)
Amortization of cash flow hedges                                                 5                             5
   Tax effect                                                                   (2)                           (2)
Dividends declared on common stock                                                          (750)           (750)
Dividends declared on preferred stock
   not subject to mandatory redemption                                                        (6)             (6)
Shares purchased 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              --
-------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2004                 $ 2,168        $ 350           $  (17)      $ 2,020         $ 4,521
--------------------------------------------------------------------------------------------------------------------
Authorized common stock is 560 million shares with no par value.


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



Page 49


-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

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

Note 1.  Summary of Significant Accounting Policies

Southern California Edison Company (SCE) is a rate-regulated electric utility that supplies 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) for
which SCE is the primary beneficiary.  Effective March 31, 2004, SCE began consolidating four cogeneration
projects for which SCE typically purchases 100% of the energy produced under long-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 United States, 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 Regulatory Commission (FERC).  In 1997, due to changes
in the rate recovery of generation-related assets, SCE began using accounting principles applicable to
enterprises in general for its investment in generation facilities.  In April 2002, SCE reapplied accounting
principles for rate-regulated enterprises to assets that were returned to cost-based regulation under the
utility-retained generation decision.

Certain prior-period amounts were reclassified to conform to the December 31, 2004 financial statement
presentation.

Financial statements prepared in compliance with accounting principles generally accepted in the United States
require management to make estimates and assumptions that affect the amounts reported in the financial statements
and Notes.  Actual results could differ from those estimates.  Certain significant estimates related to
regulatory matters, financial instruments, income taxes, pensions and postretirement benefits other than
pensions, decommissioning and contingencies are further discussed in Notes 2, 3, 6, 7, 9 and 10 to the
Consolidated Financial Statements, respectively.

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

Business Segments

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.  Electric utility segment revenue was $8.2 billion in 2004.
Electric utility segment assets were $22.8 billion as of December 31, 2004.  Electric utility income was 100% of
SCE's net income in 2004.  Additional details on the VIE segment are shown under the heading "Variable Interest
Entities" in this Note.  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 performance.

Cash Equivalents

Cash equivalents include other investments of $64 million at December 31, 2003 with original maturities of three
months or less.  There were no cash equivalents at December 31, 2004.  Additionally, at December 31,


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

2004, the VIE segment had $90 million in cash and equivalents.  For a discussion of restricted cash, see
"Restricted Cash."

Debt and Equity Investments

Unrealized gains and losses on decommissioning trust funds increase or decrease the related regulatory asset or
liability.  All investments are classified 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 December 31, 2004, SCE's 13-month
weighted-average common equity component of total capitalization was 50.5%.  At December 31, 2004, SCE had the
capacity to pay $222 million in additional dividends based on the 13-month weighted-average method.  Based on
recorded December 31, 2004 balances, SCE's common equity to total capitalization ratio was 50.4% for ratemaking
purposes.  SCE had the capacity to pay $213 million of additional dividends to Edison International based on
December 31, 2004 recorded balances.

Inventory

Inventory is stated at the lower of cost or market, cost being determined by the first in, first out method for
fuel and the average cost method for materials and supplies.

New Accounting Principles

A new accounting standard requires companies to use the fair value accounting method for stock-based
compensation.  SCE currently uses the intrinsic value accounting method for stock-based compensation.  SCE will
adopt the new method effective July 1, 2005.  The difference in expense between the two methods is shown in Note
1 under "Stock-Based Compensation."  SCE is reviewing the new standard and has not yet selected a transition
method for adoption of the new standard.

In December 2004, the Financial Accounting Standards Board (FASB) issued guidance (Staff Position 109-1) on
accounting for a tax deduction resulting from the American Jobs Creation Act of 2004.  The primary objective of
this Position is to provide guidance on accounting for the provision within the American Jobs Creation Act of 2004
that provides a tax deduction on qualified production activities.  Under this Position, recognition of the tax
deduction on qualified production activities, which include the production of electricity, is reported in the
year it is earned.  This FASB Staff Position had no material impact on SCE's financial statements.  SCE is
evaluating the effect that the manufacturer's deduction will have in subsequent years.

In December 2003, the FASB issued a revision to an accounting Interpretation (originally issued in January 2003),
Consolidation of VIEs.  The primary objective of the Interpretation is to provide guidance on the identification
of, and financial reporting for, VIEs, where control may be achieved through means other than voting rights.
Under the Interpretation, the enterprise that is expected to absorb or receive the majority of a VIE's expected
losses or residual returns, or both, must consolidate the VIE unless specific exceptions apply.  This
Interpretation was effective for special purpose entities, as defined by accounting principles generally accepted
in the United States, as of December 31, 2003, and all other entities as of March 31, 2004.


Page 51


-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

SCE has 270 long-term power-purchase contracts with independent power producers that own qualifying facilities
(QFs).  SCE was required under federal law to sign such contracts, which typically require SCE to purchase 100%
of the power produced by these facilities under terms and pricing controlled by the CPUC.  SCE conducted a review
of its QF contracts and determined that SCE has variable interests in 12 contracts with gas-fired cogeneration
plants that are potential VIEs and that contain variable pricing provisions based on the price of natural gas and
for which SCE does not have sufficient information to determine if the projects qualify for a scope exception.
SCE requested from the entities that hold these contracts the financial information necessary to determine
whether SCE must consolidate these projects.  All 12 entities declined to provide SCE with the necessary
financial information.  However, four of the 12 contracts are with entities 49%-50% owned by a related party,
Edison Mission Energy (EME).  EME is an indirect wholly owned subsidiary of SCE's parent company, Edison
International.  Although the four related-party entities have declined to provide their financial information to
SCE, Edison International has access to such information and has provided combined financial statements to SCE.
SCE has determined that it must consolidate the four power projects partially owned by EME based on a qualitative
analysis of the facts and circumstances of the entities, including the related-party nature of the transaction.
SCE will continue to attempt to obtain information for the other eight projects in order to determine whether
they should be consolidated by SCE.

The remaining 258 contracts will not be consolidated by SCE under the new accounting standard, since SCE lacks a
variable interest in these contracts or the contracts are with governmental agencies, which are generally
excluded from the standard.

SCE analyzes its potential variable interests by calculating operating cash flows.  A fixed-price contract to
purchase electricity from a power plant does not transfer sufficient risk to SCE to be considered a variable
interest.  A contract with a non-natural-gas-fired plant that is based on the price of natural gas is also not a
variable interest.  SCE has other power contracts with non-QF generators.  SCE has determined that these
contracts are not significant variable interests.

See "Variable Interest Entities" for further information.

Effective July 1, 2003, SCE adopted a new accounting standard, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity, which required issuers to classify certain freestanding financial
instruments as liabilities.  These freestanding liabilities include mandatorily redeemable financial instruments,
obligations to repurchase the issuer's equity shares by transferring assets and certain obligations to issue a
variable number of shares.  Effective July 1, 2003, SCE reclassified its preferred stock subject to mandatory
redemption to the liabilities section of its consolidated balance sheet.  These items were previously classified
between liabilities and equity.  In addition, effective July 1, 2003, dividend payments on these instruments were
included in interest expense - net of amounts capitalized on SCE's consolidated statements of income.  Prior
period financial statements were not permitted to be restated for these changes.  Therefore, upon adoption there
was no cumulative impact incurred due to this accounting change.  See disclosures regarding preferred stock in
Note 3.

Nuclear

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.


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                                                                                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 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.

Other Nonoperating Income and Deductions

Other nonoperating income and deductions are as follows:

         In millions         Year ended December 31,                   2004           2003           2002
----------------------------------------------------------------------------------------------------------

         Property condemnation settlement                            $   --          $  --         $   38
         Allowance for funds used during construction                    35             27             19
         Performance-based incentive awards                              31             21             --
         Other                                                           18             24             18
----------------------------------------------------------------------------------------------------------

         Total other nonoperating income                             $   84          $  72         $   75
----------------------------------------------------------------------------------------------------------

         Provisions for regulatory issues and refunds                $   --          $  --         $  (42)
         Various penalties                                               35             --             --
         Other                                                           34             23             24
----------------------------------------------------------------------------------------------------------

         Total other nonoperating deductions                         $   69          $  23         $  (18)
----------------------------------------------------------------------------------------------------------


Planned Major Maintenance

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

Property and 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.  AFUDC is capitalized during
plant construction and reported in current earnings in other nonoperating income.  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.

Depreciation expense stated as a percent of average original cost of depreciable utility plant was 3.9% for 2004,
4.3% for 2003 and 4.2% for 2002.

AFUDC - equity was $23 million in 2004, $21 million in 2003 and $11 million in 2002.  AFUDC - debt was $12
million in 2004, $6 million in 2003 and $8 million in 2002.

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


Page 53



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

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

----------------------------------------------------------------------------------------
           Generation plant                                     38 years to 81 years
           Distribution plant                                   24 years to 53 years
           Transmission plant                                   40 years to 60 years
           Nonutility property                                   5 years to 60 years
           Other plant                                           5 years to 40 years
----------------------------------------------------------------------------------------

SCE's net investment in generation-related utility plant was $920 million at December 31, 2004 and $867 million
at December 31, 2003.

Nuclear fuel is recorded as utility plant in accordance with CPUC rate-making procedures.

Nonutility property, including construction in progress, is capitalized at cost, including interest accrued on
borrowed funds that finance construction.  Capitalized interest was $9 million in 2004, zero in 2003 and $1
million in 2002.  The Mountainview power plant is included in nonutility property in accordance with the
rate-making treatment.

As a result of an accounting standard adopted in 2003, SCE recorded the fair value of its liability for legal
asset retirement obligations (ARO), 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-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.  Prior to this standard, SCE had recorded these amounts in
accumulated provision for depreciation and decommissioning.  SCE follows accounting principles for rate-regulated
enterprises and receives recovery of these costs through rates; therefore, implementation of this new standard
did not affect earnings.

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

     In millions
------------------------------------------------------------------------------------------
     Initial ARO liability as of January 1, 2003                                $     --
     Adoption of new standard                                                      2,024
     Accretion expense                                                               128
     Liabilities settled                                                             (68)
------------------------------------------------------------------------------------------
     ARO liability as of December 31, 2003                                         2,084
     Accretion expense                                                               132
     Liabilities settled                                                             (33)
------------------------------------------------------------------------------------------
     ARO liability as of December 31, 2004                                      $  2,183
------------------------------------------------------------------------------------------
     Fair value of nuclear decommissioning trusts                               $  2,757
------------------------------------------------------------------------------------------

Purchased Power

From January 17, 2001 to December 31, 2002, the California Department of Water Resources (CDWR) purchased power
on behalf of SCE's customers for SCE's residual net short power position (the amount of energy needed to serve
SCE's customers in excess of SCE's own generation and purchased power


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

contracts).  Additionally, the CDWR signed long-term contracts which provide power for SCE's customers.
Effective January 1, 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 revenue not
collected 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.

Regulatory Assets and Liabilities

In accordance with accounting principles for rate-regulated enterprises, SCE records regulatory assets, which
represent probable future recovery of certain costs from customers through the rate-making process, and
regulatory liabilities, which represent probable future credits to customers through the rate-making process.

Included in these regulatory assets and liabilities are SCE's regulatory balancing accounts. Sales balancing
accounts accumulate differences between recorded revenue and revenue SCE is authorized to 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 assets.  Overcollections are
recorded as regulatory balancing account liabilities.  SCE's regulatory balancing 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, distribution-cost related, transmission-cost related or
public purpose and other cost related.

Balancing 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 are deferred.


Page 55



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

Regulatory Assets

Regulatory assets included in the consolidated balance sheets are:

     In millions                    December 31,                                     2004              2003
-------------------------------------------------------------------------------------------------------------------
     Current:
       Regulatory balancing accounts                                              $    371       $     140
       Direct access procurement charges                                               109              90
       Purchased-power settlements                                                      62              57
       Other                                                                            11              12
-------------------------------------------------------------------------------------------------------------------
                                                                                       553             299
-------------------------------------------------------------------------------------------------------------------
     Long-term:
       Flow-through taxes - net                                                      1,018             974
       Rate reduction notes - transition cost deferral                                 739             985
       Unamortized nuclear investment - net                                            526             583
       Nuclear-related ARO investment - net                                            272             288
       Unamortized coal plant investment - net                                          78              66
       Unamortized loss on reacquired debt                                             250             222
       Direct access procurement charges                                               141             250
       Environmental remediation                                                        55              71
       Purchased-power settlements                                                      91             153
       Other                                                                           115             133
-------------------------------------------------------------------------------------------------------------------
                                                                                     3,285           3,725
-------------------------------------------------------------------------------------------------------------------
     Total Regulatory Assets                                                      $  3,838       $   4,024
-------------------------------------------------------------------------------------------------------------------

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 1 year to 31 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.


Page 56


                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

Regulatory Liabilities

Regulatory liabilities included in the consolidated balance sheets are:

     In millions                    December 31,                                      2004            2003
-------------------------------------------------------------------------------------------------------------------
     Current:
       Regulatory balancing accounts                                              $    357       $     549
       Direct access procurement charges                                               109              90
       Other                                                                            24              20
-------------------------------------------------------------------------------------------------------------------
                                                                                       490             659
-------------------------------------------------------------------------------------------------------------------
     Long-term:
       ARO                                                                             819             720
       Costs of removal                                                              2,112           2,020
       Direct access procurement charges                                               141             250
       Employee benefits plans                                                         200             207
       Other                                                                            84              37
-------------------------------------------------------------------------------------------------------------------
                                                                                     3,356           3,234
-------------------------------------------------------------------------------------------------------------------
     Total Regulatory Liabilities                                                 $  3,846       $   3,893
-------------------------------------------------------------------------------------------------------------------

SCE's regulatory liability related to the ARO represents timing differences between the recognition of nuclear
decommissioning obligations 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.  Historically, these removal costs
have been recorded in accumulated depreciation; however, in accordance with recent Securities and Exchange
Commission accounting guidance, the amounts accrued in provision for depreciation for decommissioning and costs
of removal were reclassified to regulatory liabilities as of December 31, 2002.  SCE's regulatory liabilities
related to direct access procurement charges are a liability to its bundled service customers and are offset by
regulatory assets from direct access customers.  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 expense.  These balances will either be returned to
ratepayers in some future rate-making proceeding, or be charged against expense to the extent that future
expenses exceed amounts recoverable through the rate-making process.

Related Party Transactions

Four EME subsidiaries have 49% to 50% ownership in partnerships (QFs) 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 "Variable Interest Entities").

SCE holds $153 million in notes receivable from affiliates, due in June 2007.  The notes were issued by Edison
International 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 other deferred charges on the balance sheet.


Page 57



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

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.

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 in periodic
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 to a final 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 for rate-regulated enterprises, amounts currently authorized in
rates for recovery of costs to be incurred in the future are not considered as revenue until the associated costs
are incurred. Instead, these amounts are recorded as deferred revenue.  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 ($2.5 billion in 2004, $1.7 billion in 2003 and $1.4 billion in 2002) and collected
from SCE's customers for these power purchases, CDWR bond-related costs (effective November 15, 2002) and direct
access exit fees (effective January 1, 2003) are being remitted to the CDWR and are not recognized as revenue to
SCE.

Stock-Based Compensation

SCE has stock-based compensation plans, which are described more fully in Note 7.  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,                 2004           2003             2002
----------------------------------------------------------------------------------------------------------
         Net income available
             for common stock, as reported                        $   915          $ 922          $ 1,228
         Add:  stock-based compensation expense using
             the intrinsic value accounting method - net of tax        28              7                7
         Less:  stock-based compensation expense using
             the fair-value accounting method - net of tax             32              9                5
----------------------------------------------------------------------------------------------------------
         Pro forma net income
            available for common stock                            $   911          $ 920          $ 1,230
----------------------------------------------------------------------------------------------------------



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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

Supplemental Accumulated Other Comprehensive Loss Information

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

     In millions                      December 31,                                 2004            2003
--------------------------------------------------------------------------------------------------------
     Minimum pension liability - net                                            $  (10)        $   (9)
     Unrealized losses on cash flow hedges - net                                    (7)           (10)
--------------------------------------------------------------------------------------------------------
     Accumulated other comprehensive loss                                       $  (17)        $  (19)
--------------------------------------------------------------------------------------------------------

The minimum pension liability is discussed in Note 7, Compensation and Benefit Plans.

Unrealized 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 $7 million (as of December 31, 2004, 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 will be reclassified into earnings during 2005.

Supplemental Cash Flows Information

SCE supplemental cash flows information is:

     In millions               Year ended December 31,                            2004        2003        2002
-----------------------------------------------------------------------------------------------------------------
     Cash payments for interest and taxes:
     Interest - net of amounts capitalized                                    $    342      $  390    $    487
     Tax payments                                                                   29         585       1,110

     Non-cash investing and financing activities:
     Details of consolidation of variable interest entities:
        Assets                                                                $    458          --          --
        Liabilities                                                               (537)         --          --

     Reoffering of pollution-control bonds                                    $    196          --          --

     Details of pollution-control bonds redemption:
       Release of funds held in trust                                         $     20          --          --
       Pollution-control bonds redeemed                                            (20)         --          --

     Details of debt exchange:
       Retirement of senior secured credit facility                           $     --      $ (700)         --
       Short-term credit facility utilized                                          --         200          --
-----------------------------------------------------------------------------------------------------------------
       Cash paid                                                                    --        (500)         --
-----------------------------------------------------------------------------------------------------------------

     Details of long-term debt exchange offer:
       Variable rate notes redeemed                                           $     --      $ (966)         --
       First and refunding mortgage bonds issued                                    --         966          --

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

     Details of senior secured credit facility transaction:
       Retirement of credit facility                                                --          --    $ (1,650)
       Senior secured credit facility replacement                                   --          --       1,600
-----------------------------------------------------------------------------------------------------------------
     Cash paid on retirement of credit facility                                     --          --         (50)
-----------------------------------------------------------------------------------------------------------------



Page 59




-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

Variable Interest Entities

SCE has variable interests in contracts with certain QFs that contain variable contract pricing provisions based
on the price of natural gas.  Further, four of these contracts are with entities that are partnerships owned in
part by a related party, EME.  These four contracts have 20-year terms.  The QFs sell electricity to SCE and
steam to nonrelated parties.  Under a new accounting standard, SCE consolidated these four projects effective
March 31, 2004.  Prior periods have not been restated.

     Project                    Capacity              Termination Date            EME Ownership
     -------                    --------              ---------------             -------------
     Kern River                  300 MW                  August 2005                   50%
     Midway-Sunset               225 MW                   May 2009                     50%
     Sycamore                    300 MW                 December 2007                  50%
     Watson                      385 MW                 December 2007                  49%

SCE has no investment in, nor obligation to provide support to, these entities other than its requirement 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.

SCE has no controlling ownership interest in the four entities that have been consolidated under the new
accounting Interpretation and has no legal or contractual rights to compel these entities to provide information
to SCE.  As a result, SCE has no legal, contractual or other right to design, establish, maintain or evaluate the
effectiveness of internal controls over financial reporting for these consolidated variable interest entities.
Accordingly, SCE did not include these variable interest entities in its conclusion regarding internal controls
over financial reporting.

The variable interest entities' operating costs, instead of purchased power expense, are shown in SCE's income
statements effective April 1, 2004.  Further, SCE's operating revenue now includes revenue from the sale of steam
by these four projects.  The table below shows the effect on SCE's consolidated statement of income now that
these variable interest entities are consolidated.

     In millions               Year ended December 31,                              2004
------------------------------------------------------------------------------------------
     Operating revenue                                                           $   285
------------------------------------------------------------------------------------------
     Fuel                                                                            578
     Purchased power                                                                (669)
     Other operation and maintenance                                                  68
     Depreciation, decommissioning and amortization                                   28
------------------------------------------------------------------------------------------
     Total operating expenses                                                          5
------------------------------------------------------------------------------------------
     Operating income                                                                280
     Minority interest                                                              (280)
------------------------------------------------------------------------------------------
     Income from continuing operations                                           $    --
------------------------------------------------------------------------------------------



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The table below shows the effect on SCE's consolidated balance sheet now that these variable interest entities
are consolidated.

     In millions                    December 31,                                                 2004
-----------------------------------------------------------------------------------------------------
     ASSETS
     Cash                                                                                      $   90
     Accounts receivable - net                                                                     49
     Other current assets                                                                          18
     Nonutility property - less accumulated provision for depreciation of $519                    377
     Deferred charges                                                                               5
-----------------------------------------------------------------------------------------------------
     Total assets                                                                              $  539
-----------------------------------------------------------------------------------------------------
     LIABILITIES AND SHAREHOLDER'S EQUITY
     Accounts payable                                                                          $   62
     Other current liabilities                                                                      2
     Long-term debt (5.0%, due 2008)                                                               54
     Deferred credits                                                                              12
     Minority interest                                                                            409
-----------------------------------------------------------------------------------------------------
     Total liabilities and shareholder's equity                                                $  539
-----------------------------------------------------------------------------------------------------

As noted under New Accounting Principles, SCE also has eight other contracts with certain 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 will
continue to attempt to obtain information for these projects in order to determine whether they should be
consolidated by SCE.  The aggregate capacity dedicated to SCE for these projects is 267 MW.  SCE paid
$166 million in 2004 to these projects.  These amounts are recoverable in utility customer rates.  SCE has no
exposure to loss as a result of its involvement with these projects.

Note 2.  Regulatory Matters

CDWR Power Purchases and Revenue Requirement Proceedings

In accordance with an emergency order by the Governor of California, the CDWR began making emergency power
purchases for SCE's customers on January 17, 2001.  In February 2001, a California law was enacted which
authorized the CDWR to: (1) enter into contracts to purchase electric power and sell power at cost directly to
SCE's retail customers; and (2) issue bonds to finance those electricity purchases.  The CDWR's total statewide
power charge and bond charge revenue requirements are allocated by the CPUC among the customers of SCE, Pacific
Gas and Electric (PG&E) and San Diego Gas & Electric (SDG&E) (collectively, the investor-owned utilities).
Amounts billed to SCE's customers for electric power purchased and sold by the CDWR (approximately $2.5 billion in
2004) are remitted directly to the CDWR and are not recognized as revenue by SCE and therefore have no impact on
SCE's earnings.

In December 2004, the CPUC issued its decision on how the CDWR's power charge revenue requirement for 2004
through 2013, when the last CDWR contract expires, will be allocated among the investor-owned utilities.  The
CPUC rejected a settlement agreement among PG&E, the Utility Reform Network (TURN), and SCE and which the ORA
supported.  However, the CPUC's final decision adopts key attributes of that settlement agreement.  It adopts a
cost-follows-contract allocation to each of the


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Notes to Consolidated Financial Statements

investor-owned utilities of the unavoidable portion of costs incurred under CDWR contracts.  A previous CPUC
decision allocated the avoidable portion of the costs on a cost-follows-contract basis.  Allocating the avoidable
and unavoidable portions on a cost-follows-contract basis provides the investor-owned utilities the appropriate
incentives to operate and administer the contracts that have been allocated to them.  In addition, in order to
fairly allocate the total burden of the CDWR contracts among the investor-owned utilities, the decision adjusts
the cost-follows-contract allocation of the total costs (avoidable and unavoidable) such that the above-market
cost burden associated with the contracts is allocated as follows:  44.8% to PG&E's customers, 45.3% to SCE's
customers, and 9.9% to SDG&E's customers.  The CPUC's December 2004 decision is based on the above market cost
analysis that SCE presented in its initial testimony in December 2003.

In response to an application filed by SDG&E, the CPUC issued an order granting limited rehearing of the December
2004 decision.  The rehearing permits parties to present alternative methodologies and updated data for the
calculation of above market costs associated with the CDWR contracts.  A schedule has not been adopted for the
rehearing, but it is expected to take place in the second quarter of 2005.

SDG&E has also filed a petition for modification of the decision urging the CPUC to replace the adopted
methodology with a methodology that would retain the cost-follows-contract allocation of the avoidable costs, but
would allocate the unavoidable costs associated with the contracts:  42.2% to PG&E's customers, 47.5% to SCE's
customers, and 10.3% to SDG&E's customers.  Such an allocation would decrease the total costs allocated to
SDG&E's customers and increase the total costs allocated to SCE's customers.  The CPUC is expected to act on the
petition in March 2005.

CPUC Litigation Settlement Agreement

In October 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC which sought full
recovery of its electricity procurement costs incurred during the energy crisis.  A key element of the 2001 CPUC
settlement agreement was the establishment of a regulatory balancing account, called the Procurement-Related
Obligations Account (PROACT), which was fully recovered by August 2003.

Energy Resource Recovery Account Proceedings

In an October 2002 decision, the CPUC established the ERRA as the rate-making mechanism to track and recover
SCE'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) new 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).  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.  As these costs
are subsequently incurred, they will be tracked and recovered 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 procurement costs, SCE can request an emergency rate adjustment in addition to
the annual forecast and reasonableness ERRA applications.

ERRA Reasonableness Review for the Period September 1, 2001 through June 30, 2003

On October 3, 2003, SCE submitted its first ERRA reasonableness review application requesting that the CPUC find
its procurement-related operations during the period from September 1, 2001 through June 30, 2003 to be
reasonable.  The CPUC's Office of Ratepayer Advocates (ORA) was allowed to review the accounting calculations
used in the PROACT mechanism.  The ORA recommended


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disallowances that totaled approximately $14 million of costs recovered through the PROACT mechanism during the
period from September 1, 2001 through June 30, 2003.  In April 2004, SCE reached an agreement with the ORA
(subject to CPUC approval) to reduce the PROACT disallowances to approximately $4 million.  On January 27, 2005,
the CPUC issued a decision approving the agreement.  The $4 million, which is mainly comprised of ISO grid
management charges and employee-related retraining costs, will be refunded to ratepayers through a credit to the
ERRA.

The January 27, 2005 CPUC decision also provides that SCE's administration of its procurement contracts will be
subject to reasonableness review under the "reasonable manager" standard.  However, the CPUC decision provides
that the review of SCE's daily dispatch of its generation resources will be subject to a compliance review, not a
reasonableness review, and will only include a review of spot market transactions in the day-ahead, hour-ahead
and real-time markets.  The decision found that SCE's daily dispatch decisions during the record period complied
with the CPUC's standard, and that its administration of its contracts was reasonable in all respects.  It
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 pre-tax net regulatory gain of
$118 million in 2004.

ERRA Reasonableness Review for the Period July 1, 2003 through December 31, 2003

On April 1, 2004, SCE submitted its second ERRA reasonableness review application requesting that the CPUC find
its procurement-related operations during the period from July 1, 2003 through December 31, 2003, to be
reasonable.  In addition, SCE requested recovery of a $10 million reward for Palo Verde Unit 3 efficient
operation and $5 million in electric energy transaction administration costs.

On January 17, 2005, the CPUC issued a decision finding that SCE's administration of its power purchase
agreements and its daily decisions dispatching its procurement resources were reasonable and prudent.  The
decision also found that the revenue and expenses recorded in SCE's ERRA account during the record period were
reasonable and prudent, and approved SCE's requested recovery of the items discussed above.

Generation Procurement Proceedings

SCE resumed power procurement responsibilities for its net-short position (expected load requirements exceed
generation supply) on January 1, 2003, pursuant to CPUC orders and California statutes passed in 2002.  The
current regulatory and statutory framework requires SCE to assume limited responsibilities for CDWR contracts
allocated by the CPUC, and provide full power procurement responsibilities on the basis of annual short-term
procurement plans, long-term resource plans and increased procurement of renewable resources.  Currently, the
CPUC and the California Energy Commission are working together to set rules for various aspects of generation
procurement which are described below.

Procurement Plan

Resource Planning Component of the Procurement Plan
---------------------------------------------------

On April 1, 2004, the CPUC instituted a resource planning proceeding that, among other things, will coordinate
consideration of long-term resource plans.  On July 9, 2004, SCE filed testimony on its long-term procurement
plan, which includes a substantial commitment to cost-effective energy efficiency and an advanced load-control
program.  A CPUC decision approving SCE's long-term procurement plan was issued in December 2004.  The decision
required all long-term procurement to be conducted through


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-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

all-source solicitations; allowed the consideration of debt equivalence in the bid evaluation process; and
required the use of a greenhouse gas adder as a bid evaluation component.  The decision also extended the
utilities' authority to procure longer-term products and lifted the affiliate ban on long-term power products.
SCE's next long-term procurement plan will be filed in 2006.

Assembly Bill 57 Component of the Procurement Plan
--------------------------------------------------

In December 2003, the CPUC adopted a 2004 short-term procurement plan for SCE which established a target level
for spot market purchases equal to 5% of monthly need, and allowed SCE to enter into contracts of up to five
years.  Currently, SCE is operating under this approved short-term procurement plan.  To the extent SCE procures
power in accordance with the plan, SCE receives full-cost recovery of its procurement transactions pursuant to
Assembly Bill 57.  Accordingly, the plan is referred to as the Assembly Bill 57 component of the procurement
plant.

Each quarter, SCE is required to file a report with the CPUC demonstrating that SCE's procurement-related
transactions associated with serving the demands of its bundled electricity customers were in conformance with
SCE's adopted short-term procurement plan.  SCE has submitted seven quarterly compliance filings covering the
period from January 1, 2003 through September 30, 2004, including its third quarter 2004 compliance filing on
November 1, 2004.  To date, however, the CPUC has only issued one resolution approving SCE's first compliance
report for the period January 1, 2003 to March 31, 2003.  While SCE believes that all of its procurement
transactions were in compliance with its adopted short-term procurement plan, SCE cannot predict with certainty
whether or not the CPUC will agree with SCE's interpretation regarding some elements.

Resource Adequacy Requirements

Under the framework adopted in the CPUC's January 22, 2004 decision, all load-serving entities in California have
an obligation to procure sufficient resources to meet their customers' needs.  On October 28, 2004, the CPUC
issued a decision clarifying the January 2004 decision.  The October 2004 decision requires load-serving entities
to ensure that adequate resources have been contracted to meet that entity's peak forecasted energy resource
demand and an additional planning reserve margin of 15-17% of that peak load by June 1, 2006.  Currently, the
decision requires SCE to demonstrate that it has contracted 90% of its May-September 2006 resource adequacy
requirement by September 30, 2005.  As the May-September period approaches, SCE will be required to fill out the
remaining 10% of its resource adequacy requirement one month in advance of expected need.  The October 28, 2004
decision also clarified that although the first compliance filing will only cover May-September 2006, the 15-17%
planning reserve margin is a year-round requirement.  In its October 2004 decision, the CPUC also decided that
long-term CDWR contracts allocated to the investor-owned utilities during the 2001 energy crisis are to be fully
counted for resource adequacy purposes, and that deliverability standards developed during subsequent phases will
be applied to such contracts.  These deliverability standards, as well as a wide range of other issues, including
scheduling and load forecasting, will be addressed in a separate phase of the proceeding which is expected to be
completed by mid-2005.  SCE expects to meet its resource adequacy requirements by the deadlines set forth in the
decision.

Avoided Cost Proceeding

SCE purchases electric energy and capacity from various QFs pursuant to contracts that provide for payment at
avoided cost, as determined by the CPUC.  On April 22, 2004, the CPUC opened a rulemaking to develop, review and
update methodologies for determining avoided costs, including the methodologies SCE uses to pay its QFs.  Among
other things, the rulemaking is to consider modifications to the current methodology for short-run avoided cost
energy pricing and the current as-available


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capacity pricing.  The rulemaking also proposes to develop a long-run avoided cost pricing methodology for QFs.
Hearings are scheduled for May 2005.  Although the rulemaking may affect the amounts paid to QFs and customer
rates, changes to pricing methodology should not affect SCE's earnings as such costs are recovered from
ratepayers, subject to reasonableness review.

Extension of QF Contracts and New QF Contracts

SCE has 270 power-purchase contracts with QFs, a number of which will expire in the next five years.  On
September 30, 2004, the CPUC issued a ruling requesting proposals and comments on the development of a long-term
policy for expiring QF contracts and new QFs.  SCE filed its response to the ruling on November 10, 2004, in
which it proposed to purchase electricity from QFs by (1) allowing QFs to compete in SCE's competitive
solicitations; (2) conducting bilateral negotiations for new contracts or contract extensions with QFs; or (3)
offering an energy-only contract at market-based avoided cost prices.  Hearings are scheduled for May 2005.

Procurement of Renewable Resources

As part of SCE's resumption of power procurement, and in accordance with a California statute passed in 2002, SCE
is required to increase its procurement of renewable resources by at least 1% of its annual electricity sales per
year so that 20% of its annual electricity sales are procured from renewable resources by no later than
December 31, 2017.  At year-end 2004, SCE obtained approximately 18% of its power supplies from renewable
resources.  In June 2003, the CPUC issued a decision adopting preliminary rules and guidance on renewable
procurement-related issues, including penalties for noncompliance with renewable procurement targets.  In June
2004, the CPUC issued two decisions adopting additional rules on renewable procurement: a decision adopting
standard contract terms and conditions and a decision adopting a market-price methodology.  In July 2004, the
CPUC issued a decision adopting criteria for the selection of least-cost and best-fit renewable resources.  In
December 2004, an assigned commissioner's ruling and scoping memo was issued establishing a schedule for
addressing various renewable procurement-related issues that were not resolved by prior rulings and decision and
directing the utilities to file renewable procurement plans addressing their 2005 renewable procurement goals and
a plan for renewable procurement over the period 2005-2014.  SCE's 2005 renewable procurement plan was filed on
March 7, 2005.

SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and
conducted negotiations with bidders regarding potential procurement contracts.  On March 8, 2005, SCE filed an
advice letter with the CPUC requesting approval of 6 renewable contracts.  SCE expects a CPUC decision on its
advice letter by the second quarter of 2005.  The procedures for measuring renewable procurement are still being
developed by the CPUC.  Based upon the current regulatory framework, SCE anticipates that it will comply, even
without new renewable procurement contracts, with renewable procurement mandates through at least 2005.  Beyond
2005, SCE will either need to sign new contracts and/or extend existing renewable QF contracts.

CDWR Contract Allocation and Operating Order

The CDWR power-purchase contracts entered into as a result of the California energy crisis have been allocated on
a contract-by-contract basis among SCE, PG&E and SDG&E, in accordance with a 2002 CPUC decision.  SCE only
assumes scheduling and dispatch responsibilities and acts only as a limited agent for the CDWR for contract
implementation.  Legal title, financial reporting and responsibility for the payment of contract-related bills
remain with the CDWR.  The allocation of CDWR contracts to SCE significantly reduces SCE's residual-net short and
also increases the likelihood that SCE will have excess power during certain periods.  SCE has incorporated CDWR
contracts allocated to it in its procurement


Page 65


-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

plans.  Wholesale revenue from the sale of excess power, if any, is prorated between the CDWR and SCE.

SCE's maximum annual disallowance risk exposure for contract administration, including administration of
allocated CDWR contracts and least cost dispatch of CDWR contract resources, is $37 million.  In addition, gas
procurement, including hedging transactions, associated with CDWR contracts is included within the cap.

On January 28, 2005, the CPUC opened a new phase of its procurement proceeding to consider the reallocation of
certain CDWR contracts.  Evidentiary hearings may be held later this year.

Holding Company Proceeding

In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions
authorizing utilities to form holding companies and initiated an investigation into, among other things:
(1) whether the holding companies violated CPUC requirements to give first priority to the capital needs of their
respective utility subsidiaries; (2) any additional suspected violations of laws or CPUC rules and decisions; and
(3) whether additional rules, conditions, or other changes to the holding company decisions are necessary.

On January 9, 2002, the CPUC issued an interim decision interpreting the CPUC requirement that the holding
companies give first priority to the capital needs of their respective utility subsidiaries.  The decision stated
that, at least under certain circumstances, holding companies are required to infuse all types of capital into
their respective utility subsidiaries when necessary to fulfill the utility's obligation to serve its customers.
The decision did not determine whether any of the utility holding companies had violated this requirement,
reserving such a determination for a later phase of the proceedings.  On February 11, 2002, SCE and Edison
International filed an application before the CPUC for rehearing of the decision.  On July 17, 2002, the CPUC
affirmed its earlier decision on the first priority requirement and also denied Edison International's request
for a rehearing of the CPUC's determination that it had jurisdiction over Edison International in this
proceeding.  On August 21, 2002, Edison International and SCE jointly filed a petition in California state court
requesting a review of the CPUC's decisions with regard to first priority requirements, and Edison International
filed a petition for a review of the CPUC decision asserting jurisdiction over holding companies.  PG&E and SDG&E
and their respective holding companies filed similar challenges, and all cases have been transferred to the First
District Court of Appeals in San Francisco.

On May 21, 2004, the Court of Appeal issued its decision in the two consolidated cases, and denied the utilities'
and their holding companies' challenges to both CPUC decisions.  The Court of Appeal held that the CPUC has
limited jurisdiction to enforce in a CPUC proceeding the conditions agreed to by holding companies incident to
their being granted authority to assume ownership of a CPUC-regulated utility.  The Court of Appeal held that the
CPUC's decision interpreting the first priority requirement was not reviewable because the CPUC had not made any
ruling that any holding company had violated the first priority requirement.  However, the Court of Appeal
suggested that if the CPUC or any other authority were to rule that a utility or holding company violated the
first priority requirement, the utility or holding company would be permitted to challenge both the finding of
violation and the underlying interpretation of the first priority requirement itself.  On June 30, 2004, Edison
International and the other utility holding companies filed with the California Supreme Court a petition for
review of the Court of Appeal decision as to jurisdiction over holding companies, but they and the utilities did
not file a challenge to the decision as to the first priority issue.  On September 1, 2004, the California
Supreme Court denied the petition for review.  The Court of Appeal's decision, as to jurisdiction, is now final.


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

The original order instituting the investigation into whether the utilities and their holding companies have
complied with CPUC decisions and applicable statutes remains in effect.  However, on February 11, 2005, an
administrative law judge ruling was issued which provides that any party to the proceedings that believes the
proceedings should remain open has 30 days to file comments listing matters that remain to be decided and
explaining why they must be resolved at the CPUC rather than in another forum.  The CPUC indicated that if
comments are not received in the 30 day time period, a decision closing the proceeding will be prepared for CPUC
consideration and no further comment will be allowed.  At this time, SCE is not aware whether or not comments
have been received or whether the CPUC has taken further action.

Mohave Generating Station and Related Proceedings

On May 17, 2002, SCE filed an application with the CPUC to address certain issues (mainly coal and slurry-water
supply issues) facing any future extended operation of Mohave, which is partly owned by SCE.  Mohave obtains all
of its coal supply from the Black Mesa Mine in northeast Arizona, located on lands of the Navajo Nation and Hopi
Tribe (the Tribes).  This coal is 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.

Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water
supply issues, SCE's application stated that SCE would probably be unable to extend Mohave's operation beyond
2005.  The uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave co-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.

On December 2, 2004 the CPUC issued a final decision on the application.  Principally, the decision: (1) directs
SCE to continue the ongoing negotiations and other efforts toward resolving the post-2005 coal and water supply
issues; (2) directs SCE to conduct a study of potential generation resources that might serve as alternatives or
complements to Mohave including solar generation and coal gasification; (3) provides an opportunity for SCE to
recover in future rates certain Mohave-related costs that SCE has already incurred or is expected to incur by
2006, including certain preliminary engineering costs, water study costs and the costs of the study of potential
Mohave alternatives; and (4) authorizes SCE to establish a rate-making account to track certain worker
protection-related costs that might be incurred in 2005 in preparation for a temporary or permanent Mohave
shutdown after 2005.

In parallel with the CPUC proceeding, negotiations have continued among the relevant parties in an effort to
resolve the coal and water supply issues.  Since November 2004, the parties have engaged in negotiations
facilitated by a professional mediator, but no final resolution has been reached.  In addition, agencies of the
federal government are now conducting both a hydro-geological study and an environmental review regarding a
possible alternative groundwater source for the slurry water; these studies, projected to cost approximately $6
million, are being funded by SCE and the other Mohave co-owners subject to the terms and conditions of a 2004
memorandum of understanding among the Mohave co-owners, the Tribes and the federal government.

The outcome of the coal and water negotiations and SCE's application are not expected to 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.  The outcome of this matter is not expected to have a material impact on earnings.


Page 67



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

For additional matters related to Mohave, see "Navajo Nation Litigation" in Note 10.

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 cost was deferred and recorded in regulatory assets as a long-term receivable to be collected from
customer revenue.  This treatment was based on SCE's expectation that any unrecovered book value at the end of
2005 would be recovered in future rates (together with a reasonable return) through a balancing account
mechanism, as presented in its May 17, 2002 application and discussed in its supplemental testimony filed in
January 2003.

Wholesale Electricity and Natural Gas Markets

In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of
electricity in the California Power Exchange 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.  Under the 2001 CPUC
settlement agreement, mentioned in "CPUC Litigation Settlement Agreement," 90% of any refunds actually realized
by SCE net of costs will be refunded to customers, except for the El Paso Natural Gas Company settlement
agreement discussed below.

El Paso Natural Gas Company (El Paso) entered into a settlement agreement with a number of parties (including
SCE, PG&E, the State of California and various consumer class action representatives) settling various claims
stated in proceedings at the FERC and in San Diego County Superior Court that El Paso had manipulated interstate
capacity and engaged in other anticompetitive behavior in the natural gas markets in order to unlawfully raise
gas prices at the California border in 2000-2001.  The United States District Court has issued an order approving
the stipulated judgment and the settlement agreement has become effective.  Pursuant to a CPUC decision, SCE will
refund to customers amounts received under the terms of the El Paso settlement (net of legal and consulting
costs) through its ERRA mechanism.  In June 2004, SCE received its first settlement payment of $76 million.
Approximately $66 million of this amount was credited to purchased-power expense, and will be refunded to SCE's
ratepayers through the ERRA over the next 12 months, and the remaining $10 million was used to offset SCE's
incurred legal costs.  Additional settlement payments totaling approximately $127 million are due from El Paso
over a 20-year period.  As a result, SCE recorded a receivable and corresponding regulatory liability of $65
million in 2004 for the discounted present value of the future payments (discounted at an annual rate of 7.86%).
Amounts El Paso refunds to the CDWR will result in reductions in the CDWR's revenue requirement allocated to SCE
in proportion to SCE's share of the CDWR's power charge revenue requirement.

On July 2, 2004, the FERC approved a settlement agreement between SCE, SDG&E and PG&E and The Williams Cos. and
Williams Power Company, providing for approximately $140 million in refunds and other payments to the settling
purchasers and others against some of Williams' power charges in 2000-2001.  In August 2004, SCE received its
$37 million share of the refunds and other payments under the Williams settlement.

On April 26, 2004, SCE, PG&E, SDG&E and several California state governmental entities agreed to settlement terms
with West Coast Power, LLC and its owners, Dynegy Inc. and NRG Energy, Inc.


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                                                                                Southern California Edison Company
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(collectively, Dynegy).  The settlement terms provide for refunds and other payments totaling $285 million, with
a proposed allocation to SCE of approximately $42 million.  The Dynegy settlement terms were approved by the FERC
on October 25, 2004 and SCE received its $42 million share of the settlement proceeds in November 2004.

On July 12, 2004, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Duke Energy
Corporation and a number of its affiliates (collectively Duke).  The settlement terms agreed to with the Duke
parties provide for refunds and other payments totaling in excess of $200 million, with a proposed allocation to
SCE of approximately $45 million.  The Duke settlement was approved by the FERC on December 7, 2004 and SCE
received its $45 million share of the settlement proceeds in January 2005.

On January 14, 2005, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Mirant
Corporation and a number of its affiliates (collectively Mirant), all of whom are debtors in a Chapter 11
bankruptcy proceeding pending in Texas.  Among other things, the settlement terms provide for expected cash and
equivalent refunds totaling $320 million, of which SCE's allocated share is approximately $68 million.  The
settlement also provides for an allowed, unsecured claim totaling $175 million in the bankruptcy of one of the
Mirant parties, with SCE being allocated approximately $33 million of the unsecured claim.  The actual value of
the unsecured claim will be determined as part of the resolution of the Mirant parties' bankruptcies.  The Mirant
settlement was submitted to the FERC for its approval on January 31, 2005 and was submitted to the Mirant
bankruptcy court for its approval on February 23, 2005.

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 from energy providers and
allocating them in accordance with the terms of the CPUC litigation settlement agreement.  The resolution
accordingly provides a mechanism whereby portions of the settlement proceeds recorded in the ESMA will be
allocated to recovery of SCE's litigation costs and expenses in the FERC refund proceedings described above and
as a shareholder incentive pursuant to the CPUC litigation settlement agreement.  Remaining amounts for each
settlement are to be refunded to ratepayers through the ERRA mechanism.  In 2004, SCE recorded in the caption
"Other nonoperating income" on the income statement a total of $12 million as shareholder incentives related to
refunds received in 2004.

Note 3.  Derivative Instruments and Hedging Activities

SCE's risk management policy allows the use of derivative financial instruments to manage financial exposure on
its investments and fluctuations in interest rates and commodity prices, but prohibits the use of these
instruments for speculative purposes.

SCE is exposed to credit loss in the event of nonperformance by counterparties.  Counterparties are required to
post collateral for certain transactions depending on the creditworthiness of each counterparty and the risk
associated with the transaction.  SCE does not expect the counterparties to fail to meet their obligations.

SCE records its derivative instruments on its balance sheet 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.
Gains or losses from changes in the fair value of a recognized asset or liability or a firm commitment are
reflected in earnings for the ineffective portion of a designated hedge.  For a designated hedge of the cash
flows of a forecasted transaction, the effective portion of the gain or loss is initially recorded as a separate
component of shareholder's equity under the caption "accumulated other


Page 69



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

comprehensive income," and subsequently reclassified into earnings when the forecasted transaction affects
earnings.  The ineffective portion of a hedge is reflected in earnings immediately.  Hedge accounting requires SCE
to formally document, designate and assess the effectiveness of hedge transactions.

SCE enters into contracts for power and gas options, as well as swaps and futures, 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.

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 of these contracts that is not eligible for the normal purchases
and sales exception under accounting rules is recorded on the balance sheet at fair value.

The carrying amounts and fair values of financial instruments are:

                                                                                  December 31,
                                                              -------------------------------------------------
                                                                         2004                      2003
                                                              -------------------------------------------------
                                                              Carrying          Fair       Carrying       Fair
     In millions                                               Amount           Value       Amount        Value
---------------------------------------------------------------------------------------------------------------
     Derivatives:
       Interest rate hedges                                   $     3        $     3      $    (1)      $   (1)
       Commodity price assets                                      14             14            3            3
       Commodity price liabilities                                (12)           (12)          --           --

     Other:
       Decommissioning trusts                                   2,757          2,757        2,530        2,530
       DOE decommissioning and decontamination fees               (13)           (13)         (19)         (18)
       QF power contracts                                         (12)           (12)         (32)         (32)
       Long-term debt                                          (5,225)        (5,551)      (4,121)      (4,446)
       Long-term debt due within one year                        (246)          (254)        (371)        (377)
       Preferred stock to be redeemed within one year              (9)            (9)          (9)          (9)
       Preferred stock subject to mandatory redemption           (139)          (140)        (141)        (139)
--------------------------------------------------------------------------------------------------------------

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) decommissioning and decontamination
fees.

Due to their short maturities, amounts reported for cash equivalents approximate fair value.

Note 4.  Liabilities and Lines of Credit

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 government agencies.  SCE
used these proceeds to finance construction of pollution-control facilities.  SCE has debt covenants that require
certain interest coverage, interest and preferred dividend coverage, and debt to total capitalization ratios to
be met.  At December 31, 2004, SCE was in compliance with these debt covenants.


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

Debt premium, discount and issuance expenses are deferred and amortized through interest expense over the life of
each issue.  Under CPUC rate-making procedures, debt reacquisition expenses are amortized 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.

In December 1997, $2.5 billion of rate reduction 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 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 or Edison International.  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 or Edison
International and the transition property is legally not an asset of SCE or Edison International.

Long-term debt is:

     In millions                      December 31,                       2004                    2003
-----------------------------------------------------------------------------------------------------
     First and refunding mortgage bonds:
       2007 - 2035 (4.65% to 8.00% and variable)                     $  2,741                $  1,816
     Rate reduction notes:
       2005 - 2007 (6.38% to 6.42%)                                       739                     985
     Pollution-control bonds:
       2006 - 2031 (2.0% to 7.2%)                                       1,196                   1,216
     Bonds repurchased                                                     --                    (354)
     Debentures and notes:
       2006 - 2053 (5.06% to 7.625%)                                      812                     758
     Subordinated debentures:
       2044 (8.375%)                                                       --                     100
     Long-term debt due within one year                                  (246)                   (371)
     Unamortized debt discount - net                                      (17)                    (29)
-----------------------------------------------------------------------------------------------------
     Total                                                           $  5,225                $  4,121
-----------------------------------------------------------------------------------------------------

     Note:  Rates and terms as of December 31, 2004

Long-term debt maturities and sinking-fund requirements for the next five years are:  2005 - $246 million; 2006 -
$927 million; 2007 - $1.4 billion; 2008 - $54 million; and 2009 - $219 million.

At December 31, 2004 and 2003 SCE had a credit line with a limit of $700 million.  At December 31, 2004, SCE had
$602 million in available credit under its credit line.  The outstanding amount and weighted-average interest
rate, respectively, for short-term debt was $88 million at 2.48% for December 31, 2004 and $200 million at 2.83%
for December 31, 2003.


Page 71



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

In January 2005, SCE issued $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
$650 million of 8% first and refunding mortgage bonds due February 2007.

In compliance with a new accounting standard, effective July 1, 2003, SCE reclassified its preferred stock
subject to mandatory redemption to the liabilities section of its consolidated balance sheet.  This item was
previously classified between liabilities and equity.  Dividend payments on preferred securities subject to
mandatory redemption are included as interest expense effective July 1, 2003.  The new standard did not allow for
prior period restatements.

SCE has 12 million authorized shares of preferred stock subject to mandatory redemption.  Shares of SCE's
preferred stock have liquidation and dividend preferences over shares of SCE's common stock.  Mandatorily
redeemable preferred stock is subject to sinking-fund provisions.  When preferred shares are redeemed, the
premiums paid, if any, are charged to expense.

Preferred stock redemption requirements for the next five years are:  2005 - $9 million; 2006 - $9 million; 2007
- $74 million; 2008 - $56 million; and 2009 - none.

Cumulative preferred stock subject to mandatory redemption is:

Dollars in millions, except per-share amounts             December 31,                 2004            2003
----------------------------------------------------------------------------------------------------------------

                                              December 31, 2004
                                      ---------------------------------
                                         Shares            Redemption
                                       Outstanding            Price
                                       -----------        -------------

$100 par value:
6.05% Series                               673,800        $ 100.00                  $   67         $    69
7.23                                       807,000          100.00                      81              81
Preferred stock to be redeemed
   within one year                                                                      (9)             (9)
----------------------------------------------------------------------------------------------------------------
Total                                                                               $  139         $   141
----------------------------------------------------------------------------------------------------------------

The 6.05% Series preferred stock has 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 is allowed to credit previously repurchased shares
against the mandatory sinking fund provisions.  In 2004, SCE redeemed 20,000 shares of 6.05% Series preferred
stock.  In 2003, SCE redeemed 56,200 shares of 6.05% Series preferred stock.  At December 31, 2004, SCE had 1,200
of previously repurchased, but not retired, shares available to credit against the mandatory sinking fund
provisions.

The 7.23% Series preferred stock also has mandatory sinking funds, requiring SCE to redeem at least 50,000 shares
per year from 2002 through 2006, and 750,000 shares in 2007.  However, SCE is allowed to credit previously
repurchased shares against the mandatory sinking fund provisions.  Since SCE had previously repurchased 193,000
shares of this series, no shares were redeemed in the last three years.  At December 31, 2004, SCE had 43,000 of
previously repurchased, but not retired, shares available to credit against the mandatory sinking fund provisions.

In 2002, SCE redeemed 1,000,000 shares of 6.45% Series preferred stock.  SCE did not issue any preferred stock in
the last three years.


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

Note 5.  Preferred Stock Not Subject to Mandatory Redemption

SCE's authorized shares are: $25 cumulative preferred - 24 million and preference - 50 million.  Shares of SCE's
preferred stock have liquidation and dividend preferences over shares of SCE's common stock.  All cumulative
preferred stock is redeemable.  When preferred shares are redeemed, the premiums paid, if any, are charged to
common equity.  No preferred stock not subject to mandatory redemption was issued or redeemed in the last three
years.

Cumulative preferred stock not subject to mandatory redemption is:

Dollars in millions, except per-share amounts             December 31,                   2004           2003
----------------------------------------------------------------------------------------------------------------
                                              December 31, 2004
                                      ---------------------------------
                                         Shares            Redemption
                                       Outstanding            Price
                                       -----------        -------------

$25 par value:
4.08% Series                             1,000,000         $ 25.50                  $   25         $    25
4.24                                     1,200,000           25.80                      30              30
4.32                                     1,653,429           28.75                      41              41
4.78                                     1,296,769           25.80                      33              33
----------------------------------------------------------------------------------------------------------------
Total                                                                               $  129         $   129
----------------------------------------------------------------------------------------------------------------


Note 6.  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.

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

The components of income tax expense from continuing operations by location of taxing jurisdiction are:

     In millions                 Year ended December 31,             2004             2003               2002
----------------------------------------------------------------------------------------------------------------
     Current:
     Federal                                                     $    (88)         $   408           $    990
     State                                                             46              174                273
----------------------------------------------------------------------------------------------------------------
                                                                      (42)             582              1,263
----------------------------------------------------------------------------------------------------------------
     Deferred:
     Federal                                                          425             (134)              (504)
     State                                                             55              (60)              (117)
----------------------------------------------------------------------------------------------------------------
                                                                      480             (194)              (621)
----------------------------------------------------------------------------------------------------------------
     Total                                                       $    438          $   388           $    642
----------------------------------------------------------------------------------------------------------------



Page 73



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

The components of the net accumulated deferred income tax liability are:

     In millions                               December 31,                         2004                 2003
----------------------------------------------------------------------------------------------------------------
     Deferred tax assets:
     Accrued charges                                                             $    200           $     334
     Investment tax credits                                                            64                  68
     Property-related                                                                 196                 243
     Regulatory balancing accounts                                                    321                 204
     Unrealized gains or losses                                                       392                 365
     Decommissioning                                                                   84                 106
     Other                                                                            245                 199
----------------------------------------------------------------------------------------------------------------
     Total                                                                       $  1,502           $   1,519
----------------------------------------------------------------------------------------------------------------
     Deferred tax liabilities:
     Property-related                                                            $  2,915           $   2,762
     Capitalized software costs                                                       164                 160
     Regulatory balancing accounts                                                    710                 360
     Unrealized gains and losses                                                      289                 262
     Decommissioning                                                                   31                  30
     Other                                                                            124                 108
----------------------------------------------------------------------------------------------------------------
     Total                                                                       $  4,233           $   3,682
----------------------------------------------------------------------------------------------------------------
     Accumulated deferred income taxes - net                                     $  2,731           $   2,163
----------------------------------------------------------------------------------------------------------------
     Classification of accumulated deferred income taxes:
     Included in deferred credits                                                $  2,865           $   2,726
     Included in current assets                                                       134                 563


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

     Year ended December 31,                                         2004             2003              2002
--------------------------------------------------------------------------------------------------------------
     Federal statutory rate                                          35.0%            35.0%             35.0%
     Tax audit adjustments                                           (7.3)            (2.8)             (1.9)
     Resolution of FERC rate case                                     --              (5.9)              --
     Property-related                                                 0.4              0.1               0.4
     Transition costs                                                 --               --               (4.5)
     State tax - net of federal deduction                             4.8              6.0               5.4
     Other                                                           (0.7)            (1.9)             (0.4)
--------------------------------------------------------------------------------------------------------------
     Effective tax rate                                              32.2%            30.5%             34.0%
--------------------------------------------------------------------------------------------------------------


The composite federal and state statutory income tax rate was 40.37% for 2004, and 40.551% for 2003 and 2002.
The lower effective tax rate of 32.2% realized in 2004 was primarily due to adjustments to tax liabilities
relating to prior years, property-related flow-through items, and other property-related adjustments.  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.  The lower effective tax rate of 34.0%
realized in 2002 was primarily due to reestablishing a tax-related regulatory asset due to implementation of the
utility-retained generation decision and recording a benefit of a favorable settlement of tax audits.


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

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 10.

Note 7.  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 $37 million in 2004, $33 million in 2003 and $30 million in 2002.

Pension Plans and Postretirement 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, 2004 and December 31, 2003, 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
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.

The expected contributions (all by the employer) are approximately $38 million for the year ended December 31,
2005.  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.


Page 75


-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


Information on plan assets and benefit obligations is shown below:

In millions                             Year ended December 31,                         2004              2003
--------------------------------------------------------------------------------------------------------------
Change in projected benefit obligation
Projected benefit obligation at beginning of year                                   $   2,809        $   2,550
Service cost                                                                               86               79
Interest cost                                                                             162              162
Amendments                                                                                 22               --
Actuarial loss                                                                            106              148
Benefits paid                                                                            (152)            (130)
--------------------------------------------------------------------------------------------------------------
Projected benefit obligation at end of year                                         $   3,033        $   2,809
--------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation at end of year                                       $   2,627        $   2,424
--------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year                                      $   2,779        $   2,281
Actual return on plan assets                                                              316              594
Employer contributions                                                                     38               34
Benefits paid                                                                            (152)            (130)
--------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year                                            $   2,981        $   2,779
--------------------------------------------------------------------------------------------------------------
Funded status                                                                       $     (52)       $     (30)
Unrecognized net loss                                                                     105              111
Unrecognized transition obligation                                                          1                6
Unrecognized prior service cost                                                            91               84
--------------------------------------------------------------------------------------------------------------
Recorded asset                                                                      $     145        $     171
--------------------------------------------------------------------------------------------------------------
Additional detail of amounts recognized in balance sheets:
Intangible asset                                                                    $       2        $       3
Accumulated other comprehensive income                                                    (16)             (16)
Pension plans with an accumulated benefit obligation
   in excess of plan assets:
Projected benefit obligation                                                        $      77        $      78
Accumulated benefit obligation                                                             61               60
Fair value of plan assets                                                                  --               --
Weighted-average assumptions at end of year:
Discount rate                                                                            5.5%             6.0%
Rate of compensation increase                                                            5.0%             5.0%


Page 76

                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

Expense components are:

In millions                      Year ended December 31,                2004            2003              2002
-------------------------------------------------------------------------------------------------------------------
Service cost                                                          $   86          $    79           $   69
Interest cost                                                            162              162              158
Expected return on plan assets                                          (201)            (187)            (224)
Special termination benefits                                              --                3               --
Net amortization and deferral                                             22               34               21
-------------------------------------------------------------------------------------------------------------------
Expense under accounting standards                                        69               91               24
Regulatory adjustment - deferred                                         (26)             (44)             (18)
-------------------------------------------------------------------------------------------------------------------
Total expense recognized                                              $   43          $    47           $    6
-------------------------------------------------------------------------------------------------------------------
Change in accumulated other comprehensive income                      $   --          $    (7)              (9)

Weighted-average assumptions:
Discount rate                                                           6.0%             6.5%             7.0%
Rate of compensation increase                                           5.0%             5.0%             5.0%
Expected return on plan assets                                          7.5%             8.5%             8.5%


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

     In millions           Year ended December 31,
---------------------------------------------------------------------------------------------
         2005                                                                       $    207
         2006                                                                            220
         2007                                                                            234
         2008                                                                            248
         2009                                                                            258
         2010-2014                                                                      1,438
---------------------------------------------------------------------------------------------
     Total                                                                          $   2,605
---------------------------------------------------------------------------------------------

Asset allocations are:
                                                                  Target for               December 31,
                                                                     2005               2004          2003
------------------------------------------------------------------------------------------------------------
     United States equity                                             45%                 47%          46%
     Non-United States equity                                         25                  25           26
     Private equity                                                    4                   2            3
     Fixed income                                                     26                  26           25
------------------------------------------------------------------------------------------------------------

Postretirement Benefits Other Than Pensions

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


Page 77



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

$116 million upon adoption.  SCE's 2004 expense decreased by approximately $8 million as a result of the subsidy.

The expected contributions (all by the employer) to the postretirement benefits other than pensions trust are $76
million for the year ended December 31, 2005.  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.  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,                                2004              2003
----------------------------------------------------------------------------------------------------------------
     Change in benefit obligation
     Benefit obligation at beginning of year                                        $   2,137        $   2,103
     Service cost                                                                          40               42
     Interest cost                                                                        123              122
     Amendments                                                                            28             (622)
     Actuarial loss (gain)                                                                (88)             581
     Benefits paid                                                                        (94)             (89)
----------------------------------------------------------------------------------------------------------------
     Benefit obligation at end of year                                              $   2,146        $   2,137
----------------------------------------------------------------------------------------------------------------
     Change in plan assets
     Fair value of plan assets at beginning of year                                 $   1,389        $   1,072
     Actual return on plan assets                                                         145              291
     Employer contributions                                                                25              115
     Benefits paid                                                                        (94)             (89)
----------------------------------------------------------------------------------------------------------------
     Fair value of plan assets at end of year                                       $   1,465        $   1,389
----------------------------------------------------------------------------------------------------------------
     Funded status                                                                  $    (681)       $    (748)
     Unrecognized net loss                                                                841            1,027
     Unrecognized prior service cost                                                     (285)            (342)
----------------------------------------------------------------------------------------------------------------
     Recorded liability                                                             $    (125)       $     (63)
----------------------------------------------------------------------------------------------------------------
     Assumed health care cost trend rates:
     Rate assumed for following year                                                      10.0%            12.0%
     Ultimate rate                                                                         5.0%             5.0%
     Year ultimate rate reached                                                          2010             2010
     Weighted-average assumptions at end of year:
     Discount rate                                                                        5.75%            6.25%



Page 78


                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

Expense components are:

In millions                      Year ended December 31,                2004            2003              2002
----------------------------------------------------------------------------------------------------------------
Service cost                                                         $    40         $     42          $    42
Interest cost                                                            123              122              133
Expected return on plan assets                                           (96)             (89)             (93)
Special termination benefits                                              --                1               --
Amortization of unrecognized prior service costs                         (29)             (20)              --
Amortization of unrecognized loss                                         49               52               10
Amortization of unrecognized transition obligation                        --                9               27
----------------------------------------------------------------------------------------------------------------
Total expense                                                        $    87         $    117          $   119
----------------------------------------------------------------------------------------------------------------
Assumed health care cost trend rates:
Current year                                                             12.0%            9.75%            10.5%
Ultimate rate                                                             5.0%             5.0%             5.0%
Year ultimate rate reached                                              2010             2008             2008
Weighted-average assumptions:
Discount rate                                                            6.25%             6.4%            7.25%
Expected return on plan assets                                            7.1%             8.2%             8.2%


Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as
of December 31, 2004 by $307 million and annual aggregate service and interest costs by $27 million.  Decreasing
the health care cost trend rate by one percentage point would decrease the accumulated obligation as of
December 31, 2004 by $249 million and annual aggregate service and interest costs by $21 million.

The following benefit payments are expected to be paid:

     In millions               Year ended December 31,
-----------------------------------------------------------------------------------------------
         2005                                                                     $    106
         2006                                                                          104
         2007                                                                          111
         2008                                                                          111
         2009                                                                          118
         2010-2014                                                                     668
-----------------------------------------------------------------------------------------------
     Total                                                                        $  1,218
-----------------------------------------------------------------------------------------------

Asset allocations are:
                                                                  Target for               December 31,
                                                                     2005               2004          2003
------------------------------------------------------------------------------------------------------------

     United States equity                                             64%                 64%          64%
     Non-United States equity                                         16                  14           13
     Fixed income                                                     20                  22           23
------------------------------------------------------------------------------------------------------------


Description of Pension and Postretirement Benefits Other Than Pensions Investment 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


Page 79




-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements

classes.  SCE employs multiple investment management firms.  Investment managers within each asset class cover a
range of investment styles and approaches.  Risk is controlled through diversification among 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.

Allowable investment types include:

United States Equity:  Common and preferred stock of large, medium, and small companies which are predominantly
United States-based.

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 debt securities that are below
investment grade.

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 fully 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 place 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 Assets 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.

Capital Markets Return Forecasts

The estimated total return for fixed income is based on an equilibrium yield for intermediate United 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 consistent with 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 bonds.  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.


Page 80


                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

Active Management Excess Return Expectations

For asset classes that are actively managed, an excess return premium is added to the capital market return
forecasts discussed above.

Stock-Based Compensation

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 14 million shares remaining for future
issuance under equity compensation plans.

Most Edison International stock options issued prior to 2000 accrue dividend equivalents, subject to certain
performance criteria.  The 2003 and 2004 options accrue dividend equivalents for the first five years of the
option term.  Unless deferred, dividend equivalents accumulate without interest.

The fair value for each option granted, reflecting the basis for the pro forma disclosures in Note 1, 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:

     December 31,                                 2004                 2003                 2002
-----------------------------------------------------------------------------------------------------
     Expected years until exercise                9 - 10                 10                 7 - 10
     Risk-free interest rate                   4.0% - 4.3%          3.8% - 4.5%          4.7% - 6.1%
     Expected dividend yield                   2.7% - 3.7%              1.8%                1.8%
     Expected volatility                        19% - 22%            44% - 53%            18% - 54%
-----------------------------------------------------------------------------------------------------


A summary of the status of Edison International stock options is as follows:

                                                                             Weighted-Average
                                                                           --------------------
                                                   Share                    Exercise    Fair Value
                                                  Options                     Price      At Grant
--------------------------------------------------------------------------------------------------
     Outstanding, Dec. 31, 2001                  5,256,581                  $ 23.70
     Granted                                     1,769,017                    18.54       $ 7.86
     Expired                                      (138,899)                   24.88
     Forfeited                                     (73,651)                   21.04
     Exercised                                      (2,250)                   15.26
--------------------------------------------------------------------------------------------------
     Outstanding, Dec. 31, 2002                  6,810,798                  $ 22.37
     Granted                                     2,076,070                    12.41       $ 7.34
     Expired                                      (115,612)                   22.98
     Forfeited                                     (59,473)                   15.34
     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
--------------------------------------------------------------------------------------------------



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-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


A summary of stock options outstanding at December 31, 2004 is as follows:

                                            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               Price
-------------------------------------------------------------------------------------------------------------------

$ 8.90-$12.99           2,004,689                 8           $ 12.19              489,038              $ 12.07
$13.00-$18.99           1,762,799                 6           $ 18.23              896,330              $ 17.95
$19.00-$29.09           5,594,425                 6           $ 24.87            3,161,343              $ 27.11
-------------------------------------------------------------------------------------------------------------------
Total                   9,361,913                 6           $ 20.91            4,546,711              $ 23.69
-------------------------------------------------------------------------------------------------------------------


The number of options exercisable and their weighted-average exercise prices at December 31, 2003 and 2002 were
4,845,967 at $24.06 and 4,160,675 at $24.23, respectively.

Performance shares were awarded to executives in January 2002, January 2003 and January 2004 and vest at the end
of December 2004, 2005 and 2006, respectively.  The number of common shares paid out 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 ratably 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 fair value for 2004, 2003 and 2002 were 178,684 at $21.94, 293,497 at $12.33, and
218,248 at $15.20, respectively.

In November 2001, deferred stock units were issued in exchange for stock options granted in 2000.  The deferred
stock units vest at a rate of 25% per year over four years.

See Note 1 for SCE's accounting policy and expenses related to stock-based compensation.

Note 8.  Jointly Owned Utility Projects

SCE owns interests in several generating stations and transmission systems for which each participant provides
its own financing.  SCE's share of expenses for each project is included in the consolidated statements of income.


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

SCE's investment in each project as of December 31, 2004 is:

                                                  Investment          Accumulated
                                                      in           Depreciation and        Ownership
     In millions                                   Facility          Amortization          Interest
-------------------------------------------------------------------------------------------------------
     Transmission systems:
       Eldorado                                  $      48            $     16                60%
       Pacific Intertie                                305                  80                50
     Generating stations:
       Four Corners Units 4 and 5 (coal)               497                 395                48
       Mohave (coal)                                   347                 262                56
       Palo Verde (nuclear)                          1,679               1,459                16
       San Onofre (nuclear)                          4,420               3,943                75
-------------------------------------------------------------------------------------------------------
     Total                                       $   7,296            $  6,155
-------------------------------------------------------------------------------------------------------


     A portion of Mohave, San Onofre and Palo Verde is included in regulatory assets on the balance
     sheet.  See Notes 1 and 2.

Note 9.  Commitments

Leases

Operating lease expense was $17 million in 2004, $15 million in 2003 and $16 million in 2002.  SCE's lease
expense is primarily for vehicles; the leases have varying terms, provisions and expiration dates.

In accordance with an accounting standard, certain power contracts in which SCE takes virtually all of the power
from specific power plants are classified as operating leases.  Estimated remaining commitments for noncancelable
leases (primarily for power purchases in 2005 and 2006) at December 31, 2004 are:

     In millions           Year ended December 31,
--------------------------------------------------------------------------------------
         2005                                                                $    48
         2006                                                                     45
         2007                                                                      9
         2008                                                                      8
         2009                                                                      5
         Thereafter                                                                9
--------------------------------------------------------------------------------------
     Total                                                                   $   124
--------------------------------------------------------------------------------------


Nuclear Decommissioning

As a result of an accounting standard adopted in 2003, SCE recorded the fair value of its liability for ARO,
primarily related to the decommissioning of its nuclear power facilities.  At that time, SCE 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 $2.2 billion as of December 31,


Page 83



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


2004, based on site-specific studies performed in 2001 for San Onofre and Palo Verde.  Changes in the estimated
costs, timing of decommissioning, or the assumptions underlying these estimates could cause material revisions to
the estimated total cost to decommission in the near term.  SCE estimates that it will spend approximately $11.4
billion through 2049 to decommission its nuclear facilities.  This estimate is based on SCE's current-dollar
decommissioning cost methodology used for rate-making purposes, escalated at rates ranging from 1.1% to 10.0%
(depending on the cost element) annually.  These costs are expected to be funded from independent decommissioning
trusts, which effective October 2003 receive contributions of approximately $32 million per year.  SCE estimates
annual after-tax earnings on the decommissioning funds of 3.7% to 6.5%.  If the assumed return on trust assets is
not earned, it is probable that additional funds needed for decommissioning will be recoverable through rates.

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 restoration.  Phase one is anticipated 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.  On February 3, 2004, SCE announced that it has
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 1, where it poses no risk to the public or the environment.  This action results in
placing the disposal of the reactor pressure vessel in Phase three of the San Onofre Unit 1 decommissioning
project.

All of SCE's San Onofre Unit 1 decommissioning costs will be paid from its nuclear decommissioning trust funds,
subject to CPUC review.  The estimated remaining cost to decommission San Onofre Unit 1 is recorded as an ARO
liability ($154 million at December 31, 2004).  Total expenditures for the decommissioning of San Onofre Unit 1
were $360 million through December 31, 2004.

SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by the Nuclear
Regulatory Commission.  Decommissioning is expected to begin after the plants' operating licenses expire.  The
operating licenses expire in 2022 for San Onofre Units 2 and 3, and in 2024, 2026 and 2027 for the Palo Verde
units.  Decommissioning costs, which are recovered through nonbypassable customer rates over the term of each
nuclear facility'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 has collected in rates amounts for the future costs of removal of its nuclear assets, and has historically
recorded these amounts in accumulated provision for depreciation and decommissioning.  However, in accordance
with recent Securities and Exchange Commission accounting guidance, the amounts accrued in accumulated provision
for depreciation and decommissioning for nuclear decommissioning and costs of removal were reclassified to
regulatory liabilities as of December 31, 2002.  Upon implementation of the new accounting standard for AROs, SCE
reversed the decommissioning amounts collected for assets legally required to be removed and recorded the fair
value of this ARO (included in the deferred credits and other liabilities section of the consolidated balance
sheet).  The cost of removal amounts collected for assets not legally required to be removed remain in regulatory
liabilities as of December 31, 2004.

Decommissioning expense under the rate-making method was $125 million in 2004, $118 million in 2003 and $73
million in 2002.  The ARO for decommissioning SCE's active nuclear facilities was $2.0 billion at December 31,
2004 and $1.9 billion at December 31, 2003.


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

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,          2004         2003
-----------------------------------------------------------------------------------------------------------------
     Municipal bonds                             2005 - 2042                          $     784     $    702
     Stock                                            -                                   1,403        1,324
     United States government issues             2005 - 2033                                485          363
     Corporate bonds                             2005 - 2037                                 41           91
     Short-term                                     2005                                     44           50
-----------------------------------------------------------------------------------------------------------------
     Total                                                                            $   2,757     $  2,530
-----------------------------------------------------------------------------------------------------------------

     Note:  Maturity dates as of December 31, 2004.

Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory
liability.  Net earnings (loss) were $91 million in 2004, $93 million in 2003 and $(25) million in 2002.
Proceeds from sales of securities (which are reinvested) were $2.5 billion in 2004, $2.2 billion in 2003 and $3.8
billion in 2002.  Net unrealized holding gains were $796 million and $677 million at December 31, 2004 and 2003,
respectively.  Approximately 91% of the cumulative trust fund contributions were tax-deductible.

Other Commitments

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 balance sheets.

Certain commitments for the years 2005 through 2009 are estimated below:

     In millions                                             2005       2006       2007       2008       2009
--------------------------------------------------------------------------------------------------------------
     Fuel supply                                            $ 173      $  58      $  65      $  59      $  36
     Purchased power                                          898        725        648        421        394
--------------------------------------------------------------------------------------------------------------

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 provider, whether or not the transmission
line is operable.  The contract requires minimum payments of $69 million through 2016 (approximately $6 million
per year).


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-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


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.

Note 10.  Contingencies

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.

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

SCE's recorded estimated minimum liability to remediate its 24 identified sites is $82 million.  In third quarter
2003, SCE sold certain oil storage and pipeline facilities.  This sale caused a reduction in SCE's recorded
estimated minimum environmental liability.  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
uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to
$123 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 30 immaterial 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 $27 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;


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

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
$55 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.

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 $13 million to $25 million.  Recorded costs for 2004 were $14
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.

Federal Income Taxes

Edison International has reached a tentative settlement with the Internal Revenue Service (IRS) on tax issues and
pending affirmative claims relating to its 1991 to 1993 tax years currently under appeal.  This settlement, which
should be finalized in 2005, is expected to result in a net earnings benefit for SCE of approximately $70 million.

Edison International received Revenue Agent Reports from the IRS in August 2002 and in January 2005 asserting
deficiencies, including deficiencies asserted against SCE, in federal corporate income taxes with respect to
audits of its 1994 to 1996 and 1997 to 1999 tax years, respectively.  Many of the asserted tax deficiencies are
timing differences and, therefore, amounts ultimately paid (exclusive of interest and penalties), if any, would
benefit SCE as future tax deductions.

The IRS Revenue Agent Report for the 1997 to 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.

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.


Page 87



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


Investigations Regarding Performance Incentives Rewards

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 or
disallowances 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.

Customer Satisfaction

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 distribution business 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 about
$10 million for 2003.

SCE has been conducting an internal investigation and keeping the CPUC informed of its progress.  On June 25,
2004, SCE submitted to the CPUC a PBR customer satisfaction investigation report, which concluded that employees
in the design organization of the transmission and distribution business unit deliberately altered customer
contact information in order to affect the results of customer satisfaction surveys.  At least 36 design
organization personnel engaged in deliberate misconduct including alteration of customer information before the
data were transmitted to the independent survey company.  Because of the apparent scope of the misconduct, SCE
proposed to refund to ratepayers $7 million of the  PBR rewards previously received and forego 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 (1997-2003).  In addition, during its investigation, SCE
determined that it could not confirm the integrity of the method used for obtaining customer satisfaction survey
data for meter reading.  Thus, SCE also proposed to refund 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 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.

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


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

design organization.  SCE has responded to these requests and the CPUC has conducted interviews of approximately
20 employees who were disciplined for misconduct.

Employee Injury and Illness Reporting

In light of the problems uncovered with the customer satisfaction surveys, SCE is conducting 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.  Under the PBR
mechanism, rewards and/or penalties for the years 1997 through 2003 were based upon a total incident rate, which
included two equally weighted measures: Occupational Safety and Health Administration (OSHA) recordable incidents
and first aid incidents.  The major issue disclosed in the investigative findings to the CPUC was that SCE failed
to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.
SCE's investigation also found reporting inaccuracies for OSHA recordable incidents, but the impact of these
inaccuracies did not have a material effect on the PBR mechanism.

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 is taking other remedial action to address the issues identified, including revising its organizational
structure and overall program for environmental, health and safety compliance.  Additional actions, including
disciplinary action against specific employees identified as having committed wrongdoing, may result once the
investigation is completed.  SCE submitted a report 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.  However, SCE anticipates that the CPUC will be submitting data requests and seeking additional
information in the near future.

System Reliability

In light of the problems uncovered with the PBR mechanisms discussed above, SCE is conducting an investigation
into the third PBR metric, system reliability.  Since the inception of PBR payments in 1997, SCE has received
$8 million in rewards and has applied for an additional $5 million reward based on frequency of outage data for
2001.  For 2002, SCE's data indicates that it earned no reward and incurred no penalty.  Based on the application
of the PBR mechanism, as adopted, SCE's data would result in penalties of $5 million and $1 million, for 2003 and
2004, respectively.  These penalties have not yet been assessed.  As a result of SCE's data and calculations, SCE
has accrued a $6 million charge in the caption "Other nonoperating deductions" on the income statement in 2004.

On February 28, 2005, SCE provided its final investigatory report to the CPUC concluding that the reliability
reporting system is working as intended.


Page 89



-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


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 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 for its separate dismissal from the lawsuit.

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 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 analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for
summary judgment in the D.C. District Court action.  On April 13, 2004, the D.C. District Court denied SCE's and
Peabody's April 2003 motions to dismiss or, in the alternative, for summary judgment.  The D.C. District Court
subsequently issued a scheduling order that imposed a December 31, 2004 discovery cut-off.  Pursuant to a joint
request of the parties, the D.C. District Court granted a 120-day stay of the action 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.

The United States Court of Appeals for the D.C. Circuit, acting on a suggestion on remand filed by the Navajo
Nation, held in an October 24, 2003 decision that the Supreme Court's March 4, 2003 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.  The Government and the Navajo Nation both filed petitions for rehearing of the
October 24, 2003 D.C. Circuit Court decision.  Both petitions were denied on March 9, 2004.  On March 16, 2004,
the D.C. Circuit Court issued an order remanding the case against the Government to the Court of Federal Claims,
which conducted a status conference on May 18, 2004.  As a result of the status conference discussion, the Navajo
Nation and the Government are in the process of briefing the remaining issues following remand.  Peabody's motion
to intervene as a party in the remanded Court of Federal Claims case was denied.

SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of
the Supreme Court's decision in the Navajo Nation's suit against the Government on this complaint, or the impact
of the complaint on the operation of Mohave beyond 2005.


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                                                                                Southern California Edison Company
------------------------------------------------------------------------------------------------------------------

Nuclear Insurance

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 1 from this secondary level, effective
June 1994.  The maximum deferred premium for each nuclear incident is $101 million per reactor, but not more than
$10 million per reactor may be charged in any one year for each incident.  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 $20 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 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.  All licensed operating plants
including San Onofre and Palo Verde are grandfathered under the applicable law.

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 million 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 insurance 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.

Spent Nuclear Fuel

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
0.1(cent)-per-kWh of nuclear-generated electricity sold after April 6, 1983.  On January 29, 2004, SCE, as operating
agent, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for DOE's
failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre.  The case if currently
stayed pending development in other spent nuclear fuel cases also before the United States Court of Federal
Claims.

SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre.  Spent
nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel
storage installation.  Movement of Unit 1 spent fuel from the Unit 3 spent fuel pool to the independent spent
fuel storage installation was completed in late 2003.  Movement of Unit 1 spent fuel from the Unit 1 spent fuel
pool to the independent spent fuel storage installation was completed in late 2004.  Movement of Unit 1 spent
fuel from the Unit 2 spent fuel pool to the independent spent fuel pool storage installation is scheduled to be
completed by summer 2005.  With these moves, there will be sufficient space in the Unit 2 and 3 spent fuel pools
to meet plant requirements


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-------------------------------------------------------------------------------------------------------------------
Notes to Consolidated Financial Statements


through mid-2007 and mid-2008, respectively.  In order to maintain a full core off-load capability, SCE is
planning to begin moving Unit 2 and 3 spent fuel into the independent spent fuel storage installation by late
2006.

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 continually load casks on a
schedule to maintain full core off-load capability for all three units.

Note 11.  Mountainview Acquisition

On March 12, 2004, SCE acquired Mountainview Power Company LLC, which owns a power plant under construction in
Redlands, California.  SCE recommenced full construction of the approximately $600 million project, which is
expected to be completed in early 2006.

Note 12.  Discontinued Operations

On July 10, 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.  Due to immateriality, the results of this unit for 2002 have not
been restated and are reflected as part of continuing operations.  For 2003, revenue from discontinued operations
was $20 million and pre-tax income was $82 million.


-------------------------------------------------------------------------------------------------------------------
Quarterly Financial Data (Unaudited)

                                               2004                                         2003
                           --------------------------------------------   -----------------------------------------
In millions                 Total    Fourth    Third    Second     First  Total   Fourth    Third   Second   First
-------------------------------------------------------------------------------------------------------------------
Operating revenue          $8,448    $1,920   $2,655    $2,176   $1,696   $8,854  $1,859   $2,794   $2,386  $1,815
Operating income            2,013       499      682       587      245    1,578     293      609      416     260
Net income                    921       317      260       243      101      932     223      375      229     105
Net income available for
  common stock                915       315      259       242      100      922     222      374      225     101
Common dividends declared     750       155      150       145      300      945     945       --       --      --
-------------------------------------------------------------------------------------------------------------------

Operating income was restated for prior quarters due to a reclassification of performance share expense from
nonoperating to operating expenses

Totals may not add precisely due to rounding.



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------------------------------------------------------------------ ---------------------------------------------------
Selected Financial and Operating Data:  2000 - 2004                                 Southern California Edison Company


Dollars in millions                                       2004        2003         2002         2001         2000
---------------------------------------------------------------------------------------------------------------------

Income statement data:

Operating revenue                                       $ 8,448     $ 8,854      $ 8,706      $ 8,126       $ 7,870
Operating expenses                                        6,435       7,276        6,588        3,509        10,529
Purchased-power expenses                                  2,332       2,786        2,016        3,770         4,687
Income tax (benefit)                                        438         388          642        1,658        (1,022)
Provisions for regulatory adjustment clauses - net         (201)      1,138        1,502       (3,028)        2,301
Interest expense - net of amounts capitalized               409         457          584          785           572
Net income (loss) from continuing operations                921         882        1,247        2,408        (2,028)
Net income (loss)                                           921         932        1,247        2,408        (2,028)
Net income (loss) available for common stock                915         922        1,228        2,386        (2,050)
Ratio of earnings to fixed charges                         4.40        3.81         4.21         6.15          *
    *less than 1.00

---------------------------------------------------------------------------------------------------------------------

Balance sheet data:

Assets                                                 $ 23,290    $ 21,771     $ 36,058     $ 22,453      $ 15,966
Gross utility plant                                      17,981      16,991       16,232       15,982        15,653
Accumulated provision for depreciation
  and decommissioning                                     4,506       4,386        4,057        7,969         7,834
Short-term debt                                              88         200           --        2,127         1,451
Common shareholder's equity                               4,521       4,355        4,384        3,146           780
Preferred stock:
  Not subject to mandatory redemption                       129         129          129          129           129
  Subject to mandatory redemption                           139         141          147          151           256
Long-term debt                                            5,225       4,121        4,525        4,739         5,631
Capital structure:
  Common shareholder's equity                              45.1%       49.8%        47.7%        38.5%        11.5%
  Preferred stock:
    Not subject to mandatory redemption                     1.3%        1.5%         1.4%         1.6%         1.9%
    Subject to mandatory redemption                         1.4%        1.6%         1.6%         1.9%         3.8%
  Long-term debt                                           52.2%       47.1%        49.3%        58.0%        82.8%

---------------------------------------------------------------------------------------------------------------------

Operating data:

Peak demand in megawatts (MW)                            20,762      20,136       18,821       17,890        19,757
Generation capacity at peak (MW)                         10,207       9,861        9,767        9,802         9,886
Kilowatt-hour deliveries (in millions)                   97,273      92,763       79,693       78,524        84,430
Total energy requirement (kWh) (in millions)             78,738      77,158       71,663       83,495        82,503
Energy mix:
  Thermal                                                  33.7%       37.9%        40.2%        32.5%        36.0%
  Hydro                                                     4.5%        5.2%         5.0%         3.6%         5.4%
  Purchased power and other sources                        61.8%       56.9%        54.8%        63.9%        58.6%
Customers (in millions)                                    4.67        4.60         4.53         4.47         4.42
Full-time employees                                      13,454      12,698       12,113       11,663        12,593


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                                        SOUTHERN CALIFORNIA EDISON COMPANY
                               2244 Walnut Grove Avenue, Rosemead, California 91770
                                                   626.302.1212
                                                  www.edison.com