UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-Q

(Mark One)

/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934

For the quarterly period ended             September 30, 1999
                                 ----------------------------------------------
                                       OR

/ / Transition report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934

For the transition period from ________________________ to ____________________

                           Commission File No. 1-2313

                       SOUTHERN CALIFORNIA EDISON COMPANY
             (Exact name of registrant as specified in its charter)

                  CALIFORNIA                          95-1240335
        (State or other jurisdiction of            (I.R.S. Employer
        incorporation or organization)            Identification No.)

           2244 Walnut Grove Avenue
                (P.O. Box 800)
             Rosemead, California
             (Address of principal                       91770
              executive offices)                      (Zip Code)

                                 (626) 302-1212
              (Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.

Yes   X          No ___

Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:

              Class                           Outstanding at November 8, 1999
-----------------------------------------------------------------------------
   Common Stock, no par value                           434,888,104

===============================================================================


<PAGE>

SOUTHERN CALIFORNIA EDISON COMPANY

INDEX
                                                                         Page
                                                                          No.
Part I.  Financial Information:

   Item 1.  Consolidated Financial Statements:

            Report of Independent Public Accountants                       1

            Consolidated Statements of Income -- Three, Nine and
               Twelve Months Ended September 30, 1999, and 1998            2

            Consolidated Statements of Comprehensive Income --
               Three, Nine and Twelve Months Ended September 30, 1999,
               and 1998                                                    2

            Consolidated Balance Sheets -- September 30, 1999,
               December 31, 1998, and September 30, 1998                   3

            Consolidated Statements of Cash Flows --
               Three, Nine and Twelve Months Ended
               September 30, 1999, and 1998                                5

            Notes to Consolidated Financial Statements                     6

   Item 2.  Management's Discussion and Analysis of Results
                     of Operations and Financial Condition                27


Part II. Other Information:

   Item 1.  Legal Proceedings                                             38

   Item 6.  Exhibits and Reports on Form 8-K                              41

<PAGE>

PART I FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS


To Southern California Edison Company:

We have audited the accompanying consolidated balance sheets of Southern
California Edison Company (SCE), a California corporation, and its subsidiaries
as of September 30, 1999, December 31, 1998, and September 30, 1998, and the
related consolidated statements of income, comprehensive income, and cash flows
for each of the three-, nine- and twelve-month periods ended September 30, 1999,
and 1998. These financial statements are the responsibility of SCE's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. 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. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of SCE and its subsidiaries as of
September 30, 1999, December 31, 1998, and September 30, 1998, and the results
of their operations and their cash flows for each of the three-, nine- and
twelve-month periods ended September 30, 1999, and 1998, in conformity with
generally accepted accounting principles.

                                                         ARTHUR ANDERSEN LLP
                                                         ARTHUR ANDERSEN LLP

Los Angeles, California
November 2, 1999




                                       1
<PAGE>

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME
In thousands

<TABLE>
<CAPTION>
                                                  3 Months Ended             9 Months Ended              12 Months Ended
                                                   September 30,              September 30,               September 30,
----------------------------------------------------------------------------------------------------------------------------

                                                1999         1998          1999         1998           1999         1998
----------------------------------------------------------------------------------------------------------------------------

<S>                                        <C>          <C>            <C>          <C>           <C>           <C>
Operating revenue                          $ 2,303,922  $  2,369,498   $ 5,701,460  $ 5,610,970   $ 7,590,008   $ 7,591,334
----------------------------------------------------------------------------------------------------------------------------

Fuel                                            57,592        64,621       163,022      242,489       244,249       409,882
Purchased power-- contracts                    823,470       908,407     1,856,130    2,010,269     2,471,762     2,747,155
Purchased power-- PX-- net                     317,391       393,739       531,490      433,838       733,995       433,838
Provisions for regulatory
   adjustment clauses-- net                   (201,430)     (447,676)     (562,179)    (289,314)     (745,384)     (422,811)
Other operating expenses                       368,033       437,065     1,218,331    1,124,693     1,574,281     1,502,105
Maintenance                                     84,378       104,265       279,395      304,627       385,335       407,916
Depreciation, decommissioning and
   amortization                                413,400       378,189     1,176,695    1,137,087     1,585,343     1,446,518
Income taxes                                   154,380       172,015       317,120      396,777       365,986       541,434
Property and other taxes                        29,260        31,642        96,733      102,406       122,728       130,055
Net loss (gain) on sale of utility plant           767        89,939        (2,158)    (529,099)      (15,669)     (529,840)
----------------------------------------------------------------------------------------------------------------------------

Total operating expenses                     2,047,241     2,132,206     5,074,579    4,933,773     6,722,626     6,666,252
----------------------------------------------------------------------------------------------------------------------------

Operating income                               256,681       237,292       626,881      677,197       867,382       925,082
----------------------------------------------------------------------------------------------------------------------------

Provision for rate phase-in plan                    --            --            --           --            --       (12,578)
Allowance for equity funds
   used during construction                      4,040         3,051         9,932        8,740        13,017        10,800
Interest and dividend income                    20,465        18,031        51,272       51,754        66,245        69,356
Other nonoperating income
   (deductions)-- net                            5,696        27,672        29,080       19,774         4,921        (1,234)
----------------------------------------------------------------------------------------------------------------------------

Total other income-- net                        30,201        48,754        90,284       80,268        84,183        66,344
----------------------------------------------------------------------------------------------------------------------------

Income before interest expense                 286,882       286,046       717,165      757,465       951,565       991,426
----------------------------------------------------------------------------------------------------------------------------

Interest and amortization on long-term debt    101,072       103,916       299,527      319,784       401,600       405,873
Other interest expense                          20,806        16,032        64,276       50,142        78,361        78,342
Allowance for borrowed funds used
   during construction                          (3,505)       (2,076)       (8,619)      (5,947)      (10,718)       (8,427)
Capitalized interest                               (42)         (330)       (1,110)        (612)       (1,792)         (691)
----------------------------------------------------------------------------------------------------------------------------

Total interest expense-- net                   118,331       117,542       354,074      363,367       467,451       475,097
----------------------------------------------------------------------------------------------------------------------------

Net income                                     168,551       168,504       363,091      394,098       484,114       516,329
Dividends on preferred stock                     8,445         5,612        20,253       19,019        25,865        25,778
----------------------------------------------------------------------------------------------------------------------------

Earnings available for common stock          $ 160,106     $ 162,892     $ 342,838    $ 375,079     $ 458,249     $ 490,551
----------------------------------------------------------------------------------------------------------------------------
</TABLE>


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
In thousands

<TABLE>
<CAPTION>
                                          3 Months Ended                 9 Months Ended           12 Months Ended
                                           September 30,                  September 30,            September 30,
-------------------------------------------------------------------------------------------------------------------
                                              1999         1998          1999        1998         1999       1998
-------------------------------------------------------------------------------------------------------------------
<S>                                       <C>           <C>          <C>          <C>         <C>         <C>
Net income                                $ 168,551     $ 168,504    $ 363,091    $ 394,098   $ 484,114   $ 516,329
Unrealized gain (loss) on securities--net    31,993       (21,631)      24,776       (9,189)     43,240       1,944
Reclassification adjustment for gains
  included in net income                    (13,654)           --      (45,899)          --     (63,735)         --
-------------------------------------------------------------------------------------------------------------------
Comprehensive income                      $ 186,890     $ 146,873    $ 341,968    $ 384,909   $ 463,619   $ 518,273
-------------------------------------------------------------------------------------------------------------------
</TABLE>

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



                                       2
<PAGE>

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
In thousands

<TABLE>
<CAPTION>
                                                             September 30,       December 31,       September 30,
                                                                 1999                1998               1998
------------------------------------------------------------------------------------------------------------------
ASSETS

Utility plant, at original cost:
<S>                                                          <C>                 <C>                <C>
   Transmission and distribution                             $ 12,134,001        $ 11,771,678       $ 11,591,649
   Generation                                                   1,698,781           1,689,469          1,728,929
Accumulated provision for depreciation
   and decommissioning                                         (7,265,355)         (6,896,479)        (6,765,106)
Construction work in progress                                     703,742             516,664            582,569
Nuclear fuel, at amortized cost                                   148,785             172,250            141,569
-----------------------------------------------------------------------------------------------------------------

Total utility plant                                             7,419,954           7,253,582          7,279,610
-----------------------------------------------------------------------------------------------------------------

Nonutility property -- less accumulated provision
   for depreciation of $8,794, $25,682
   and $25,381 at respective dates                                 72,248              56,681             74,940
Nuclear decommissioning trusts                                  2,326,847           2,239,929          2,013,293
Other investments                                                 181,560             179,480            210,116
-----------------------------------------------------------------------------------------------------------------

Total other property and investments                            2,580,655           2,476,090          2,298,349
-----------------------------------------------------------------------------------------------------------------

Cash and equivalents                                              227,718              81,500            284,312
Receivables, including unbilled revenue, less
   allowances of $27,417, $22,230 and $20,235
   for uncollectible accounts at respective dates               1,299,047           1,112,630          1,266,361
Fuel inventory                                                     51,150              51,299             50,561
Materials and supplies, at average cost                           120,064             116,259            121,408
Accumulated deferred income taxes-- net                           143,441             274,833            269,277
Regulatory balancing accounts-- net                               127,516             287,377              6,539
Prepayments and other current assets                              129,751              91,992            127,168
-----------------------------------------------------------------------------------------------------------------

Total current assets                                            2,098,687           2,015,890          2,125,626
-----------------------------------------------------------------------------------------------------------------

Unamortized nuclear investment-- net                            1,564,807           2,161,998          2,387,998
Income tax-related deferred charges                             1,352,336           1,463,256          1,454,606
Regulatory balancing accounts-- net                             1,250,085             361,404            400,997
Unamortized debt issuance and reacquisition
   expense                                                        341,786             348,816            356,018
Other deferred charges                                            997,630             865,892            915,612
-----------------------------------------------------------------------------------------------------------------

Total deferred charges                                          5,506,644           5,201,366          5,515,231
-----------------------------------------------------------------------------------------------------------------

Total assets                                                 $ 17,605,940        $ 16,946,928       $ 17,218,816
-----------------------------------------------------------------------------------------------------------------
</TABLE>

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



                                       3
<PAGE>

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
In thousands, except share amounts

<TABLE>
<CAPTION>
                                                        September 30,      December 31,        September 30,
                                                            1999               1998                  1998
-----------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES

Common stock (434,888,104 shares
<S>                                                    <C>                 <C>                <C>
   outstanding at each date)                           $ 2,168,054         $ 2,168,054        $ 2,168,054
Additional paid-in capital                                 335,014             334,031            334,031
Accumulated other comprehensive income                      18,339              39,462             38,834
Retained earnings                                          585,375             793,625            819,941
Preferred stock:
   Not subject to mandatory redemption                     128,755             128,755            128,755
   Subject to mandatory redemption                         255,700             255,700            255,700
Long-term debt                                           5,221,915           5,446,638          5,486,384
----------------------------------------------------------------------------------------------------------

Total capitalization                                     8,713,152           9,166,265          9,231,699
----------------------------------------------------------------------------------------------------------

Current portion of long-term debt                          568,009             400,810            593,311
Short-term debt                                            605,003             469,565            105,780
Accounts payable                                           561,364             447,484            640,409
Accrued taxes                                              984,560             678,955            832,331
Accrued interest                                            88,778              89,828             70,506
Dividends payable                                           94,350              91,742             91,943
Deferred unbilled revenue and other current
   liabilities                                           1,414,335           1,096,332          1,162,644
----------------------------------------------------------------------------------------------------------

Total current liabilities                                4,316,399           3,274,716          3,496,924
----------------------------------------------------------------------------------------------------------

Accumulated deferred income taxes-- net                  2,768,891           2,993,142          2,880,334
Accumulated deferred investment tax credits                217,822             250,116            302,539
Customer advances and other deferred credits               824,537             795,266            791,081
Power purchase contracts                                   333,262             129,698            133,700
Other long-term liabilities                                431,547             337,411            382,230
----------------------------------------------------------------------------------------------------------

Total deferred credits and other liabilities             4,576,059           4,505,633          4,489,884
----------------------------------------------------------------------------------------------------------

Minority interest                                              330                 314                309
----------------------------------------------------------------------------------------------------------
Commitments and contingencies
   (Notes 2, 8, 9 and 10)

Total capitalization and liabilities                  $ 17,605,940        $ 16,946,928       $ 17,218,816
----------------------------------------------------------------------------------------------------------
</TABLE>

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


                                       4
<PAGE>

SOUTHERN CALIFORNIA EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands

<TABLE>
<CAPTION>
                                                 3 Months Ended           9 Months Ended              12 Months Ended
                                                  September 30,            September 30,               September 30,
------------------------------------------------------------------------------------------------------------------------
                                               1999        1998         1999         1998           1999          1998
------------------------------------------------------------------------------------------------------------------------

Cash flows from operating activities:
<S>                                        <C>         <C>          <C>          <C>            <C>           <C>
Net income                                 $ 168,551   $ 168,504    $ 363,091    $ 394,098      $ 484,114     $ 516,329
Adjustments for non-cash items:
   Depreciation, decommissioning and
      amortization                           413,400     378,189    1,176,695    1,137,087      1,585,343     1,446,518
   Other amortization                         26,295      25,784       69,419       63,316         95,426        89,610
   Rate phase-in plan                             --          --           --        3,777             --        16,220
   Deferred income taxes and
     investment tax credits                  (81,249)     66,342      (14,233)    (140,683)        31,946       (57,804)
   Other long-term liabilities                22,511      20,227      103,822       36,293         55,001        11,196
   Regulatory balancing
     accounts-- long-term                   (424,415)   (543,024)    (888,681)    (400,997)      (849,088)     (400,997)
   Regulatory asset related to sale of
     generating plants                           (58)   (111,310)         183     (219,301)          (748)     (219,301)
   Net loss (gain) on sale of
     generating plants                           227      88,355         (883)    (551,984)       (13,522)     (551,984)
   Other-- net                               (18,347)    (16,338)     (38,549)     (35,631)           907       (55,936)
Changes in working capital:
   Receivables                              (236,671)   (235,569)    (186,417)    (359,973)       (32,686)      (58,360)
   Regulatory balancing accounts             150,579     185,722      159,861      186,772       (120,977)       94,396
   Fuel inventory, materials and supplies     (2,060)     (4,326)      (3,656)      19,070            755        33,820
   Prepayments and other current assets     (112,281)   (112,028)     (37,759)     (34,070)        (2,583)         (994)
   Accrued interest and taxes                259,377     (87,083)     304,555      308,161        170,501        17,877
   Accounts payable and other
     current liabilities                     430,448     357,382      431,883      464,493        172,646       420,744
------------------------------------------------------------------------------------------------------------------------

Net cash provided by operating activities    596,307     180,827    1,439,331      870,428      1,577,035     1,301,334
------------------------------------------------------------------------------------------------------------------------

Cash flows from financing activities:
Long-term debt issued                        135,300          --      490,840           --        490,840            --
Long-term debt repaid                       (145,410)     (1,575)    (362,872)    (606,030)      (532,872)     (606,030)
Rate reduction notes issued                       --          --           --           --             --     2,444,127
Rate reduction notes repaid                  (58,520)    (78,605)    (178,280)    (161,070)      (268,801)     (155,908)
Preferred stocks redeemed                         --      (1,000)          --      (74,300)            --       (74,300)
Nuclear fuel financing-- net                 (13,828)      7,393      (22,844)     (11,478)         4,878       (18,990)
Short-term debt financing-- net              197,888     (15,775)     135,438     (216,248)       499,223      (664,520)
Dividends paid                              (274,358)   (429,124)    (563,373)    (982,146)      (711,039)   (2,258,643)
-------------------------------------------------------------------------------------------------------------------------

Net cash used by financing activities       (158,928)   (518,686)    (501,091)  (2,051,272)      (517,771)   (1,334,264)
-------------------------------------------------------------------------------------------------------------------------

Cash flows from investing activities:
Additions to property and plant             (242,254)   (211,272)    (717,391)    (548,319)    (1,029,910)     (789,850)
Proceeds from sale of generating plants           --      43,000           --    1,188,039         15,000     1,188,039
Funding of nuclear decommissioning trusts    (29,049)    (41,315)     (95,473)    (118,196)      (140,202)     (162,750)
Unrealized gain (loss) on securities--net     18,339     (21,631)     (21,123)      (9,189)       (20,495)        1,944
Other-- net                                  (29,136)     22,447       41,965       (9,451)        59,749       (16,192)
-------------------------------------------------------------------------------------------------------------------------

Net cash provided (used) by
   investing activities                     (282,100)   (208,771)    (792,022)     502,884     (1,115,858)      221,191
-------------------------------------------------------------------------------------------------------------------------

Net increase (decrease) in cash
   and equivalents                           155,279    (546,630)     146,218     (677,960)       (56,594)      188,261
Cash and equivalents, beginning
   of period                                  72,439     830,942       81,500      962,272        284,312        96,051
------------------------------------------------------------------------------------------------------------------------

Cash and equivalents, end of period        $ 227,718   $ 284,312    $ 227,718    $ 284,312      $ 227,718      $284,312
------------------------------------------------------------------------------------------------------------------------

Cash payments for interest and taxes:
Interest-- net of amounts capitalized      $  98,112   $  91,821   $  215,425    $ 217,488     $  261,681     $ 309,063
Taxes                                         92,616     325,666       92,628      326,092        171,533       548,129
</TABLE>

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


                                       5
<PAGE>

SOUTHERN CALIFORNIA EDISON COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1. Summary of Significant Accounting Policies

Southern California Edison Company (SCE) is a public utility which supplies
electric energy for its 4.3 million customers in central, coastal and Southern
California. SCE also produces electricity. The regulatory environment in which
SCE operates is changing as a result of a 1995 California Public Utilities
Commission (CPUC) decision on electric utility industry restructuring and state
legislation enacted in 1996.

Basis of Presentation

SCE's accounting policies conform with generally accepted accounting principles,
including the accounting principles for rate-regulated enterprises which reflect
the rate-making policies of the CPUC and the Federal Energy Regulatory
Commission (FERC). As a result of industry restructuring legislation enacted by
the State of California and related changes in the rate-recovery of generation
related assets, SCE accounts for its investment in generation facilities in
accordance with accounting principles applicable to enterprises in general.
Application of such accounting principles to SCE's generation assets, beginning
in 1997, did not result in any adjustment of their carrying value; however, in
the second quarter of 1998, the carrying value of SCE's nuclear investments
(excluding decommissioning) was reduced by $2.6 billion and a regulatory asset
was established for the same amount.

The consolidated financial statements include SCE and its subsidiaries.
Intercompany transactions have been eliminated. Certain prior-period amounts
were reclassified to conform to the September 30, 1999, financial statement
presentation.

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

Since April 1, 1998, when the new market structure began, SCE has been selling
all of its generation through the power exchange (PX), as mandated by the CPUC's
1995 restructuring decision. Through the PX, SCE satisfies the electric energy
needs of customers who did not choose an alternative energy provider. These
transactions through the PX are reported as Purchased power -- PX -- net.

Transactions through the PX were:

<TABLE>
<CAPTION>
                                      3 Months Ended            9 Months Ended         12 Months Ended
                                       September 30,             September 30,          September 30,
-------------------------------------------------------------------------------------------------------
In millions                         1999         1998          1999       1998        1999       1998
-------------------------------------------------------------------------------------------------------

<S>                                 <C>       <C>           <C>        <C>         <C>        <C>
Purchases                           $  882    $ 1,081       $ 1,739    $ 1,425     $ 2,298    $ 1,425
Generation sales                       565        687         1,208        991       1,564        991
-------------------------------------------------------------------------------------------------------

Purchased power-- PX-- net          $  317   $    394      $    531   $    434    $    734   $    434
-------------------------------------------------------------------------------------------------------
</TABLE>

Cash Equivalents

Cash equivalents include tax-exempt investments and time deposits and other
investments with original maturities of three months or less.

Estimates

Financial statements prepared in compliance with generally accepted accounting
principles require management to make estimates and assumptions that affect the
amounts reported in the financial statements and disclosure of contingencies.
Actual results could differ from those estimates. Certain significant estimates
related to regulatory matters, decommissioning and contingencies are further
discussed in Notes 2, 9 and 10 to the Consolidated Financial Statements,
respectively.



                                       6
<PAGE>

Fuel Inventory

Fuel inventory is valued under the last-in, first-out method for fuel oil and
natural gas, and under the first-in, first-out method for coal.

Nuclear

SCE is recovering its investment in San Onofre Nuclear Generating Station Units
2 and 3 and Palo Verde Nuclear Generating Station on an accelerated basis, as
authorized by the CPUC. The accelerated recovery will continue through December
2001, earning a 7.35% fixed rate of return. San Onofre's operating costs,
including nuclear fuel and nuclear fuel financing costs, and incremental capital
expenditures, are recovered through an incentive pricing plan which allows SCE
to receive about 4(cent) per kilowatt-hour through 2003. Any differences between
these costs and the incentive price will flow through to the shareholders. Palo
Verde's accelerated plant recovery, as well as operating costs, including
nuclear fuel and nuclear fuel financing costs, and incremental capital
expenditures, are subject to balancing account treatment through 2001.

Beginning January 1, 1998, San Onofre's incentive pricing plan and accelerated
plant recovery and the Palo Verde balancing account became part of the
transition cost balancing account. SCE will be required to share equally with
ratepayers the net benefits received from operation of Palo Verde, beginning in
2002, and from the operation of the San Onofre units in 2004. Palo Verde's
existing nuclear unit incentive procedure will continue only for purposes of
calculating a reward for performance of any unit above an 80% capacity factor
for a fuel cycle.

CPUC-authorized rate phase-in plans, which deferred collection of revenue for
each unit at Palo Verde during the first four years of operation, ended in
February 1996, September 1996 and January 1998 for Units 1, 2 and 3,
respectively.

Regulation of Utility Business

SCE, which is subject to rate-regulation by the CPUC and the FERC, operates in a
highly regulated environment in which it has an obligation to deliver electric
service to customers in return for an exclusive franchise within its service
territory.

Effective January 1, 1998, SCE's rates were unbundled into separate charges for
energy, transmission, distribution, the non-bypassable competition transition
charge (CTC), public benefit programs and nuclear decommissioning. The
transmission component is being collected through FERC-approved rates, subject
to refund. SCE's costs associated with its hydroelectric plants are being
recovered through a performance-based mechanism. This mechanism sets the
hydroelectric revenue requirement and establishes a formula for extending it
through the duration of the electric industry restructuring transition period
(March 31, 2002), or until market valuation of the hydroelectric facilities,
whichever occurs first. Revenue from hydroelectric facilities in excess of the
hydroelectric revenue requirement is credited against the costs to transition to
a competitive market. Decommissioning costs are being recovered through a
CPUC-authorized non-bypassable charge.

The CTC provides SCE the opportunity to recover its costs to transition to a
competitive market (approximately $10.6 billion 1998 net present value).
Transition costs related to power-purchase contracts are being recovered through
the terms of the contracts while most of the remaining transition costs will be
recovered through 2001. A portion of the stranded costs that residential and
small commercial customers would have paid between 1998 and 2001, has been
financed by the issuance of rate reduction notes, allowing SCE to reduce rates
by at least 10% to these customers, effective January 1, 1998. The notes allow
for the rate reduction by lowering the carrying cost on a portion of the
transition costs and by deferring recovery of a portion of these transition

                                       7
<PAGE>

costs until after the transition period. Additionally, the state legislation
contained provisions for the recovery (through 2006) of reasonable
employee-related transition costs, incurred and projected, for retraining,
severance, early retirement, outplacement and related expenses.

Regulatory Assets and Liabilities

In accordance with accounting principles for rate-regulated enterprises, SCE
records regulatory assets, which represent probable future revenue associated
with certain costs that will be recovered from customers through the rate-making
process, and regulatory liabilities, which represent probable future reductions
in revenue associated with amounts that are to be credited to customers through
the rate-making process. SCE's discontinuance of accounting principles for
rate-regulated enterprises to its generation assets did not result in a
write-off of its generation-related regulatory assets since the CPUC has
approved recovery of these assets through the CTC.

Regulatory assets and liabilities included in the consolidated balance sheets
are:

<TABLE>
<CAPTION>
                                                          September 30,   December 31,  September 30,
     In millions                                              1999            1998          1998
-----------------------------------------------------------------------------------------------------
     Generation-related:
<S>                                                        <C>             <C>           <C>
     Unamortized nuclear investment-- net                  $ 1,565         $ 2,162       $ 2,388
     Flow-through taxes                                        358             614           675
     Rate reduction notes-- transition cost deferral           619             315           266
     Unamortized loss on sale of plant                         137             183           197
     Purchased-power settlements                               301             130           134
     Environmental remediation                                  16              16            16
     Regulatory balancing accounts and other                   884             354           287
----------------------------------------------------------------------------------------------------
         Subtotal                                            3,880           3,774         3,963
----------------------------------------------------------------------------------------------------
     Other:
     Flow-through taxes                                        995             849           780
     Unamortized loss of reacquired debt                       301             308           314
     Environmental                                             114             125           129
     Regulatory balancing accounts and other                   (18)            110            (7)
----------------------------------------------------------------------------------------------------
         Subtotal                                            1,392           1,392         1,216
----------------------------------------------------------------------------------------------------
     Total                                                 $ 5,272         $ 5,166       $ 5,179
----------------------------------------------------------------------------------------------------
</TABLE>

Generation-related regulatory assets and liabilities are being recovered through
the CTC through March 31, 2002, except for the rate reduction notes regulatory
asset which will be recovered over the terms of the rate reduction notes. The
other regulatory assets and liabilities are being recovered through other
components of the unbundled rates.

The unamortized nuclear investment regulatory asset was created during the
second quarter of 1998. SCE reduced its remaining nuclear plant investment by
$2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its
balance sheet for the same amount in accordance with asset impairment accounting
standards. For this impairment assessment, the fair value of the investment was
calculated by discounting expected future net cash flows. This reclassification
had no effect on SCE's results of operations.

If during the transition period events were to occur that made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.6
billion, after tax, at September 30, 1999) as a one-time, non-cash charge
against earnings.

                                       8
<PAGE>

Regulatory Balancing Accounts

Beginning January 1, 1998, the difference between generation-related revenue and
generation-related costs is being accumulated in the transition cost balancing
account, effectively eliminating all other balancing accounts except those used
to assist in the administration of public purpose funds. Additionally, gains
resulting from the sale of the gas- and oil-fueled generation plants during 1998
were credited to the transition cost balancing account; the losses are being
amortized over the remaining transition period and accumulated in the transition
cost balancing account. These transition costs are being recovered from utility
customers (with interest) through the CTC mechanism.

Prior to January 1, 1998, the differences between CPUC-authorized and actual
base-rate revenue from kilowatt-hour sales and CPUC-authorized and actual energy
costs were accumulated in balancing accounts until they were refunded to, or
recovered from, utility customers through authorized rate adjustments (with
interest). On January 1, 1998, the balances in these balancing accounts were
transferred to the transition cost balancing account.

Income tax effects on all balancing account changes are deferred.

Research, Development and Demonstration (RD&D)

SCE capitalizes RD&D costs that are expected to result in plant construction. If
construction does not occur, these costs are charged to expense.

Revenue

Operating revenue includes amounts for services rendered but unbilled at the end
of each period.

Utility Plant

Plant additions, including replacements and betterments, are capitalized. Such
costs include direct material and labor, construction overhead 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. 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.

Replaced or retired  property and removal  costs less salvage are charged to the
accumulated provision for depreciation. Depreciation expense stated as a percent
of average original cost of depreciable utility plant was 3.4%, 3.6% and 5.3%
for the three,  nine and twelve months ended  September 30, 1999,  respectively,
and 3.4%,  4.6% and 5.1% for the three,  nine and twelve months ended  September
30, 1998, respectively.

SCE's net investment in generation-related utility plant was $1.0 billion, $1.1
billion and $1.0 billion at September 30, 1999, December 31, 1998, and September
30, 1998, respectively.

Note 2. Regulatory Matters

FERC Transmission Rate Case

SCE filed its first FERC transmission rate case in March 1997. The filing
proposed a transmission revenue requirement of $211 million. In March 1999, a
proposed FERC decision was issued recommending a return on equity of 9.68%
(compared to SCE's current CPUC rate for distribution of 11.6%) and a lower
revenue requirement. SCE filed briefs opposing the proposed decision in May
1999. In response to a recent FERC ruling, on November 1, 1999, SCE filed
additional evidence regarding return on equity. A final FERC decision is
expected in early 2000. SCE does not expect the final decision to have a
material effect on its results of operations or financial position.

                                       9
<PAGE>

Recovery of Restructuring Implementation Costs

The independent system operator (ISO) assumed operational control of the
transmission system after the ISO and PX began accepting bids and schedules for
electricity purchases on March 31, 1998. The restructuring implementation costs
related to the start-up and development of the PX, which were paid by the
utilities, were to be recovered from all retail customers over the four-year
transition period. SCE's share of the charge is $45 million, plus interest and
fees. SCE's share of the ISO's start-up and development costs (approximately $16
million per year) will be paid over a 10-year period. In May 1998, SCE filed an
application with the CPUC to identify the categories of such costs (including
costs related to the implementation of direct access), and to establish the
reasonableness of those costs incurred in 1997.

On September 16, 1999, the CPUC approved a settlement between SCE, the CPUC's
Office of Ratepayer Advocates and several other parties allowing SCE to recover
substantially all (approximately $300 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would cease to recover these transition costs under
restructuring legislation.

Note 3.    Financial Instruments

Derivative Financial Instruments

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

SCE uses the hedge accounting method to record its derivative financial
instruments, except for gas call options and PX block forward transactions.
Hedge accounting requires an assessment that the transaction reduces risk, that
the derivative be designated as a hedge at the inception of the derivative
contract, and that the changes in the market value of a hedge move in an inverse
direction to the item being hedged. Under hedge accounting, the derivative
itself is not recorded on SCE's balance sheet. Mark-to-market accounting would
be used if the hedge accounting criteria were not met. Interest rate
differentials and amortization of premiums for interest rate caps are recorded
as adjustments to interest expense. If the derivatives were terminated before
the maturity of the corresponding debt issuance, the realized gain or loss on
the transaction would be amortized over the remaining term of the debt.

SCE has gas call options that mitigate its exposure to increases in natural gas
prices. Increases in natural gas prices tend to increase the price of
electricity. The options cover various periods from 1998 through 2001. In July
1999, SCE began participating in the PX block forward market. In the PX block
forward market, SCE can purchase monthly blocks of energy for six days a week
(excluding Sundays and holidays) for 16 hours a day. These purchases can be made
up to 12 months in advance of the delivery date. The CPUC has currently limited
SCE's use of the PX block forward market to a maximum of approximately 2,400 MW
in any month.

SCE uses the mark-to-market accounting method for its gas call options. Gains
and losses from monthly changes in market prices are recorded as income or
expense. However, the costs of the options and the market price changes are
included in the transition cost balancing account. As a result, the

                                       10
<PAGE>

mark-to-market gains or losses have no effect on earnings. Block forward
purchases receive the same accounting and ratemaking treatment as SCE's gas call
options.

Interest rate swaps are used to reduce the potential impact of interest rate
fluctuations on floating-rate long-term debt. At the balance sheet dates of
September 30, 1999, December 31, 1998, and September 30, 1998, SCE had an
interest rate swap agreement which fixed the interest rate at 5.585% for $196
million of debt due 2008; it expires February 28, 2008. The interest rate swap
agreement requires the parties to pledge collateral according to bond rating and
market interest rate changes. At September 30, 1999, SCE had pledged $26 million
as collateral due to a decline in market interest rates. SCE is exposed to
credit loss in the event of nonperformance by the counterparty to the agreement,
but does not expect the counterparty to fail to meet its obligation.

Fair Value of Financial Instruments

Fair values of financial instruments were:

<TABLE>
<CAPTION>
                                    September 30,            December 31,          September 30,
  In millions                          1999                     1998                  1998
-------------------------------------------------------------------------------------------------
                                  Cost         Fair       Cost       Fair       Cost       Fair
  Instrument                      Basis        Value      Basis      Value      Basis      Value
-------------------------------------------------------------------------------------------------

  Financial assets:
<S>                            <C>           <C>         <C>       <C>        <C>        <C>
  Decommissioning trusts       $ 1,630       $ 2,327     $ 1,534   $ 2,240    $ 1,489    $ 2,013
  Equity investments                --            --           7        72          9         88
  Gas call options                  31            23          39        31         42         50

  Financial liabilities:
  DOE decommissioning and
     decontamination fees     $     45      $     39    $     45  $     40   $     50   $     44
  Interest rate swap                --            14          --        28         --         28
  Long-term debt                 5,222         5,214       5,447     5,699      5,486      5,756
  Preferred stock subject to
     mandatory redemption          256           261         256       274        256        276
-------------------------------------------------------------------------------------------------
</TABLE>

Financial assets are carried at their fair value based on quoted market prices
for decommissioning trusts and equity investments and on financial models for
gas call options. Financial liabilities are recorded at cost. Financial
liabilities' fair values are based on: termination costs for the interest rate
swap; brokers' quotes for long-term debt and preferred stock; and discounted
future cash flows for U.S. Department of Energy (DOE) decommissioning and
decontamination fees. Due to their short maturities, amounts reported for cash
equivalents and short-term debt approximate fair value.

Gross unrealized holding gains (losses) on financial assets were:

<TABLE>
<CAPTION>
                             September 30,     December 31,   September 30,
  In millions                   1999              1998           1998
----------------------------------------------------------------------------
  Decommissioning trusts:
<S>                            <C>               <C>            <C>
  Municipal bonds              $ 179             $ 196          $ 162
  Stocks                         348               365            245
  U.S. government issues         133               115            107
  Short-term and other            37                30             10
----------------------------------------------------------------------------
                                 697               706            524
  Equity investments              --                65             79
  Gas call options                (8)               (8)             8
----------------------------------------------------------------------------
  Total                        $ 689             $ 763          $ 611
----------------------------------------------------------------------------
</TABLE>

                                       11
<PAGE>

There were no unrealized holding losses on financial assets for the years
presented, other than the unrealized holding loss on the gas call options at
September 30, 1999, and December 31, 1998.

In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which as amended will be effective
January 1, 2001, requires all derivatives to be recognized on the balance sheet
at fair value. Gains or losses from changes in fair value would be recognized in
earnings in the period of change unless the derivative is designated as a
hedging instrument. Gains or losses from hedges of a forecasted transaction or
foreign currency exposure would be reflected in other comprehensive income.
Gains or losses from hedges of a recognized asset or liability or a firm
commitment would be reflected in earnings for the ineffective portion of the
hedge. SCE anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect
earnings.

Investments

Net unrealized gains (losses) on equity investments are recorded as accumulated
other comprehensive income. Unrealized gains and losses on decommissioning trust
funds are recorded in the accumulated provision for decommissioning.

All investments are classified as available-for-sale.

Long-Term Debt

California law prohibits SCE from incurring or guaranteeing debt for its
affiliates that are not rate-regulated.

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

Debt premium, discount and issuance expenses are amortized 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.

Commercial paper intended to be refinanced for a period exceeding one year and
used to finance nuclear fuel scheduled to be used more than one year after the
balance sheet date is classified as long-term debt.

Long-term debt maturities and sinking-fund requirements for the five
twelve-month periods following September 30, 1999, are: 2000 -- $568 million;
2001 -- $647 million; 2002 -- $247 million; 2003 -- $572 million; and 2004 --
$372 million.

In December 1997, SCE Funding LLC, a special purpose entity, of which SCE is the
sole member, issued approximately $2.5 billion of rate reduction notes to
Bankers Trust Company of California, as certificate trustee for the California
Infrastructure and Economic Development Bank Special Purpose Trust SCE-1
(Trust), which is a special purpose entity established by the State of
California. The terms of the rate reduction notes generally mirror the terms of
the pass-through certificates issued by the Trust, which are known as rate
reduction certificates. 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 pursuant to
the restructuring legislation and a financing order of the CPUC and consists
generally of the right to be paid a specified amount from a


                                       12
<PAGE>
non-bypassable rate charged to residential and small commercial customers.
Despite the legal sale of the transition property by SCE to SCE Funding LLC, the
amounts reflected as assets on SCE's balance sheet have not been reduced by the
amount of the transition property sold, and the liabilities of SCE Funding LLC
for the rate reduction notes are for accounting purposes reflected as long-term
debt on the consolidated balance sheets of SCE. SCE used the proceeds from the
sale of the transition property to retire debt and equity securities. The rate
reduction notes are secured solely by the transition property and certain other
assets of SCE Funding LLC, and there is no recourse to SCE or Edison
International.

Although SCE Funding LLC is consolidated with SCE in the financial statements,
as required by generally accepted accounting principles, 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 consisted of:
<TABLE>
<CAPTION>
                                                 September 30,   December 31,   September 30,
In millions                                          1999            1998           1998
---------------------------------------------------------------------------------------------
First and refunding mortgage bonds:
<S>       <C>  <C>        <C>                     <C>            <C>             <C>
   2000-- 2026 (5.625% to 7.25%)                  $ 1,400        $ 1,550         $ 1,550
Rate reduction notes:
   2000-- 2007 (6.14% to 6.42%)                     2,039          2,217           2,307
Pollution-control bonds:
   2008-- 2031 (5.125% to 7.2% and variable)        1,196          1,201           1,201
Funds held by trustees                                 (2)            (2)             (2)
Debentures and notes:
   2000-- 2029 (5.875% to 8.25%)                    1,000            700             870
Subordinated debentures:
   2044 (8.375%)                                      100            100             100
Commercial paper for nuclear fuel                      85            108              80
Long-term debt due within one year                   (568)          (401)           (593)
Unamortized debt discount-- net                       (28)           (26)            (27)
---------------------------------------------------------------------------------------------
Total                                             $ 5,222        $ 5,447         $ 5,486
---------------------------------------------------------------------------------------------
</TABLE>

Short-Term Debt

SCE has lines of credit totaling $1.25 billion that can be used at negotiated or
bank index rates. At September 30, 1999, $50 million was available for
short-term debt and $515 million was available for the long-term refinancing of
certain variable-rate pollution-control debt.

Short-term debt consisted of commercial paper used to finance fuel inventories
and general cash requirements. Commercial paper outstanding at September 30,
1999, December 31, 1998, and September 30, 1998, was $685 million, $581 million
and $187 million, respectively. Commercial paper intended to finance nuclear
fuel scheduled to be used more than one year after the balance sheet date is
classified as long-term debt in connection with refinancing terms under
five-year term lines of credit with commercial banks. Weighted-average interest
rates were 5.5%, 5.3% and 5.6% at September 30, 1999, December 31, 1998, and
September 30, 1998, respectively.

On October 25, 1999,  SCE issued $175 million of floating rate notes due October
2000.

Note 4.    Equity

The CPUC regulates SCE's capital structure, limiting the dividends it may pay
Edison International. At September 30, 1999, SCE had the capacity to pay
approximately $586 million in additional dividends and continue to maintain its
authorized capital structure.


                                       13
<PAGE>

Changes in SCE's common shareholder's equity were as follows:

Three months ended September 30, 1998, and 1999:

<TABLE>
<CAPTION>
                                                                         Accumulated                       Total
                                                         Additional         Other                         Common
                                             Common        Paid-in      Comprehensive     Retained     Shareholder's
In millions                                   Stock        Capital         Income         Earnings        Equity
--------------------------------------------------------------------------------------------------------------------
<S>             <C> <C>                     <C>           <C>              <C>          <C>             <C>
Balance at June 30, 1998                    $ 2,168       $  334           $  61        $ 1,079         $ 3,642
--------------------------------------------------------------------------------------------------------------------
Net income                                                                                  169             169
Unrealized loss on securities                                                (22)                           (22)
Dividends declared on common stock                                                         (422)           (422)
Dividends declared on preferred stock                                                        (6)             (6)
--------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1998               $ 2,168       $  334           $  39         $  820         $ 3,361
--------------------------------------------------------------------------------------------------------------------
Balance at June 30, 1999                    $ 2,168       $  334             $ -         $  694         $ 3,196
--------------------------------------------------------------------------------------------------------------------
Net income                                                                                  169             169
Unrealized gain on securities                                                 53                             53
Tax effect                                                                   (21)                           (21)
Reclassified adjustment for gains
   included in net income                                                    (23)                           (23)
Tax effect                                                                     9                              9
Dividends declared on common stock                                                         (269)           (269)
Dividends declared on preferred stock                                                        (8)             (8)
Capital stock expense                                          1                                              1
-------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1999               $ 2,168       $  335           $  18         $  586         $ 3,107
-------------------------------------------------------------------------------------------------------------------

Nine months ended September 30, 1998, and 1999:

In millions
-------------------------------------------------------------------------------------------------------------------
Balance at December  31, 1997               $ 2,168       $  334           $  48        $ 1,408         $ 3,958
-------------------------------------------------------------------------------------------------------------------
Net income                                                                                  394             394
Unrealized loss on securities                                                 (2)                            (2)
Tax effect                                                                    (7)                            (7)
Dividends declared on common stock                                                         (960)           (960)
Dividends declared on preferred stock                                                       (19)            (19)
Stock option appreciation                                                                    (3)             (3)
-------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1998               $ 2,168       $  334           $  39         $  820         $ 3,361
-------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998                $ 2,168       $  334           $  39         $  794         $ 3,335
-------------------------------------------------------------------------------------------------------------------
Net income                                                                                  363             363
Unrealized gain on securities                                                 42                             42
Tax effect                                                                   (17)                           (17)
Reclassified adjustment for gains
   included in net income                                                    (77)                           (77)
Tax effect                                                                    31                             31
Dividends declared on common stock                                                         (548)           (548)
Dividends declared on preferred stock                                                       (20)            (20)
Stock option appreciation                                                                    (3)             (3)
Capital stock expense                                          1                                              1
-------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1999               $ 2,168       $  335           $  18         $  586         $ 3,107
-------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       14
<PAGE>

Twelve months ended September 30, 1998, and 1999:

<TABLE>
<CAPTION>
                                                                         Accumulated                       Total
                                                         Additional         Other                         Common
                                             Common        Paid-in      Comprehensive     Retained     Shareholder's
In millions                                   Stock        Capital         Income         Earnings        Equity
--------------------------------------------------------------------------------------------------------------------
<S>                  <C> <C>                <C>           <C>              <C>          <C>             <C>
Balance at September 30, 1997               $ 2,168       $  334           $  37        $ 2,559         $ 5,098
--------------------------------------------------------------------------------------------------------------------
Net income                                                                                  516             516
Unrealized gain on securities                                                  4                              4
Tax effect                                                                    (2)                            (2)
Dividends declared on common stock                                                       (2,227)         (2,227)
Dividends declared on preferred stock                                                       (26)            (26)
Stock option appreciation                                                                    (2)             (2)
--------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1998               $ 2,168       $  334           $  39         $  820         $ 3,361
--------------------------------------------------------------------------------------------------------------------
Net income                                                                                  484             484
Unrealized gain on securities                                                 58                             58
Tax effect                                                                   (15)                           (15)
Reclassified adjustment for gains
   included in net income                                                   (107)                          (107)
Tax effect                                                                    43                             43
Dividends declared on common stock                                                         (689)           (689)
Dividends declared on preferred stock                                                       (26)            (26)
Stock option appreciation                                                                    (3)             (3)
Capital stock expense                                          1                                              1
-------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1999               $ 2,168       $  335           $  18         $  586         $ 3,107
-------------------------------------------------------------------------------------------------------------------
</TABLE>

Authorized common stock is 560 million shares with no par value. Authorized
shares of preferred and preference stock are: $25 cumulative preferred -- 24
million; $100 cumulative preferred -- 12 million; and preference -- 50 million.
All cumulative preferred stocks are redeemable.

Mandatorily redeemable preferred stocks are subject to sinking-fund provisions.
When preferred shares are redeemed, the premiums paid are charged to common
equity.

Preferred stock redemption requirements for the five twelve-month periods
following September 30, 1999, are: 2000 and 2001 -- zero; 2002 -- $105 million;
2003 -- $9 million; and 2004 -- $9 million.

                                       15
<PAGE>

Cumulative preferred stock consisted of:
<TABLE>
<CAPTION>
                                                                September 30,    December 31,   September 30,
Dollars in millions, except per share amounts                       1999             1998           1998
-------------------------------------------------------------------------------------------------------------
                                            September 30, 1999
                                       -------------------------
                                          Shares     Redemption
                                       Outstanding     Price
                                       -------------------------

Not subject to mandatory redemption:

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

Subject to mandatory redemption:
$100 par value:
6.05% Series                               750,000     $100.00     $   75         $   75         $   75
6.45                                     1,000,000      100.00        100            100            100
7.23                                       807,000      100.00         81             81             81
-----------------------------------------------------------------------------------------------------------
Total                                                               $ 256          $ 256          $ 256
-----------------------------------------------------------------------------------------------------------
</TABLE>

In the third quarter of 1998, 10,000 shares of Series 7.23% preferred stock were
redeemed. In the second quarter of 1998, 2.2 million shares of Series 5.80%
preferred stock and 183,000 shares of Series 7.23% were redeemed. There were no
preferred stock issuances for the periods presented.

Note 5.         Income Taxes

SCE and its subsidiaries will be included in Edison International's consolidated
federal income tax and combined state franchise tax returns. Under income tax
allocation agreements, each subsidiary calculates its own tax liability.

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.

                                       16
<PAGE>

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

<TABLE>
<CAPTION>
                                                          September 30,   December 31,  September 30,
In millions                                                   1999            1998          1998
-----------------------------------------------------------------------------------------------------
Deferred tax assets:
<S>                                                        <C>             <C>            <C>
Property-related                                           $   196         $   197        $   208
Unrealized gains or losses                                     408             387             --
Investment tax credits                                         133             152            153
Regulatory balancing accounts                                  133              96             84
Decommissioning-related                                        129             126            801
Unbilled revenue                                               124             117            147
Other                                                          396             356             34
------------------------------------------------------------------------------------------------------
Total                                                      $ 1,519         $ 1,431        $ 1,427
------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related                                           $ 2,685         $ 3,005        $ 3,046
Capitalized software costs                                     236             196            173
Regulatory balancing accounts                                  434             162             62
Unrealized gains and losses                                    306             284            240
Other                                                          484             502            517
------------------------------------------------------------------------------------------------------
Total                                                      $ 4,145         $ 4,149        $ 4,038
------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net                    $ 2,626         $ 2,718        $ 2,611
------------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits                               $ 2,769         $ 2,993        $ 2,880
Included in current assets                                     143             275            269
</TABLE>

The current and deferred components of income tax expense were:

<TABLE>
<CAPTION>
                                                 3 Months Ended           9 Months Ended         12 Months Ended
                                                  September 30,            September 30,          September 30,
----------------------------------------------------------------------------------------------------------------
In millions                                     1999        1998         1999        1998       1999       1998
----------------------------------------------------------------------------------------------------------------
Current:
<S>                                           <C>          <C>         <C>          <C>       <C>        <C>
Federal                                       $  199       $  96       $  263       $  452    $  261     $  486
State                                             52          22           69          100        70        105
----------------------------------------------------------------------------------------------------------------
                                                 251         118          332          552       331        591
----------------------------------------------------------------------------------------------------------------
Deferred -- federal and state:
Accrued charges                                  (54)        (10)         (38)         (24)      (57)       (33)
Amortization of regulatory assets                 10          63           22           53        33         53
Depreciation                                     (52)        (22)        (148)        (106)     (211)      (115)
Investment and energy tax credits-- net          (11)         (6)         (32)         (22)      (85)       (27)
Regulatory balancing accounts                     61         152          198           36       339         66
State tax-- privilege year                       (17)         (7)          10           --        10         (2)
Unbilled revenue                                 (21)       (100)          (7)         (98)       23        (51)
Other                                            (11)         (2)          (7)          15       (16)        43
----------------------------------------------------------------------------------------------------------------
                                                 (95)         68           (2)        (146)       36        (66)
----------------------------------------------------------------------------------------------------------------
Total income tax expense                      $  156      $  186       $  330       $  406    $  367     $  525
----------------------------------------------------------------------------------------------------------------
Classification of income taxes:
Included in operating income                  $  154      $  172       $  317       $  397    $  366     $  541
Included in other income                           2          14           13            9         1        (16)
</TABLE>

The composite federal and state statutory income tax rate was 40.551% for the
three, nine and twelve months ended September 30, 1999, and 1998.

                                       17
<PAGE>

The federal statutory income tax rate is reconciled to the effective tax rate
below:

<TABLE>
<CAPTION>
                                         3 Months Ended          9 Months Ended          12 Months Ended
                                          September 30,           September 30,           September 30,
--------------------------------------------------------------------------------------------------------
                                       1999          1998      1999         1998      1999         1998
--------------------------------------------------------------------------------------------------------
<S>                                     <C>          <C>        <C>         <C>        <C>         <C>
Federal statutory rate                  35.0%        35.0%      35.0%       35.0%      35.0%       35.0%
Ad valorem lien date adjustment         (0.2)         3.0        0.3         1.6       (0.5)        1.2
Amortization of regulatory assets        2.7         17.7        2.8         6.6        3.5         5.0
Capitalized software                    (4.3)         1.0       (2.7)       (0.1)      (2.8)       (0.5)
Property-related and other               9.0         (8.8)       8.0         2.5        8.7         4.8
Investment and energy tax credits       (3.2)        (1.2)      (4.5)       (1.6)      (9.7)       (1.7)
State tax-- net of federal deduction     8.9          5.8        8.5         6.3        8.7         6.3
--------------------------------------------------------------------------------------------------------
Effective tax rate                      47.9%        52.5%      47.4%       50.3%      42.9%       50.1%
--------------------------------------------------------------------------------------------------------
</TABLE>

Note 6. Employee 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 $6
million, $18 million and $23 million for the three, nine and twelve months ended
September 30, 1999, respectively, and $4 million, $12 million and $16 million
for the three, nine and twelve months ended September 30, 1998, respectively.

Pension Plan

SCE has a noncontributory, defined-benefit pension plan that covers employees
meeting minimum service requirements. In April 1999, SCE adopted a cash balance
feature for its non-represented employees. SCE recognizes pension expense as
calculated by the actuarial method used for ratemaking. In 1998, SCE adopted a
new accounting standard that revises the disclosure requirements for pension
plans. Prior periods have been restated.


                                       18
<PAGE>

Information on plan assets and benefit obligations is shown below:

<TABLE>
<CAPTION>
                                                         9 Months Ended    Year Ended     9 Months Ended
                                                          September 30,   December 31,     September 30,
In millions                                                   1999            1998             1998
--------------------------------------------------------------------------------------------------------
Change in benefit obligation
<S>                                                          <C>            <C>             <C>
Benefit obligation at beginning of period                    $  2,251       $ 2,094         $ 2,094
Service cost                                                       50            59              42
Interest cost                                                     114           141             105
Plan amendments                                                   (25)           --              --
Actuarial loss                                                     --            90              --
Benefits paid                                                    (105)         (133)           (103)
--------------------------------------------------------------------------------------------------------
Benefit obligation at end of period                          $  2,285       $ 2,251         $ 2,138
--------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of period             $  2,552       $ 2,298         $ 2,298
Actual return on plan assets                                      241           334              63
Employer contributions                                             51            53              43
Benefits paid                                                    (105)         (133)           (103)
-------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                   $  2,739       $ 2,552         $ 2,301
-------------------------------------------------------------------------------------------------------
Funded status                                                $    454       $   301         $   163
Unrecognized net loss (gain)                                     (463)         (372)           (227)
Unrecognized transition obligation (17-year amortization)          30            33              35
Unrecognized prior service cost                                   133           168             169
-------------------------------------------------------------------------------------------------------
Pension asset (liability)                                    $    154       $   130         $   140
------------------------------------------------------------------------------------------------------
Discount rate                                                   6.75%          6.75%         7.0%
Rate of compensation increase                                   5.0%           5.0%          5.0%
Expected return on plan assets                                  7.5%           7.5%          8.0%
</TABLE>

The components of pension expense were:

<TABLE>
<CAPTION>
                                                3 Months Ended       9 Months Ended       12 Months Ended
                                                  September 30,       September 30,        September 30,
------------------------------------------------------------------------------------------------------------
In millions                                   1999       1998       1999      1998        1999       1998
------------------------------------------------------------------------------------------------------------
<S>                                          <C>        <C>        <C>       <C>         <C>        <C>
Service cost                                 $  16      $  14      $  50     $  42       $  67      $  53
Interest cost                                   38         35        114       105         150        139
Expected return on plan assets                 (48)       (45)      (144)     (135)       (179)      (175)
Net amortization and deferral                    2          4          7        12           9         13
------------------------------------------------------------------------------------------------------------
Pension expense under accounting standards       8          8         27        24          47         30
Regulatory adjustment-- deferred                 5          5         12        15           8         22
------------------------------------------------------------------------------------------------------------
Net pension expense recognized               $  13      $  13      $  39     $  39       $  55      $  52
------------------------------------------------------------------------------------------------------------
</TABLE>

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.  In 1998,  SCE  adopted a new  accounting  standard  that  revises the
disclosure  requirements for  postretirement  benefit plans.  Prior periods have
been restated.

                                       19
<PAGE>

Information on plan assets and benefit obligations is shown below:

<TABLE>
<CAPTION>
                                                       9 Months Ended        Year Ended     9 Months Ended
                                                        September 30,       December 31,     September 30,
     In millions                                            1999                1998             1998
-----------------------------------------------------------------------------------------------------------
     Change in benefit obligation
<S>                                                        <C>                <C>               <C>
     Benefit obligation at beginning of period             $ 1,545            $ 1,533           $ 1,533
     Service cost                                               33                 41                27
     Interest cost                                              78                 99                78
     Actuarial loss (gain)                                      --                (74)               --
     Benefits paid                                             (45)               (54)              (48)
-----------------------------------------------------------------------------------------------------------
     Benefit obligation at end of period                   $ 1,611            $ 1,545           $ 1,590
-----------------------------------------------------------------------------------------------------------
     Change in plan assets
     Fair value of plan assets at beginning of period      $ 1,029            $   815           $   815
     Actual return on plan assets                               57                147                48
     Employer contributions                                     75                121                81
     Benefits paid                                             (45)               (54)              (48)
----------------------------------------------------------------------------------------------------------
     Fair value of plan assets at end of period            $ 1,116            $ 1,029           $   896
----------------------------------------------------------------------------------------------------------
     Funded status                                         $  (495)           $  (516)          $  (694)
     Unrecognized net loss                                      84                 84               241
     Unrecognized transition obligation (20-year
        amortization)                                          355                376               382
----------------------------------------------------------------------------------------------------------
     Recorded asset (liability)                            $   (56)           $   (56)          $   (71)
----------------------------------------------------------------------------------------------------------
     Discount rate                                            6.75%              6.75%              7.0%
     Expected return on plan assets                           7.5%               7.5%               8.0%
</TABLE>

The components of postretirement benefits other than pension expense were:

<TABLE>
<CAPTION>
                                          3 Months Ended       9 Months Ended     12 Months Ended
                                           September 30,        September 30,      September 30,
-------------------------------------------------------------------------------------------------
 In millions                              1999      1998       1999     1998      1999    1998
-------------------------------------------------------------------------------------------------
<S>                                       <C>       <C>        <C>      <C>       <C>     <C>
 Service cost                             $ 11      $  9       $ 33     $ 27      $ 47    $ 36
 Interest cost                              26        26         78       78        99     102
 Expected return on plan assets            (19)      (16)       (57)     (48)      (71)    (59)
 Amortization of loss (gain)                --         1         --        3        (2)      1
 Amortization of transition obligation       7         7         21       21        27      27
-------------------------------------------------------------------------------------------------
 Total expense                            $ 25      $ 27       $ 75     $ 81     $ 100   $ 107
-------------------------------------------------------------------------------------------------
</TABLE>

The assumed rate of future increases in the per-capita cost of health care
benefits is 8.25% for 1999, gradually decreasing to 5.0% for 2009 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of September 30, 1999, by $275 million
and annual aggregate service and interest costs by $34 million. Decreasing the
health care cost trend rate by one percentage point would decrease the
accumulated obligation as of September 30, 1999, by $220 million and annual
aggregate service and interest costs by $26 million.

Stock Option Plans

In April 1998, Edison International shareholders approved the Edison
International Equity Compensation Plan. The plan replaces the Long-Term
Incentive Compensation Program, consisting of officer, director, and management
plans, which was adopted by Edison International shareholders in 1992. No new
awards will be made under the prior program; however, it will remain in effect
as long as any awards remain outstanding under the prior program.

                                       20
<PAGE>

The prior program participated in the use of 8.2 million shares of common stock
reserved for potential issuance under various stock compensation programs to
directors, officers and senior managers of Edison International and its
affiliates. Under these programs, options on 2.8 million shares of Edison
International common stock are currently outstanding to officers and senior
managers.

The new plan authorizes the annual issuance of shares equal to one percent of
the issued and outstanding shares of Edison International common stock as of
December 31 of the prior year. This authorization is cumulative so that to the
extent shares are not needed to meet new plan requirements in any year, the
excess authorized shares carry over to subsequent years until plan termination.
One percent of the issued and outstanding Edison International common stock on
December 31, 1998, and December 31, 1997, was 3.5 million and 3.8 million
shares, respectively. Under the new plan, options on 4.0 million shares of
Edison International common stock are currently outstanding to officers and
senior managers of SCE.

Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market value
of the underlying stock at the date of grant. All Edison International stock
options granted prior to 1999 include a dividend equivalent feature. Generally,
for options issued before 1994, amounts equal to dividends accrue on the options
at the same time and at the same rate as would be payable on the number of
shares of Edison International common stock covered by the options. The amounts
accumulate without interest. For Edison International stock options issued after
1993, dividend equivalents are subject to reduction unless certain shareholder
return performance criteria are met. Beginning with the 1999 Edison
International stock option awards, some stock options include a dividend
equivalent feature, and some stock options do not include a dividend equivalent
feature.

The new plan's stock options have a 10-year term with one-fourth of the total
award vesting after each of the first four years of the award term. The prior
program's stock options have a 10-year term with one-third of the total award
vesting after each of the first three years of the award term. If an optionee
retires, dies or is permanently and totally disabled during the vesting period,
the unvested options will vest and be exercisable to the extent of 1/36 (prior
program) or 1/48 (the new plan) of the grant for each full month of service
during the vesting period.

Unvested options of any person who has served in the past on the Edison
International or SCE Management Committee (which was dissolved in 1993) will
vest and be exercisable upon the member's retirement, death or permanent and
total disability. Upon retirement, death or permanent and total disability, the
vested options may continue to be exercised within their original terms by the
recipient or beneficiary. If an optionee is terminated other than by retirement,
death or permanent and total disability, options which had vested as of the
prior anniversary date of the grant are forfeited unless exercised within 180
days of the date of termination. All unvested options are forfeited on the date
of termination.

SCE measures compensation expense related to stock-based compensation by the
intrinsic value method. Compensation expense recorded under the
stock-compensation program was $2 million, $3 million and $5 million for the
three, nine and twelve months ended September 30, 1999, respectively, and $1
million, $8 million and $9 million for the three, nine and twelve months ended
September 30, 1998, respectively.

Stock-based compensation expense under the fair-value method of accounting would
have resulted in pro forma earnings of $160 million, $342 million and $458
million for the three, nine and twelve months ended September 30, 1999,
respectively; and $163 million, $377 million and $492 million for the three,
nine and twelve months ended September 30, 1998, respectively.


                                       21
<PAGE>

The fair value for each option granted, reflecting the basis for the above pro
forma disclosures, was determined on the date of grant using the Black-Scholes
option-pricing model. The following assumptions were used in determining fair
value through the model:

                                   12 Months Ended
                                    September 30,
---------------------------------------------------------

                                 1999             1998
---------------------------------------------------------

   Expected life                7 years         7 years
   Risk-free interest rate    4.7% - 5.6%     4.7% - 5.6%
   Expected volatility         17% - 18%          17%
---------------------------------------------------------

The application of fair-value accounting to calculate the pro forma disclosures
above is not an indication of future income statement effects. The pro forma
disclosures do not reflect the effect of fair-value accounting on stock-based
compensation awards granted prior to 1995.

Note 7. 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.

The investment in each project, as included in the consolidated balance sheet as
of September 30, 1999, was:

<TABLE>
<CAPTION>
                                         Original     Accumulated
                                          Cost of   Depreciation and      Under Ownership
In millions                              Facility     Amortization      Construction Interest
---------------------------------------------------------------------------------------------
Transmission systems:
<S>                                      <C>            <C>            <C>        <C>
  Eldorado                               $    36        $   6          $   3      60%
  Pacific Intertie                           241           81              6      50%
Generating stations:
  Four Corners Units 4 and 5 (coal)          460          320              2      48%
  Mohave (coal)                              321          210              3      56%
  Palo Verde (nuclear)(1)                  1,608        1,091             16      16%
  San Onofre (nuclear)(1)                  4,264        3,139             22      75%
-------------------------------------------------------------------------------------------
Total                                    $ 6,930      $ 4,847          $  52
--------------------------------------------------------------------------------------------
</TABLE>

(1)  Reported as "Unamortized nuclear investment -- net."

Note 8. Leases

SCE has operating leases, primarily for vehicles, with varying terms, provisions
and expiration dates.

Estimated remaining commitments for noncancelable leases at September 30, 1999,
were:

Year ended December 31,         In millions
-------------------------------------------
1999                             $   3
2000                                13
2001                                10
2002                                 6
2003                                 5
Thereafter                           9
-------------------------------------------
Total                            $  46
-------------------------------------------

                                       22
<PAGE>

Note 9. Commitments

Nuclear Decommissioning

Decommissioning is estimated to cost $1.9 billion in current-year dollars, based
on site-specific studies performed in 1998 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 $8.6 billion through 2060 to decommission its nuclear facilities.
This estimate is based on SCE's current dollar decommissioning costs, escalated
at rates ranging from 0.3% to 10.0% (depending on the cost element) annually.
These costs are expected to be funded from independent decommissioning trusts,
which, effective June 3, 1999, receive contributions of approximately $25
million per year. SCE estimates annual after-tax earnings on the decommissioning
funds of 3.9% to 4.9%.

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 2013 for San Onofre Units 2 and 3, and 2025-2027 for Palo
Verde. Decommissioning costs, which are accrued and recovered through
non-bypassable customer rates over the term of each nuclear facility's operating
license, are recorded as a component of depreciation expense.

In June 1999, the CPUC authorized SCE to access its nuclear decommissioning
trust funds to commence decommissioning of San Onofre Unit 1 (shut down in 1992
pursuant to a CPUC agreement) effective immediately.

Decommissioning expense was $34 million, $103 million and $149 million for the
three, nine and twelve months ended September 30, 1999, respectively, and $41
million, $119 million and $155 million for the three, nine and twelve months
ended September 30, 1998, respectively. The accumulated provision for
decommissioning, excluding San Onofre Unit 1, was $1.3 billion at September 30,
1999, and $1.2 billion at both December 31, 1998, and September 30, 1998. The
estimated costs to decommission San Onofre Unit 1 ( approximately $360 million)
are recorded as a liability.

Decommissioning funds collected in rates are placed in independent trusts,
which, together with accumulated earnings, will be utilized solely for
decommissioning.

Trust investments (cost basis) include:

<TABLE>
<CAPTION>
                              Maturity         September 30,    December 31,   September 30,
  In millions                  Dates              1999             1998           1998
--------------------------------------------------------------------------------------------
<S>                          <C>    <C>         <C>             <C>             <C>
  Municipal bonds            2000 - 2033        $  571          $  547          $  537
  Stocks                          -                503             550             543
  U.S. government issues     1999 - 2029           447             355             396
  Short-term and other       1999 - 2030           109              82              13
--------------------------------------------------------------------------------------------
  Total                                        $ 1,630         $ 1,534         $ 1,489
--------------------------------------------------------------------------------------------
</TABLE>

Trust fund earnings (based on specific identification) increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were $25
million, $49 million and $68 million for the three, nine and twelve months ended
September 30, 1999, respectively; and $17 million, $44 million and $55 million
for the three, nine and twelve months ended September 30, 1998, respectively.
Proceeds from sales of securities (which are reinvested) were $776 million, $1.8
billion and $2.1 billion for the three, nine and twelve months ended September
30, 1999, respectively; and $342 million, $911 million and $1.1 billion for the
three, nine and twelve months ended September 30, 1998, respectively.
Approximately 90% of the trust fund contributions were tax-deductible.

                                       23
<PAGE>

Other Commitments

SCE has fuel supply contracts which require payment only if the fuel is made
available for purchase. Additionally, SCE's gas and coal fuel contracts require
payment of certain fixed charges whether or not gas or coal is delivered.

SCE has power-purchase contracts with certain qualifying facilities (QF)
(cogenerators and small power producers) and other utilities. These contracts
provide for capacity payments if a facility meets certain performance
obligations and energy payments based on actual power supplied to SCE. There are
no requirements to make debt-service payments. As a result of the utility
industry restructuring, SCE has entered into purchased-power settlements to end
its contract obligations with certain QFs. The settlements (approximately $300
million) are reported as long-term liabilities. Settlement payments are being
recovered through the CTC.

SCE has unconditional purchase obligations for part of a power plant's
generating output, as well as firm transmission service from another utility.
Minimum payments are based, in part, on the debt-service requirements of the
provider, whether or not the plant or transmission line is operable. SCE's
minimum commitment under both contracts is approximately $172 million through
2017. The purchased-power contract (approximately $30 million) is expected to
provide approximately 5.5% of current or estimated future operating capacity,
and is reported as a long-term liability. The transmission service contract
requires a minimum payment of approximately $6 million a year.

Certain commitments for the years 1999 through 2003 are estimated below:

<TABLE>
<CAPTION>
In millions                            1999    2000    2001    2002   2003
---------------------------------------------------------------------------
<S>                                    <C>     <C>    <C>     <C>    <C>
Projected construction expenditures    $ 975   $ 940  $ 891   $ 860  $ 856
Fuel supply contracts                    168     138    124     140    133
Purchased-power capacity payments        654     629    627     625    620
---------------------------------------------------------------------------
</TABLE>

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 Protection

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 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).

                                       24
<PAGE>

SCE's recorded estimated minimum liability to remediate its 49 identified sites
is $165 million. The ultimate costs to clean up SCE's identified sites may vary
from its recorded liability due to numerous uncertainties inherent in the
estimation process, such as: the extent and nature of contamination; the
scarcity of reliable data for identified sites; the varying costs of alternative
cleanup methods; developments resulting from investigatory studies; the
possibility of identifying additional sites; and the time periods over which
site remediation is expected to occur. SCE believes that, due to these
uncertainties, it is reasonably possible that cleanup costs could exceed its
recorded liability by up to $284 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of
reasonably possible outcomes. SCE has sold all of its gas- and oil-fueled
generation plants and has retained some liability associated with the divested
properties.

The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $85 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. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a regulatory
asset of $130 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 now 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
$5 million to $15 million. Recorded costs for the twelve-month period ended
September 30, 1999, were $15 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 and,
based upon the CPUC's regulatory treatment of environmental-cleanup 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.

Nuclear Insurance

Federal law limits public liability claims from a nuclear incident to $9.8
billion. SCE and other owners of San Onofre and Palo Verde have purchased the
maximum private primary insurance available ($200 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 U.S. 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 $88 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 $175 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.

                                       25
<PAGE>

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. These policies are issued primarily by mutual insurance companies
owned by utilities with nuclear facilities. 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 $21 million per year. Insurance premiums are charged to operating expense.

Spent Nuclear Fuel

Under federal law, the DOE is responsible for the selection and development of a
facility for disposal of spent nuclear fuel and high-level radioactive waste.
Such a facility was to be in operation by January 1998. However, the DOE did not
meet its obligation. It is not certain when the DOE will begin accepting spent
nuclear fuel from San Onofre or from other nuclear power plants.

SCE has primary responsibility for the interim storage of its spent nuclear fuel
at San Onofre. Current capability to store spent fuel is estimated to be
adequate through 2005. Meeting spent-fuel storage requirements beyond that
period would require new and separate interim storage facilities, the costs for
which have not been determined. Extended delays by the DOE could lead to
consideration of costly alternatives involving 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 one mill per
kilowatt-hour of nuclear-generated electricity sold after April 6, 1983.

Palo Verde on-site spent fuel storage capacity will accommodate needs until 2002
for Units 1 and 2, and until 2003 for Unit 3. Arizona Public Service Company,
operating agent for Palo Verde, is constructing an interim fuel storage facility
that is expected to be completed in 2002.

SCE and other owners of nuclear power plants may be able to recover interim
storage costs arising from DOE delays in the acceptance of utility spent nuclear
fuel by pursuing relief under the terms of the contracts, as directed by the
courts, or through other court actions.

                                       26
<PAGE>

Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition

Results of Operations

Earnings

Southern California Edison Company's (SCE) earnings for the three, nine and
twelve months ended September 30, 1999, were $160 million, $343 million and $458
million, respectively, compared with $163 million, $375 million and $491 million
for the same periods in 1998. The year-to-date and twelve-months-ended decreases
were mainly due to the scheduled refueling outages at the San Onofre Nuclear
Generating Station during the first half of 1999.

Operating Revenue

As a result of industry restructuring, customers have an option to buy power
from SCE or directly from the power exchange (PX), thus becoming direct access
customers. Direct access customers are continuing to be billed by SCE, but are
also given a credit for the generation portion of their bills. Operating revenue
decreased 3% for the three months ended September 30, 1999, compared to the
year-earlier period, primarily due to a credit given to customers who choose
direct access. Operating revenue increased for the nine months ended September
30, 1999, compared to the same period last year. The increase resulted primarily
from maintenance service SCE is providing the new owners of the divested gas-
and oil-fueled plants, partially offset by the energy credit given to direct
access customers in the third quarter of 1999. Over 93% of operating revenue was
from retail sales. Retail rates are regulated by the California Public Utilities
Commission (CPUC) and wholesale rates are regulated by the Federal Energy
Regulatory Commission (FERC).

Due to warmer weather during the summer months, operating revenue during the
third quarter of each year is significantly higher than other quarters.

Legislation enacted in September 1996 provided for, among other things, a 10%
rate reduction for residential and small commercial customers beginning in 1998
and other rates to remain frozen at June 1996 levels (system average of
10.1(cent) per kilowatt-hour). See the discussion in Regulatory Environment
below.

Operating Expenses

Fuel expense decreased 33% and 40%, respectively, for the nine and twelve months
ended September 30, 1999, compared with the same periods in 1998. The decreases
resulted from the sale of the generating plants in 1998.

Since April 1, 1998, SCE has been required to sell all of its generated power
through the PX and acquire all of its power through the PX to distribute to its
customers. These transactions with the PX are reported net. PX purchased-power
expense decreased for the quarter ended September 30, 1999, compared to the
year-earlier period, due to lower prices and lower volume of purchases during
the third quarter of 1999. The lower volume was partially due to an increase in
direct access customers. PX purchased-power expense increased for the
year-to-date and twelve-months ended periods due to higher prices in May and
June of 1999. There were no comparable purchases during the first quarter of
1998. SCE is continuing to purchase power under existing contracts from certain
nonutility generators (known as qualifying facilities) and from other utilities.
This purchased power is also sold through the PX. Purchased-power expense --
contracts decreased for the three, nine and twelve months ended September 30,
1999, compared to the same periods last year, primarily due to SCE entering into
settlements to end its contractual obligations with certain qualifying
facilities. SCE was required under federal law to purchase power from certain
qualifying facilities at CPUC-mandated prices even though energy and capacity
prices under these contracts are generally higher than other sources. For the
twelve months ended September 30, 1999, SCE paid about $1.5 billion (including
energy and capacity payments) more for these power purchases than the cost of
power available from other sources.

                                       27
<PAGE>

Provisions for regulatory adjustment clauses increased for the three months
ended September 30, 1999, compared to the year-earlier period. The quarterly
increase primarily reflects overcollections related to the difference between
generation-related revenue and generation-related costs and overcollections
related to the administration of public purpose funds. These overcollections
were partially offset by revenue deferrals related to the rate-making treatment
of the rate reduction notes. This rate-making treatment has allowed for the
deferral of the recovery of a portion of the transition-related costs, from a
four-year period to a 10-year period. Provisions for regulatory adjustment
clauses decreased for the nine and twelve months ended September 30, 1999,
compared to same periods last year. These decreases were mainly due to
undercollections related to the difference between generation-related revenue
and generation-related costs and the rate-making treatment of the rate reduction
notes. These undercollections were partially offset by overcollections related
to the administration of public purpose funds. See the discussion in Revenue and
Cost-Recovery Mechanisms.

Other operating expenses decreased 16% for the three months ended September 30,
1999, compared to the same period in 1998, primarily due to a reduction in
mandated transmission service (known as must-run reliability services) expenses
due to a new calculation method adopted by the FERC, partially offset by an
increase in grid management payments to the independent system operator (ISO).
Other operating expenses increased for the nine and twelve months ended
September 30, 1999, mostly due to increases in direct access activities and PX
costs incurred by SCE in early 1999. These increases were partially offset by
the decrease in the third quarter discussed above.

Maintenance expense decreased 19% for the quarter ended September 30, 1999,
compared to the year-earlier period, mainly due to lower expenses incurred at
distribution facilities.

Depreciation, decommissioning and amortization expense increased for the three,
nine and twelve months ended September 30, 1999, compared to the prior-year
periods, primarily due to the recovery of direct-access related items as a
result of a recent CPUC decision. The twelve-months-ended increase also reflects
the amortization of the loss on the sales of the generating plants in 1998. The
amortization of the loss on plant sales is part of the competition transition
charge (CTC) mechanism.

Income taxes decreased for the three, nine and twelve months ended September 30,
1999, compared to the same periods in 1998, primarily due to the increased tax
expense associated with the gain on plant sales in 1998. The year-to-date and
twelve-months-ended decreases are also due to lower pre-tax income for those
periods. In addition, the twelve-months-ended decrease resulted from the
increased tax expense associated with CTC amortization in the 1998 period.

Net loss (gain) on sale of utility plant resulted from the sale of SCE's 12 gas-
and oil-fueled generation plants in 1998. Gains were used to reduce stranded
costs. Losses will be recovered from customers over the transition period.

Other Income

The provision for rate phase-in plan reflected a CPUC-authorized, 10-year rate
phase-in plan, which deferred the collection of revenue during the first four
years of operation for the Palo Verde units. The deferred revenue (including
interest) was collected evenly over the final six years of each unit's plan. The
plan ended in February 1996, September 1996 and January 1998 for Units 1, 2 and
3, respectively. The provision was a non-cash offset to the collection of
deferred revenue.

Other nonoperating income decreased for the three months ended September 30,
1999, compared to the prior-year period, primarily due to additional accruals
for regulatory matters in 1999 and the reversal of an accrual in 1998, partially
offset by the gain on sale of an equity investment. Other nonoperating income
increased for the both the nine and twelve months ended September 30, 1999,
mostly due to the gain on sales of equity investments, partially offset by the
third quarter decreases discussed above. The twelve-months-ended increase also
reflects regulatory accruals made in the fourth quarter of 1997.

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Interest Expense

Other interest expense increased 30% and 28%, respectively, for the three and
nine months ended September 30, 1999, compared to the same periods in 1998,
mostly due to higher overall short-term debt balances necessary to meet general
cash requirements during the periods.

Financial Condition

SCE's liquidity is primarily affected by debt maturities, dividend payments and
capital expenditures. Capital resources include cash from operations and
external financings.

Edison International's board of directors has authorized the repurchase of up to
$2.8 billion (increased from $2.3 billion in July 1998) of its outstanding
shares of common stock. Edison International repurchased approximately 101
million shares ($2.4 billion) between January 1995 and February 28, 1999, funded
by dividends from its subsidiaries and the proceeds of the rate reduction notes
issuance.

Cash Flows from Operating Activities

Net cash provided by operating activities totaled $596 million, $1.4 billion and
$1.6 billion, respectively, for the three, nine and twelve months ended
September 30, 1999, compared with $181 million, $870 million and $1.3 billion
for the same periods in 1998. Cash from operations exceed capital requirements
for all periods presented. SCE's cash flow coverage of dividends for the three,
nine and twelve months ended September 30, 1999, was 2.2 times, 2.6 times and
2.2 times, respectively, compared to 0.4 times, 0.9 times and 0.6 times for the
year-earlier periods. The increases in 1999 primarily reflect the special
dividends SCE paid to Edison International ($350 million in second quarter 1998,
$330 million in third quarter 1998 and $1.2 billion in December 1997 from the
rate reduction note proceeds).

Cash Flows from Financing Activities

At September 30, 1999, SCE had total credit lines of $1.25 billion, with $50
million available for short-term debt and $515 million available for the
long-term refinancing of its variable-rate pollution-control bonds. These
unsecured lines of credit are at negotiated or bank index rates and expire in
2002.

Short-term debt is used to finance fuel inventories and general cash
requirements. Long-term debt is used mainly to finance capital expenditures.
External financings are influenced by market conditions and other factors,
including limitations imposed by SCE's articles of incorporation and trust
indenture. As of September 30, 1999, SCE could issue approximately $11.2 billion
of additional first and refunding mortgage bonds and $2.9 billion of preferred
stock at current interest and dividend rates.

California law prohibits SCE from incurring or guaranteeing debt for its
affiliates that are not rate-regulated. Additionally, the CPUC regulates SCE's
capital structure, limiting the dividends it may pay Edison International. At
September 30, 1999, SCE had the capacity to pay approximately $586 million in
additional dividends and continue to maintain its authorized capital structure.

In December 1997, SCE Funding LLC, a special purpose entity, of which SCE is the
sole member, issued approximately $2.5 billion of rate reduction notes to
Bankers Trust Company of California, as certificate trustee for the California
Infrastructure and Economic Development Bank Special Purpose Trust SCE-1
(Trust), which is a special purpose entity established by the State of
California. The terms of the rate reduction notes generally mirror the terms of
the pass-through certificates issued by the Trust, which are known as rate
reduction certificates. 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 pursuant to
the restructuring legislation and a financing order of the CPUC and consists
generally of the right to be paid a specified amount from a non-bypassable rate
charged to residential and small commercial customers. Despite the legal sale of
the transition property by SCE to SCE Funding LLC, the amounts reflected as

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assets on SCE's balance sheet have not been reduced by the amount of the
transition property sold to SCE Funding LLC, and the liabilities of SCE Funding
LLC for the rate reduction notes are for accounting purposes reflected as
long-term liabilities on the consolidated balance sheet of SCE. SCE used the
proceeds from the sale of the transition property to retire debt and equity
securities.

The remaining series of outstanding rate reduction notes have scheduled
maturities beginning in 2000 and ending in 2007, with interest rates ranging
from 6.14% to 6.42%. The rate reduction notes are secured solely by the
transition property and certain other assets of SCE Funding LLC, and there is no
recourse to SCE or Edison International.

Although SCE Funding LLC is consolidated with SCE in the financial statements,
as required by generally accepted accounting principles, 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.

On October 25, 1999, SCE issued $175 million of floating rate notes, due October
2000.

Cash Flows from Investing Activities

Cash flows from investing activities are affected by additions to property and
plant, proceeds from the sale of generating plants (see the discussion in
Regulatory Environment below) and funding of nuclear decommissioning trusts.
Decommissioning costs are accrued and recovered in rates over the term of each
nuclear generating facility's operating license. SCE estimates that it will
spend approximately $8.6 billion through 2060 to decommission its nuclear
facilities. This estimate is based on SCE's current-dollar decommissioning costs
($1.9 billion), escalated at rates ranging from 0.3% to 10.0% (depending on the
cost element) annually. These costs are expected to be funded from independent
decommissioning trusts which receive SCE contributions of approximately $25
million per year.

Market Risk Exposures

SCE's primary market risk exposures arise from fluctuations in energy prices and
interest rates. SCE's risk management policy allows the use of derivative
financial instruments to manage its financial exposures, but prohibits the use
of these instruments for speculative or trading purposes.

As a result of the rate freeze established in the restructuring legislation,
SCE's transition costs are recovered as the residual component of rates once the
costs for distribution, transmission, public purpose programs, nuclear
decommissioning and the cost of supplying power to its customers through the PX
and ISO have already been recovered. Accordingly, more revenue will be available
to cover transition costs when market prices in the PX and ISO are low than when
PX and ISO prices are high. The PX and ISO market prices to date have generally
been reasonable, although some irregular price spikes have occurred. The ISO has
responded to price spikes in the market for reliability services (referred to as
ancillary services) by imposing a price cap on the market for such services
until certain actions have been completed to improve the functioning of those
markets. Similarly, the ISO currently maintains a cap on its market for
imbalance energy until adequate measures to improve the efficient operation of
the market have been implemented. The caps in these markets mitigate the risk of
costly price spikes that would reduce the revenue available to SCE to pay
transition costs. The price cap instituted by the ISO in the summer of 1998 was
$250/MWh. In October 1999, that cap was raised to $750/MWh and will remain at
that level through the summer of 2000, unless certain identified market
improvements do not occur. Under such circumstances, the price cap will be
reduced to $500/MWh. SCE has entered into hedges against high natural gas
prices, since increases in natural gas prices tend to raise the price of
electricity.

In July 1999, SCE began participating in forward purchases through a PX block
forward market. In the PX block forward market, SCE can purchase monthly blocks
of energy for six days a week (excluding Sundays and holidays) for 16 hours a
day. These purchases can be made up to 12 months in advance of the delivery
date. The CPUC has currently limited SCE's use of the PX block forward market to
a maximum of approximately 2,400 MW in any month. SCE requested permission from
the CPUC to begin a pilot demand responsiveness program that would allow
customers to be paid to curtail their load during times of very high prices.
This request was denied for 1999, but SCE will continue to work with the CPUC
and others to implement some form of demand responsiveness programs prior to the
summer of 2000.

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A 10% increase in market interest rates would result in a $7 million increase in
the fair value of SCE's interest rate hedge agreements. A 10% decrease in market
interest rates would result in a $7 million decline in the fair market value of
interest rate hedge agreements. A 10% increase in natural gas prices would
result in a $21 million increase in the fair market value of gas call options. A
10% decrease in natural gas prices would result in a $13 million decline in the
fair market value of gas call options. A 10% change in market rates is expected
to have an immaterial effect on SCE's other financial instruments.

Projected Capital Requirements

SCE's projected construction expenditures for the next five years are: 1999--
$975 million; 2000-- $940 million; 2001-- $891 million; 2002-- $860 million; and
2003-- $856 million.

Long-term debt maturities and sinking fund requirements for the five
twelve-month periods following September 30, 1999, are: 2000 -- $568 million;
2001 -- $647 million; 2002 -- $247 million; 2003 -- $572 million; and 2004 --
$372 million.

Preferred stock redemption requirements for the five twelve-month periods
following September 30, 1999, are: 2000 and 2001 -- zero; 2002 -- $105 million;
2003 -- $9 million; and 2004 -- $9 million.

Regulatory Environment

SCE currently operates in a highly regulated environment in which it has an
obligation to deliver electric service to customers in return for an exclusive
franchise within its service territory. This regulatory environment is changing
as a result of a 1995 CPUC decision on restructuring and state legislation
enacted in 1996. The Statute substantially adopted the CPUC's restructuring
decision by addressing stranded-cost recovery for utilities and providing a
certain cost-recovery time period for the transition costs associated with
generation-related assets. The Statute also included provisions to finance a
portion of the stranded costs that residential and small commercial customers
would have paid between 1998 and 2001, which allowed SCE to reduce rates by at
least 10% to these customers, effective January 1, 1998. The Statute mandated
other rates to remain frozen at June 1996 levels (system average of 10.1(cent)
per kilowatt-hour), including those for large commercial and industrial
customers, and included provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the rate
freeze, SCE expects to be able to recover its revenue requirement during the
1998--2001 transition period. In addition, the Statute mandated the
implementation of the CTC (see the detailed discussion below) that provides
utilities the opportunity to recover costs made uneconomic by electric utility
restructuring.

Revenue and Cost-Recovery Mechanisms

Revenue is determined by various mechanisms depending on the utility operation.
Revenue related to distribution operations is being determined through a
performance-based rate-making mechanism (PBR) and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return. The distribution PBR
will extend through December 2001. Key elements of the distribution PBR include:
distribution rates indexed for inflation based on the Consumer Price Index less
a productivity factor; adjustments for cost changes that are not within SCE's
control; a cost-of-capital trigger mechanism based on changes in a bond index;
standards for customer satisfaction; service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders will
share gains and losses from distribution operations. Transmission revenue is
being determined through FERC-authorized rates that are subject to refund.

SCE's transition costs are being recovered through a non-bypassable CTC. This
charge applies to all customers who were using or began using utility services
on or after the CPUC's December 1995 restructuring decision date. SCE has
estimated its transition costs to be approximately $10.6 billion (1998 net
present value) from 1998 through 2030. This estimate was based on incurred
costs, forecasts of future costs and assumed market prices. However, changes in
the assumed market prices could materially affect these estimates. Transition
costs related to power-purchase contracts are being recovered through the terms
of their contracts while most of the remaining transition costs will be
recovered through 2001. The potential transition costs are comprised of $6.4
billion from SCE's qualifying facilities contracts, which are the direct result

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of prior legislative and regulatory mandates, and $4.2 billion from costs
pertaining to certain generating assets (including the 1998 sale of SCE's
generating plants) and regulatory commitments consisting of costs incurred
(whose recovery has been deferred by the CPUC) to provide service to customers.
Such commitments include the recovery of income tax benefits previously flowed
through to customers, postretirement benefit transition costs, accelerated
recovery of San Onofre Units 2 and 3 and the Palo Verde units, and certain other
costs. During 1998, SCE sold all of its gas- and oil-fueled generation plants
for $1.2 billion, over $500 million more than the combined book value. Net
proceeds of the sales were used to reduce stranded costs, which otherwise were
expected to be collected through the CTC mechanism. If events occur during the
restructuring process that result in all or a portion of the transition costs
being improbable of recovery, SCE could have write-offs associated with these
costs if they are not recovered through another regulatory mechanism.

Revenue from generation-related operations is being determined through the
competitive market and the CTC mechanism, which now includes the nuclear
rate-making agreements. The portion of revenue related to fossil and
hydroelectric generation operations that is made uneconomic by electric industry
restructuring is recovered through the CTC mechanism. The portion that is
economic is recovered through the market. SCE's costs associated with its
hydroelectric plants are being recovered through a performance-based mechanism.
The mechanism sets the hydroelectric revenue requirement and establishes a
formula for extending it through the duration of the electric industry
restructuring transition period, or until market valuation of the hydroelectric
facilities, whichever occurs first. The mechanism provides that power sales
revenue from hydroelectric facilities in excess of the hydroelectric revenue
requirement be credited against the costs to transition to a competitive market.
In 1999, fossil and hydroelectric generation assets have the opportunity to earn
a 7.22% return.

SCE is recovering its investment in its nuclear facilities on an accelerated
basis in exchange for a lower authorized rate of return. SCE's nuclear assets
are earning an annual rate of return of 7.35%. In addition, the San Onofre plan
authorizes a fixed rate of approximately 4(cent) per kilowatt-hour generated for
operating costs including incremental capital costs, and nuclear fuel and
nuclear fuel financing costs. The San Onofre plan commenced in April 1996, and
ends in December 2001 for the accelerated recovery portion and in December 2003
for the incentive-pricing portion. Palo Verde's operating costs, including
incremental capital costs, and nuclear fuel and nuclear fuel financing costs,
are subject to balancing account treatment. The Palo Verde plan commenced in
January 1997 and ends in December 2001. Beginning January 1, 1998, both the San
Onofre and Palo Verde rate-making plans became part of the CTC mechanism.

The changes in distribution, transmission and generation revenue from the
regulatory mechanisms discussed above, excluding the effects of other rate
actions, are expected to have an approximately $20 million negative impact on
1999 earnings.

In March 1997, SCE filed its first FERC transmission rate case. In March 1999, a
proposed FERC decision was issued which recommended a reduced rate of return on
equity of 9.68% (compared to SCE's current CPUC rate for distribution of 11.6%)
and a reduced return on transmission assets of 8.41% (compared to the current
rate of 9.43% being earned on transmission assets). SCE filed comments opposing
the proposed decision in May 1999. In response to a recent FERC ruling, on
November 1, 1999, SCE filed additional evidence regarding return on equity. A
final FERC decision is expected in early 2000. SCE does not expect the final
decision to have a material effect on its results of operations or financial
position.

Restructuring Implementation Costs

The ISO assumed operational control of the transmission system after the ISO and
PX had begun accepting bids and schedules for electricity purchases on March 31,
1998. The restructuring implementation costs related to the start-up and
development of the PX, which are paid by the utilities, were to be recovered
from all retail customers over the four-year transition period. SCE's share of
the charge is $45 million, plus interest and fees. SCE's share of the ISO's
start-up and development costs (approximately $16 million per year) will be paid
over a 10-year period. In May 1998, SCE filed an application with the CPUC to
identify the categories of such costs (including costs related to the
implementation of direct access) and to establish the reasonableness of those
costs incurred in 1997.

On September 16, 1999, the CPUC approved the settlement agreement between SCE,
the CPUC's Office of Ratepayer Advocates and several other parties allowing SCE

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to recover substantially all (approximately $300 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would cease to recover these transition costs under
restructuring legislation.

Accounting for Generation-Related Assets

If the CPUC's electric industry restructuring plan continues as described above,
SCE will be allowed to recover its transition costs through non-bypassable
charges to its distribution customers (although its investment in certain
generation assets would be subject to a lower authorized rate of return). In
1997, SCE discontinued application of accounting principles for rate-regulated
enterprises for its investment in generation facilities based on new accounting
guidance. The new guidance did not require SCE to write off any of its
generation-related assets, including related regulatory assets. SCE has retained
these assets on its balance sheet because the Statute and restructuring plan
referred to above make probable their recovery through a non-bypassable CTC to
distribution customers. The regulatory assets relate primarily to the recovery
of accelerated income tax benefits previously flowed through to customers,
purchased power contract termination payments and unamortized losses on
reacquired debt. The new accounting guidance also permits the recording of new
generation-related regulatory assets during the transition period that are
probable of recovery through the CTC mechanism.

During the second quarter of 1998, additional guidance was developed related to
the application of asset impairment standards to these assets. Using this
guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6
billion (as of June 30, 1998) and recording a regulatory asset on its balance
sheet for the same amount. For this impairment assessment, the fair value of the
investment was calculated by discounting future net cash flows. This
reclassification had no effect on SCE's results of operations.

If during the transition period events were to occur that made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.6
billion, after tax, at September 30, 1999) as a one-time, non-cash charge
against earnings. At this time, SCE cannot predict what other revisions will
ultimately be made during the restructuring process in subsequent proceedings or
the effect, after the transition period, that competition will have on its
results of operations or financial position.

Environmental Protection

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.

As further discussed in Note 10 to the Consolidated Financial Statements, SCE
records its environmental 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. Unless
there is a probable amount, SCE records the lower end of this likely range of
costs.

SCE's recorded estimated minimum liability to remediate its 49 identified sites
is $165 million. One of SCE's sites, a former pole-treating facility, is
considered a federal Superfund site and represents 40% of its recorded
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. SCE believes that, due to these uncertainties, it is reasonably
possible that cleanup costs could exceed its recorded liability by up to $284
million. The upper limit of this range of costs was estimated using assumptions
least favorable to SCE among a range of reasonably possible outcomes. SCE has
sold all of its gas- and oil-fueled power plants and has retained some liability
associated with the divested properties.

The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $85 million of its recorded liability, through an incentive
mechanism. Under this mechanism, SCE will recover 90% of cleanup costs through

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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. Costs
incurred at SCE's remaining sites are expected to be recovered through customer
rates. SCE has recorded a regulatory asset of $130 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
$5 million to $15 million. Recorded costs for the twelve-month period ended
September 30, 1999, were $15 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 and,
based upon the CPUC's regulatory treatment of environmental-cleanup 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.

The 1990 Federal 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 expects
to have excess allowances under Phase II of the Clean Air Act (2000 and later).
The act also calls for a study to determine if additional regulations are needed
to reduce regional haze in the southwestern U.S. In addition, another study was
undertaken to determine the specific impact of air contaminant emissions from
the Mohave Generating Station on visibility in Grand Canyon National Park. The
final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave station tracer concentrations and visibility
impairment. The absence of any obvious relationship cannot rule out Mohave
station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. In June
1999, the Environmental Protection Agency issued an advanced notice of proposed
rulemaking regarding assessment of visibility impairment at the Grand Canyon.
SCE intends to file comments on the proposed rulemaking. At this time, SCE is
unable to predict the potential effect of these studies on sulfur dioxide
regulations for Mohave, or what effect the final reports may have on SCE's
results of operations or financial position.

SCE's projected environmental capital expenditures are $900 million for the
1999--2003 period, mainly for undergrounding certain transmission and
distribution lines.

San Onofre Steam Generator Tubes

The San Onofre Units 2 and 3 steam generators have performed relatively well
through the first 15 years of operation, with low rates of ongoing steam
generator tube degradation. However, during the Unit 2 scheduled refueling and
inspection outage in 1997, an increased rate of tube degradation was identified,
which resulted in the removal of more tubes from service than had been expected.
The steam generator design allows for the removal of up to 10% of the tubes
before the rated capacity of the unit must be reduced. As a result of the
increased degradation, a mid-cycle inspection outage was conducted in early 1998
for Unit 2. Continued degradation was found during this inspection. A favorable
or decreasing trend in degradation was observed during inspection in the
scheduled refueling outage in January 1999. Analysis of results of the January
1999 inspection determined that a mid-cycle inspection outage in early 2000 will
be unnecessary. With the results from the January 1999 outage, 7.5% of the tubes
have now been removed from service.

During Unit 3's refueling outage, which was completed in May 1999, a complete
inspection of the steam generator tubes was performed. Results obtained were
within expectations. To date, 5.4% of Unit 3's tubes have been removed from

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service. During the refueling, follow-up inspections of the tube support
thinning problem first detected in 1997 were performed. These inspections
confirmed that corrective actions taken in 1997 were effective and the thinning
has been stabilized.

New Accounting Rules

In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which as amended will be effective
January 1, 2001, requires all derivatives to be recognized on the balance sheet
at fair value. Gains or losses from changes in fair value would be recognized in
earnings in the period of change unless the derivative is designated as a
hedging instrument. Gains or losses from hedges of a forecasted transaction or
foreign currency exposure would be reflected in other comprehensive income.
Gains or losses from hedges of a recognized asset or liability or a firm
commitment would be reflected in earnings for the ineffective portion of the
hedge. SCE anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect
earnings.

Year 2000 Issue

Many of SCE's existing computer systems were originally programmed to represent
any date by using six digits (e.g., 12/31/99) rather than eight digits (e.g.,
12/31/1999). Accordingly, such programs, if not appropriately addressed, could
fail or create erroneous results when attempting to process information
containing dates after December 31, 1999. This situation has been referred to
generally as the Year 2000 Issue.

SCE has a comprehensive program in place to address potential Year 2000 impacts.
Edison International provides overall coordination of this effort. SCE divides
Year 2000 activities into five phases: inventory, impact assessment,
remediation, testing and implementation. SCE met its goal to have 100% of its
critical systems Year 2000-ready by July 1, 1999. A critical system is defined
as those applications and systems, including embedded processor technology,
which if not appropriately remediated, may have a significant impact on
customers, the health and safety of the public and/or personnel, the revenue
stream, or regulatory compliance. A system, application or physical asset is
deemed to be Year 2000-ready if it is determined by SCE to be suitable for
continued use through 2028 (or through the last year of the anticipated life of
the asset, whichever occurs first), even though it may not be fully Year
2000-compliant. A system, application, or physical asset is deemed to be Year
2000-compliant if it accurately processes date/time data, such as calculating,
comparing, and sequencing from, into, and between the 20th and 21st centuries,
1999 and 2000, and leap-year calculations.

SCE has structured the scope of the program to focus on three principal
categories: mainframe computing, distributed computing and physical assets (also
known as embedded processors). The mainframe and distributed computing assets
consist of computer application systems (software). Physical assets include
information technology infrastructure (hardware, operating system software) and
embedded processor technology in generation, transmission, distribution, and
facilities components.

Included among the critical applications that are Year 2000-ready are the
financial, customer information and billing, material management, and human
resource systems. Work has also been completed on critical physical assets in
the areas of information technology infrastructure, and embedded processor
technology in generation, transmission, distribution and facilities assets. SCE
filed a statement with the Nuclear Regulatory Commission (NRC) on June 28, 1999,
stating that its Year 2000 readiness program has been completed for those
systems within the scope of its operating license, NRC regulations and other
critical systems required for continued operation of San Onofre Units 2 and 3.

Ongoing efforts continue to focus on non-critical systems and on guarding
against reintroduction of components that are not Year 2000-ready into Year
2000-ready systems. SCE has adopted a technology production freeze beginning
November 15, 1999, and extending through January 15, 2000. During this period,
any changes to SCE's production environment will be tightly controlled. The
freeze covers changes to physical assets with embedded processors and
information technology infrastructure, and includes moves, adds and changes to
communications equipment, computers and software applications.

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<PAGE>

The other essential component of the Year 2000 program is to identify and assess
vendor products and business partners for Year 2000 readiness, as these external
parties may have the potential to impact SCE's Year 2000 readiness. SCE has
implemented a process to identify and contact vendors and business partners to
determine their Year 2000 status. Evaluation of responses and other follow-up
activities are substantially complete. SCE's general policy requires that all
newly purchased products and services be Year 2000-ready or otherwise designed
to allow SCE to determine whether such products and services present Year 2000
issues. SCE is also working to address Year 2000 issues related to all ISO and
PX interfaces, as well as joint ownership facilities. SCE exchanges Year
2000-readiness information (including, but not limited to, test results and
related data) with its affiliates and other external parties as part of its Year
2000-readiness efforts.

SCE's current estimate of its Year 2000 costs, including the costs of new
hardware and software application modification, work on contingency planning
efforts discussed below and continuing work on non-critical assets, is $69
million, about 38% of which is expected to be capital costs. SCE's Year 2000
costs expended through September 30, 1999, were $60 million. SCE expects current
rate levels for providing electric service to be sufficient to provide funding
for utility-related modifications.

Although SCE expects that its critical facilities, systems, information
technology infrastructure and physical assets will remain fully Year 2000-ready,
there can be no assurance that the facilities, systems, infrastructure and
physical assets of other companies on which the systems and operations of SCE
rely will be converted on a timely basis and will remain ready for 2000. SCE
believes that prudent business practices call for development of contingency
plans. These plans include provisions for monitoring, validating and managing
the continued performance of SCE Year 2000-sensitive systems and assets during
critical transition periods, development of work-arounds and expedited
fix-on-failure strategies. Where appropriate, contingency plans include
scheduling of key personnel, identification of alternate suppliers and securing
adequate on-site supplies of critical materials. SCE plans to have more than 500
additional personnel, over and above normal holiday staffing, at key facilities
for the Year 2000 rollover.

SCE has implemented a Year 2000 contingency planning process as a part of its
Year 2000 remediation program. Each SCE department is required to assess the
Year 2000 risks, including both internal and external risks and dependencies,
associated with critical systems and assets, that are date aware or date
sensitive. This includes assessment of Year 2000 risks for all indispensable or
critical business processes and key facilities.

Where appropriate, the plans utilize or supplement the existing Corporate
Emergency Response and Recovery Plan, and Information Technology disaster
recovery plan, for identified Year 2000-related events. SCE's Year 2000
contingency plans are designed to coordinate and interface with the California
ISO and the PX and to satisfy Western System Coordinating Council (WSCC) and
North American Electric Reliability Council (NERC) recommendations and Nuclear
Energy Institute guidelines. SCE will continue to work with these industry
groups, as well as the Electric Power Research Institute and other major
interconnecting utilities, regarding its contingency plans. Initial development
of these plans was completed in June 1999. SCE filed a report on its contingency
plans, as required, with the CPUC on July 1, 1999. Contingency plans have been
used in conducting SCE and electric industry drills and will continue to be used
to conduct internal exercises during the fourth quarter of 1999. SCE expects
that its contingency plans will continue to be revised and enhanced as 2000
approaches.

Although SCE's Year 2000 contingency plans use risk-based methods, the plans are
being evaluated against the NERC/WSCC suggested "More Probable" and "Credible
Worst Case Scenarios." SCE believes that the most reasonably likely worst case
Year 2000 scenario would be small, localized interruptions of service which
would be restored in a timeframe that is within normal service levels.

SCE does not expect the Year 2000 Issue to have a material adverse effect on its
results of operation or financial position; however, if not effectively
remediated, and despite the adoption of contingency plans, negative effects from
Year 2000 issues, including those related to internal systems, vendors, business
partners, the ISO, the PX or customers, could cause results to differ.

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Forward-looking Information

In the preceding Management's Discussion and Analysis of Results of Operations
and Financial Condition and elsewhere in this quarterly report, the words
estimates, expects, anticipates, believes, and other similar expressions are
intended to identify forward-looking information that involves risks and
uncertainties. Actual results or outcomes could differ materially as a result of
such important factors as further actions by state and federal regulatory bodies
setting rates and implementing the restructuring of the electric utility
industry; the effects of new laws and regulations relating to restructuring and
other matters; the effects of increased competition in the electric utility
business and other energy-related businesses, including direct customer access
to retail energy suppliers and the unbundling of revenue cycle services such as
metering and billing; changes in prices of electricity and fuel costs; the terms
of divestiture of utility generation assets; changes in market interest rates;
new or increased environmental liabilities; the ability to create and expand new
businesses such as telecommunications; the effects of the Year 2000 Issue;
municipalization and other unforeseen events.

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<PAGE>

PART II OTHER INFORMATION

Item 1. Legal Proceedings

                        Geothermal Generators' Litigation

On June 9, 1997, SCE filed a complaint in Los Angeles County Superior Court
against an independent power producer of geothermal generation and six of its
affiliated entities (Coso parties). SCE alleges that in order to avoid power
production plant shutdowns caused by excessive noncondensable gas in the
geothermal field brine, the Coso parties routinely vented highly toxic hydrogen
sulfide gas from unmonitored release points beginning in 1990 and continuing
through at least 1994, in violation of applicable federal, state, and local
environmental law. According to SCE, these violations constituted material
breaches by the Coso parties of their obligations under their contracts with SCE
and applicable law. The complaint sought termination of the contracts and
damages for excess power purchase payments made to the Coso parties. The Coso
parties' motion to transfer venue to Inyo County Superior Court was granted on
August 31, 1997. On June 1, 1998, the Court struck SCE's request for termination
of the contracts, leaving SCE with its claim for damages and other relief. On
February 16, 1999, the Court denied the Coso parties' motion for judgment on the
pleadings directed to SCE's first amended complaint.

The Coso parties have also asserted various claims against SCE, The Mission
Group, and Mission Power Engineering Company (Mission parties) in a cross
complaint filed in the action commenced by SCE as well as in a separate action
filed against SCE by three of the Coso parties in Inyo County Superior Court. In
November 1997, the Court struck all but two causes of action asserted in the
separate action on the grounds that they should have been raised as part of the
Coso parties' cross-complaint, and ordered the remaining two causes of action
consolidated for all purposes with the action filed by SCE.

The Coso parties subsequently filed second and third amended cross-complaints.
The third amended cross-complaint names SCE, the Mission parties and Edison
International. As against SCE, the third amended cross-complaint purports to
state causes of action for declaratory relief, breach of the covenant of good
faith and fair dealing; inducing breach of agreements between the Coso parties
and their former employees; breach of an earlier settlement agreement between
the Mission parties and the Coso parties; slander and disparagement, injunctive
relief and restitution for unfair business practices; anticipatory breach of the
contracts; and violations of Public Utilities Code ss.ss. 453, 702 and 2106. As
against the Mission parties, the third amended cross-complaint seeks damages for
breach of warranty of authority with respect to the settlement agreement, and
for equitable indemnity. The Coso parties voluntarily dismissed Edison
International from the third amended cross-complaint on December 4, 1998. As
against SCE, the third amended cross-complaint seeks restitution, compensatory
damages in excess of $115 million, punitive damages in an amount not less than
$400 million, interest, attorney's fees, declaratory relief, and injunctive
relief.

On September 21, 1998, SCE filed an answer to the third amended cross-complaint
generally denying the allegations contained therein and asserting affirmative
defenses. In addition, SCE filed a cross-complaint for reformation of the
contracts alleging that if they are not susceptible to SCE's interpretation,
they should be reformed to reflect the parties' true intention. SCE subsequently
voluntarily filed a first amended cross-complaint. On February 26, 1999, after
the Court had sustained a demurrer to its first amended cross-complaint, SCE
filed a second amended cross-complaint for reformation.

Following various pre-trial motions filed by the Mission parties and Edison
International, the Coso parties purported to file a fourth amended
cross-complaint on December 23, 1998, against the Mission Parties only. The
Mission parties' demurrer to and motion to strike directed to the fourth amended
cross-complaint was heard and taken under submission on March 10, 1999.

On December 15, 1998, the Court granted the Coso parties leave to file a second
amended complaint in the separately filed (now consolidated) action. The second
amended complaint, which names SCE and Edison International, alleges that SCE
engaged in anti-competitive conduct, false advertising, and conduct proscribed
by Public Utilities Code ss. 2106, and seeks injunctive relief, restitution, and
punitive damages. On January 20, 1999, SCE filed three motions to strike several

                                       38
<PAGE>

portions of the second amended complaint on the grounds, among others, that the
CPUC or FERC have either exclusive or primary jurisdiction over the matters
asserted therein, and that SCE's alleged conduct was in furtherance of
constitutionally protected rights of free speech and petition and therefore not
actionable. These matters were heard on February 22, 1999, and taken under
submission at that time. Edison International also filed a demurrer and motion
to strike the second amended complaint. The Court denied the motion to strike
and overruled the demurrer on March 22, 1999.

On April 1, 1999, the Court signed a stipulation and order submitted by the
parties staying all proceedings to allow the parties to engage in settlement
discussions. The Court and the parties have continued the stay in effect through
and including November 30, 1999, in order to permit the continuation of
settlement discussions. As a result of the stay, all discovery has been
suspended. Furthermore, during the period of the stay, the Court will not issue
orders or rulings on matters taken under submission.

The Court has set a trial date of March 1, 2000, but, in light of the stay
currently in effect, has reserved jurisdiction to advance or to continue the
trial date. The materiality of net final judgments against SCE in these actions
would be largely dependent on the extent to which any damages or additional
payments which might result therefrom are recoverable through rates.

                      San Onofre Personal Injury Litigation

SCE is actively involved in three lawsuits claiming personal injuries allegedly
resulting from exposure to radiation at San Onofre. On August 31, 1995, the wife
and daughter of a former San Onofre security supervisor sued SCE and SDG&E in
the U.S. District Court for the Southern District of California. Plaintiffs also
named Combustion Engineering and the Institute of Nuclear Power Operations as
defendants. All trial court proceedings were stayed pending ruling of the Ninth
Circuit Court of Appeals, on an appeal of a lower court's judgment in favor of
SCE in two earlier cases raising similar allegations. On May 28, 1998, the Court
of Appeal affirmed these judgments. Pursuant to an agreement of the parties as
described below, all proceedings in this matter have been stayed.

On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District
Court for the Southern District of California. Plaintiffs also named Combustion
Engineering. The trial in this case resulted in a jury verdict for both
defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed
an appeal of the trial court's judgment to the Ninth Circuit Court of Appeals.
Briefing on the appeal was completed in January 1999 and the parties are
awaiting a date for oral argument to be set by the Court. A decision is not
expected until at least early 2000.

On November 28, 1995, a former contract worker at San Onofre, her husband, and
her son, sued SCE in the U.S. District Court for the Southern District of
California. Plaintiffs also named Combustion Engineering. On August 12, 1996,
the Court dismissed the claims of the former worker and her husband with
prejudice, leaving only the son as plaintiff. Pursuant to an agreement of the
parties as described below, all proceedings in this matter have been stayed.

In March of 1999, SCE reached an agreement with the plaintiffs in both of the
above cases currently pending at the U.S. District Court level to stay all
proceedings including trial, pending the results of the case currently before
the Ninth Circuit Court of Appeals. The parties agreed that if the plaintiffs in
that case do not receive a favorable determination on appeal, then the two cases
at the District Court level will be dismissed. If, however, those plaintiffs
receive a favorable determination on their appeal, then the two District Court
cases will be set for trial. On March 23, 1999, the District Court approved the
parties' stay agreement in both cases.

SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although SCE is no longer
actively involved in these actions, the impact on SCE, if any, from further
proceedings in those cases against the remaining defendants cannot be determined
at this time.

                                       39
<PAGE>

               Mohave Generating Station Environmental Litigation

On February 19, 1998, the Sierra Club and the Grand Canyon Trust filed suit in
the U.S. District Court of Nevada against SCE and the other three co-owners of
Mohave Generating Station (Mohave). The lawsuit alleges that Mohave has been
violating various provisions of the Clean Air Act (CAA), the Nevada state
implementation plan, certain Environmental Protection Agency orders, and
applicable pollution permits relating to opacity and sulfur dioxide emission
limits over the last five years. The plaintiffs seek declaratory and injunctive
relief as well as civil penalties. Under the CAA, the maximum civil penalty
obtainable is $25,000 per day per violation. SCE and the co-owners obtained an
extension to respond to the complaint pending the court's ruling on a motion to
dismiss filed by the defendants. The plaintiffs filed an opposition to the
defendants' motion to dismiss as well as a separate motion for partial summary
judgment on May 8, 1998.

On June 4, 1998, the plaintiffs served SCE and the other Mohave co-owners with a
60-day supplemental notice of intent to sue. This supplemental notice identified
additional causes of action as well as an additional plaintiff (National Parks
and Conservation Association) to be added to the proceedings. On November 12,
1998, the court bifurcated the liability and damage phases of the case and
granted plaintiffs' motion to amend the complaint to add the National Parks and
Conservation Association as a plaintiff.

On December 8, 1998, defendants filed a supplemental memorandum in support of
defendants' opposition to plaintiffs' motion for partial summary judgment. On
February 4, 1999, plaintiffs filed their first amended complaint to add the
National Parks and Conservation Association as a plaintiff in the action. On
March 10, 1999, defendants filed a motion for partial summary judgment. On March
11, 1999, plaintiffs filed a motion for partial summary judgment to establish
emission limit violations as alleged in certain of the causes of action in their
first amended complaint.

On March 8, 1999, the parties filed a stipulated request for a 60-day stay which
was granted and ordered, by the Court on March 9, 1999. A subsequent stay was
granted, which was to expire on July 6, 1999 before being extended to July 20,
1999. No further stay has been sought or is in effect at this time. On July 6,
1999, each party filed an opposition to the other parties' motion for summary
judgment. On August 2, 1999, defendants filed a reply to plaintiffs' opposition.
On August 5, 1999, plaintiffs filed a reply to defendant's opposition. On
October 6, 1999, the parties filed a consent decree with the Federal District
Court in Las Vegas, requesting the judge to approve the decree, and
simultaneously dismiss the lawsuit. The decree provides that certain
environmental control hardware (lime spray dryers, fabric filter baghouses and
low NOx burners) should be installed on the facility by December 31, 2005, in
order to continue to operate the plant as a coal-fired facility after that date.

                            Navajo Nation Litigation

On June 18, 1999, SCE, was served with a complaint filed by the Navajo Nation in
the United States District Court for the District of Columbia against Peabody
Holding Company and certain of its affiliates (Peabody), Salt River Project
Agricultural Improvement and Power District, and SCE. The complaint asserts
claims against the defendants for, among other things, violations of the federal
RICO statute, interference with fiduciary duties and contractual relations,
fraudulent misrepresentation by nondisclosure, and various contract-related
claims. Peabody supplies coal from mines on Navajo Nation lands to Mohave. The
complaint claims that the defendants' actions prevented the Navajo Nation from
obtaining the full value in royalty rates for the coal. 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, which will be
argued on February 11, 2000. In the meantime, the Court has stayed discovery.

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Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE
effective June 1, 1993 (File No. 1-2313, Form 10-K for the year ended December
31, 1993)*

3.2 Certificate of Correction of Restated Articles of Incorporation of SCE dated
June 23, 1997 (File No. 1-2313, Form 10-Q for the quarter ended September 30,
1997)*

3.3 Amended Bylaws of Southern California Edison Company as adopted by the Board
of Directors on April 15, 1999 (File No. 1-2313, Form 10-Q for the quarter ended
June 30, 1999)*

10.1 Executive Retirement Plan Restated Effective April 1, 1999

10.2 Executive Supplemental Benefit Program as Amended January 30, 1990

23. Consent of Independent Public Accountants

27. Financial Data Schedule

(b) Reports on Form 8-K:

None

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

* Incorporated by reference pursuant to Rule 12b-32.

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                                   SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant  has duly  caused  this  report  to be  signed  on its  behalf by the
undersigned thereunto duly authorized.

                          SOUTHERN CALIFORNIA EDISON COMPANY
                                            (Registrant)

                          By       THOMAS M. NOONAN
                                   ------------------------------
                                   THOMAS M. NOONAN
                                   Vice President and Controller

                          By       KENNETH S. STEWART
                                   ------------------------------
                                   KENNETH S. STEWART
                                   Assistant General Counsel and
                                   Assistant Secretary

November 10, 1999